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

Robert Alan Brackett - Sanford C. Bernstein & Co. LLC Arun Jayaram - JPMorgan Securities LLC David R. Tameron - Wells Fargo Securities LLC Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc. Brian Singer - Goldman Sachs & Co. Charles A. Meade - Johnson Rice & Company LLC Evan Calio - Morgan Stanley & Co.

LLC James Sullivan - Alembic Global Advisors LLC Michael Anthony Hall - Heikkinen Energy Advisors LLC Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc. Doug Leggate - Bank of America Merrill Lynch.

Welcome to the Apache Corporation's second quarter 2017 results earnings call. I would like to turn the call over to Gary Clark, Vice President, Investor Relations. Sir, the floor is yours..

Good afternoon, and thank you for joining us on Apache Corporation's second 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 second 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 noncontrolling interest in Egypt and Egypt tax barrels. Please note that all currency references in our prepared remarks are in U.S. dollars.

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..

review our approach to navigating the lower-for-longer oil price environment; discuss the strategic rationale and financial benefits of our pending exit from Canada; provide current operational highlights, including Alpine High; and conclude with our thoughts around balancing funding and spending in 2018.

Since the beginning of 2015, we have restructured our business to adapt and thrive in a lower-for-longer commodity price environment. The organization reacted swiftly to the downturn in oil prices. We stressed the importance of properly aligning cost structure with commodity prices as well as achieving and maintaining cash flow neutrality.

We completed a series of transactions that simplified our portfolio. We reduced operating costs, overhead, and capital commitments, and significantly improved the balance sheet. With regard to our asset base and strategy, we successfully expanded and enhanced our organic unconventional North American acreage footprint and technical capabilities.

We also focused our international capital spending to deliver strong and sustainable free cash flow from our core businesses in Egypt and the North Sea. These efforts were supported by significant improvements in our planning and capital allocation processes, which helped drive our strategy of returns-focused organic growth.

In early 2017, WTI oil prices were trading above $50 per barrel, with the out years of the NYMEX strip trending even higher. We had concerns about the fundamentals underpinning this oil price optimism and the corresponding cash flows from operations.

At the same time, we had just announced our discovery at Alpine High, a very attractive large-scale opportunity which would require significant near-term investment.

Given our strong financial position, a cost structure that was now properly aligned with commodity prices, and a deep inventory of fully burdened high rate-of-return projects, we believed it was appropriate and value creating to budget a moderate outspend for the near term.

Our general philosophy was that the upstream expenditures and dividends should be funded within cash flow while using a combination of non-core asset sales and the balance sheet to fund a viable midstream build-out at Alpine High.

Accordingly, on our fourth quarter earnings call in February, we announced a 2017 capital budget based on a $50 WTI oil price, which at the time was conservative relative to the prevailing strip.

We also announced that we had protected the 2017 capital program with put options at $50 WTI and $51 Brent for the majority of our oil production in the second half of the year.

This helped to ensure our ability to fund the Alpine High capital program, which was strategically important to our long-term returns-focused growth strategy through a potentially volatile commodity price environment.

Today, through the combination of expected cash flows from operations and proceeds from recent asset sales, our planned 2017 CapEx and dividends are funded. As a result, our $3.1 billion capital program remains unchanged. We expect to end 2017 with more cash and less debt, and we will have significantly higher production levels in the Permian Basin.

I'd now like to comment on our exit from Canada, which we anticipate will be finalized upon the closing of two transactions later this month. From a strategic perspective, the sale of Canada further streamlines our portfolio and increases our North American leverage to the Permian Basin, which can be seen in our financial and operational supplement.

While the Montney and Duvernay plays in Canada offer long-term growth potential, they are strategically disadvantaged relative to the other opportunities within our portfolio. Financially, Apache will realize several important benefits from the Canadian divestiture.

In addition to the roughly $700 million headline sales price, the present value of asset retirement obligations on our balance sheet will be reduced by approximately $800 million. Gross cash overhead costs plus other corporate program costs will be reduced by approximately $70 million annually.

Average cash margins per BOE, earnings per share, and free cash flow will be positively impacted, and return on capital employed at the corporate level will improve. I will conclude my remarks on Canada by noting that Apache is very grateful to the many employees who built this region over the years.

We believe the employees and the assets will be well served under the new owners, who are eager to make significant capital investments in the business. Turning now to results and highlights from the quarter, oil and gas capital investment was $738 million in the second quarter, two-thirds of which was in the Permian Basin.

Of this amount, Alpine High midstream expenditures were $128 million. Total first half 2017 capital investment of $1.4 billion is consistent with our planned full-year CapEx of $3.1 billion. As a reminder, this year we budgeted for an average well cost increase of 10% to 15% versus 2016 levels.

And while we have seen price increases of 30% to 40% for certain service lines, our increased pad drilling operations coupled with other efficiencies and cost initiatives have resulted in average well cost at/or below budgeted levels. Tim will discuss this more in his remarks.

As anticipated, our total daily production bottomed out in the second quarter, and we have shifted to a growth trajectory. We expect continued production volume increases at Alpine High and in the Midland Basin as well as our international regions during the second half of 2017.

Now, I'd like to discuss some of our specific regional highlights, starting with Alpine High. As noted previously, we achieved first production at Alpine High in early May and exceeded our June 30 target of 50 million cubic feet per day of processed gas.

Currently, our net sales gas exceeds 60 million cubic feet per day, and we anticipate this will increase to more than 100 million cubic feet per day by the end of September. Due to the timing of infrastructure build-out and gas takeaway, the majority of our Alpine High production thus far has come from our northernmost acreage.

The drilling in this area has primarily been lease-retention-focused, and these wells are generally deeper and, thus, have a lower liquids content. The liquids ratio should increase as we drill and connect more wells in other areas of the play, and as we commission additional processing facilities.

In the month of June, total Alpine High sales, net to Apache, averaged approximately 7,400 BOEs per day, of which approximately 10% was oil and natural gas liquids. As just mentioned, this liquids ratio should increase in the second half of the year. On the midstream side, we invested $270 million in the first half of 2017.

Managing midstream internally provides Apache with operational flexibility and cost control benefits as we delineate the upstream and move into early-stage development.

By retaining 100% ownership, we are investing in an asset that we believe will significantly increase in value as the upstream production and reserve potential are further demonstrated.

Currently, our operational midstream facilities consist of 35 miles of 30-inch trunkline for gas takeaway, more than 40 miles of smaller diameter gathering lines, two central processing sites and eight central tank batteries. In addition, we have several significant midstream infrastructure milestones coming up in the second half of the year.

In August, we will bring online our third central processing site followed by a fourth and fifth site in September, one of which will be located in the southern portion of the play.

Also in September, we will connect our 30-inch trunkline to a market pipeline in the southern portion of the play, which will be capable of moving gas south to Mexico or north to the Waha Hub. Around year-end, we plan to have our sixth central processing site operational.

In terms of new activity, we drilled four appraisal wells in the oil window of the Wolfcamp, Bone Springs parasequences at vertical depths ranging from 9,000 to 10,000 feet. We are excited about these wells, which have confirmed an over-pressured regime and 42-degree to 44-degree gravity oil.

One of the wells, an approximate 4,500-foot lateral drilled in the Wolfcamp formation recorded a 30-day average rate in excess of 1,000 barrels of oil equivalent per day. With an oil cut of 70%, this well has cumulative production of approximately 37,000 barrels of oil in 75 days.

A second well in the Wolfcamp is still cleaning up and producing around 400 barrels of oil per day. The third and fourth wells will be completed and begin flowing back shortly. We are pleased with the indications thus far from our oil bearing parasequence test at Alpine High.

Early results from mapping and testing these zones gives us confidence at minimum in hundreds of drilling locations, and there is still a considerable amount of acreage in numerous landing zones to be tested.

Optimization work is underway at Alpine High, and we are testing a number of different parameters across multiple formations to determine the best patterns, spacing, well-bore placement and completion designs. This process will be multifaceted and continuous. As we gather data and reach key conclusions, we will discuss them further with the market.

On the costs side, we have made excellent progress and remain comfortable with our previous estimated average drilling and completion cost of $4 million to $6 million per well, despite the rising service cost environment. Overall, Alpine High operations are on track to progress to development.

Trunkline and gathering system construction and takeaway connections are proceeding as expected, and our processing facilities are actively optimizing liquids recovery. From the wells connected and flowing thus far, we are seeing decline curves and pressure data consistent with our EUR projections.

In addition to the Wolfcamp and Bone Springs parasequences I just mentioned, we continue to be very confident in our more than 3,000 wet-gas well location count, which remains highly economic at current or even lower prices.

Turning now to the Midland Basin where our activity is primarily focused on multi-well pad drilling to the Wolfcamp and Spraberry formations. In April, we brought the nine well Schrock 34 pad online at the Azalea field in Glasscock County. This pad exhibited strong performance with 60-day cumulative production exceeding our expectations.

Average well costs were only $4.3 million, underscoring the significant efficiencies we are achieving in pad operations. In the second half of 2017, we have five additional multi-well pads scheduled to come online in the Midland Basin, which Tim will discuss in a moment.

Internationally, we continued to generate strong free cash flow during the second quarter. In Egypt, our exploration program included two high-rate exploration discoveries with material potential for more activity in the Matruh Basin.

As previously mentioned, we have received approval and expect to have signed agreements soon for two new concessions in Egypt. Combined, these blocks add approximately 1.6 million acres to Apache's footprint in the Western Desert, a 40% increase.

With the opportunity set provided by these new concessions and the modern vintage 3-D seismic we are accumulating across our acreage in the Western Desert, we are very excited about the long-term potential in Egypt.

Moving over to the North Sea; at Callater, we completed our facilities tieback ahead of schedule and proceeded with testing of the 18x discovery well in June. In July, we successfully tested a second well in an adjacent fault block.

Both wells were recently brought online at a combined facilities-constrained rate of approximately 19,000 BOEs per day net to Apache, of which approximately 70% was oil and liquids. I'd like to close with a review of our 2018 capital budget and the flexibility we have around this program.

Adjusted for the pending divestment of Canada, our planned capital budget for 2018 is $3.1 billion. This plan, which we announced in February, was based on $55 WTI oil and $3 NYMEX gas, and was designed to approximate cash flow neutrality, excluding Alpine High midstream investment.

Our 2018 budget is flexible and can be adjusted in response to macro conditions, as every $5 per barrel change in oil prices impacts our cash flow by roughly $350 million. If necessary, we have numerous options available next year to manage a lower oil price environment.

To begin with, we are maintaining the operational flexibility to reduce planned activity across most, if not all of our regions. Second, we believe costs in a sub-$55 oil price world would be lower than what we have estimated in our plan; and hence, the same overall activity set could be delivered for less than the $3.1 billion budget.

Third, we could continue with the small asset package divestitures. Fourth, we have multiple options with respect to our Alpine High midstream assets, possibly initiating a monetization process or seeking third-party funding. And lastly, we could choose to utilize a portion of our significant cash position.

What you can count on is that we will enter 2018 well prepared to manage a capital program commensurate with the prevailing price environment. We will do so with a keen focus on long-term returns, and we have no intention of stressing the balance sheet or diluting our shareholders. To wrap up, Apache is executing well on all fronts.

Production is now growing in the U.S., as our Permian teams deliver strong drilling results in the Delaware and Midland Basins. In Egypt and the North Sea, we are bringing on several key wells which will provide production momentum in the second half of 2017.

Across the company, we are successfully managing cost pressures and working diligently to manage LOE and G&A. In terms of our long-term growth and return expectations, we are making excellent progress incorporating or merging Alpine High outlook into our multiyear plan.

As that full field development plan evolves, we will look to communicate some of the key elements of the multiyear plan to the investment community. Apache's balance sheet remains in great shape and our expected cash flow from oil production is well protected in the back half of this year.

We look forward to entering 2018 in a strong financial position and continuing to create value with our differentiated, organic, unconventional exploration capabilities. I will now turn the call over to Tim to provide more operational details..

Good afternoon. My remarks today will cover operational activity and key wells in our focus areas, new technologies we are applying to improve our performance and service and supply cost trends. Our second quarter production results reflect the lingering impact of last year's reduced capital and development activity.

These effects, combined with the scheduled maintenance activities in Canada and the North Sea, contributed to a 3% production decrease on an adjusted basis from the preceding quarter. With those events behind us, we are shifting to a growth trajectory for the remainder of the year and beyond.

During the second quarter, we increased activity at a measured pace, averaging 35 operated rigs worldwide with 17 in the Permian, 1 in the Mid-Continent, 13 in Egypt and 4 in the North Sea. In North America, second quarter 2017 production averaged 244,000 barrels of oil equivalent per day, down 3% from the first quarter.

In the Permian Basin, production of 146,000 BOE per day was flat compared to the preceding period. I'll begin with an overview of Alpine High in the Delaware Basin, where we have six rigs operating today.

At quarter close, 11 wells were connected and producing into our midstream facilities, five of which were constrained to control flow as we commissioned newly-installed equipment and evaluated initial reservoir performance.

Six wells were in various stages of flowback and testing, and 17 wells were waiting on completion, or shut-in waiting on infrastructure. Subsequent to quarter-end, we have connected additional wells, and production continues to impress.

In addition to the Alpine High parasequence wells that John mentioned, we also recently completed a Barnett well with a test rate of more than 7.7 million cubic feet of gas, 400 barrels of oil and 450 barrels of NGLs per day from a 3,300-foot lateral. I would also note that we are seeing much more competitor activity around Alpine High.

Offset operators have drilled or were drilling 16 wells with another 28 competitor wells permitted. As we drill more wells, we are also seeing improvements on the costs side. We are utilizing a spudder rig to set surface casing in an effort to reduce shallow hole cost associated with high-demand larger rigs.

In addition, we have been successful in the elimination of the casing string in some areas, and reduced drill time in the intermediate and lateral sections of the well. All-in costs for these wells are on track to fall within our targeted range of $4 million to $6 million.

Elsewhere in the Delaware Basin, in our Mentone field north of the Alpine High, we brought online a five-well pad at the Magpie unit. These wells were drilled with 1-mile laterals in the third Bone Springs and achieved an average 30-day IP rate in excess of 1,000 BOE per day and an average cost of $4.5 million per well.

In the Midland Basin, we are primarily focused on drilling larger multi-well pads. The nine-well Schrock 34 pad in our Azalea field is contributing strong performance. This mile-long pad was designed as a spacing and landing zone test with completion in the Wolfcamp A1, B1 and B3.

In addition to this pad, we drilled the Calverley 2932 1H, a 1.5-mile lateral that is the first well of a future nine-well pad. 30-day IPs from these 10 Azalea wells averaged approximately 950 BOE per day, with a 75% oil cut.

In the Powell Field, we completed the first two wells on two separate pads, where we plan to drill a total of 12 wells each in the Wolfcamp B formation. One pad has a mile laterals and achieved a 30-day average IP rate of nearly 900 BOE per day.

The other pad has a 1.5-mile laterals and achieved an average 30-day IP rate of just under 1,300 BOE per day. During the second half of 2017, we plan to bring online approximately 30 Midland Basin wells, most of them having extended laterals of 1.5 miles or longer. I'll turn now to our international assets.

Adjusted production in Egypt, which excludes minority interest and the impact of tax barrels, increased slightly from the first quarter 2017 to 89,000 barrels of oil equivalent per day. We had several exploration and development highlights from the Egyptian drilling program during the second quarter, primarily in our legacy Matruh Basin.

We are developing new concepts in this mature basin, which is leading to greater results from great rock. We tested two zones at the Herunefer West 1X well. The AEB tested 5,900 BOE per day, and the Lower Safa tested 4,500 BOE per day.

The discovery established our thickest pay interval to date within the basin, logging approximately 400 feet of total net pay in the Safa and AEB formations. It also sets up several development locations and derisks additional exploration prospects on trend.

Also in the Matruh Basin, the Bravo 2X tested at nearly 4,100 BOE per day from 78 feet of pay in the Safa, with additional pay behind pipe. In Egypt, during the first half of 2017, we have drilled a total of 43 wells with a 77% success rate.

Notably, 22 of the 33 producers have exhibited extremely high test rates exceeding 1,000 BOE per day, with successes spanning five different basins. Keep in mind that these are vertical wells with completed well costs of approximately $3 million. We have also performed 18 recompletions this year, with flow rates also exceeding 1,000 BOE per day.

I'll move now to our North Sea region. Due to scheduled maintenance activity at the Beryl platforms, our production declined to 55,000 BOE per day during the second quarter of 2017. This was better than expected, as equipment deliveries necessary for the planned maintenance turnarounds were delayed, so the tar started later than planned.

We used this delay to accelerate testing of our first well at Callater, the 18x. As previously disclosed, the lower half of the 18x tested at a peak 24-hour rate of more than 15,000 barrels of oil and 28 million cubic feet of gas. This was stronger than expected and nearly equivalent to the rate that we had forecasted for the entire well.

Subsequent to the second quarter end, we tested the upper half of the Callater 18x, and it flowed at a peak 24-hour rate of more than 19,000 BOE per day with a 69% oil cut. As John noted, we also recently completed a second well at Callater in the adjacent fault block.

The CB2 tested at a very strong 24-hour rate of more than 11,000 BOE per day with a 65% oil cut. With both wells flowing at Callater, we expect the North Sea will deliver higher production levels in the second half of the year. In addition to the progress at Callater, we drilled the BLB, an infill well at Beryl Bravo platform.

This well flowed at a 30-day initial production rate averaging nearly 6,400 barrels of oil equivalent per day, with an 82% oil cut from the Nansen reservoir. Please refer to our financial and operational supplement for more details on our second quarter production.

Across our portfolio, we are implementing new technologies to improve the data we use to explore the subsurface, increase operational efficiencies, reduce costs, and improve hydrocarbon recoveries while optimizing net present value. We are taking an integrated geoscience and engineering approach to these initiatives.

In the Permian, both in the Delaware and Midland Basins, we are collecting massive amounts of data from multiple sources.

On a single pad, to better understand reservoir performance, we have obtained or installed downhole microseismic data, surface vertical seismic profiles, fiber optics collecting pressure and temperature data, downhole pressure monitors, and oil and chemical tracers.

This data collection and analysis will provide us unprecedented insight into the effect of our stimulations on the rock fabric. Ultimately, it will allow us to optimize well placement and spacing.

Apache also has been building new state-of-the-art water treatment and recycling facilities, including large, highly engineered water storage pits in both Midland and the Delaware Basins. These facilities directly add value to our projects by reducing water costs and increasing reliability and flexibility.

Finally, Apache is developing new workflows and technologies that allow for rapid characterization of thousands of feet of core and quickly getting this into the hands of geologists and engineers for faster characterization of shale plays and landing zones.

Overall, we are building a far more robust understanding of our conventional and unconventional plays and their performance than was previously possible. Instead of just gathering data, we are owning, maintaining, validating, and optimizing the use of the data to add value to our assets. I'll move now to service costs.

This is a positive execution story, as we've been able to effectively maintain the lower cost structure achieved in 2016. As John noted, we anticipated much of the inflation we're seeing today and have been successful offsetting it with operational efficiencies and service contracts.

Overall costs for North America were essentially flat in the second quarter of 2017 compared with the first quarter. We do not expect rising service costs to materially impact our activity or budget for the remainder of 2017.

We continue to see cost inflation for certain services and supplies, primarily for pressure pumping and sand in West Texas, where spot market prices continue to trend upward. Hoping to offset this, we are sourcing low-cost sands that are delivered from local mines in the Permian Basin, reducing transportation costs considerably.

We also entered into contracts with pricing indexed to WTI, which protects against a portion of those increases. Internationally, costs are tracking as expected. During the third quarter, the current contract on Ocean Patriot expires, and we've renewed the semisubmersible drilling rig at a considerably lower day rate.

This will reduce our North Sea drilling costs in 2018 and 2019, with an option for a third year. I will conclude by noting that we have increased activity in North America at a very measured pace and generally avoided direct competition for equipment and services at spot market rates. We are focused on generating strong, fully burdened returns.

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

Thank you, Tim, and, good afternoon, everyone. On today's call, I will review our second quarter financial results. I will provide an update on quarterly and annual guidance items, which will reflect the full anticipated effect of Apache's exit from Canada.

And lastly, I will comment on our updated hedges and the continuing strength of our financial position. Let me begin with second quarter financial results. As noted in our press release, Apache reported net income of $572 million or $1.50 per diluted common share.

Earnings were positively impacted by a net deferred income tax benefit related to a financial restructuring in Canada in preparation for the exit. This consists primarily of a $678 million reduction in a U.S. deferred income tax liability with respect to untaxed foreign source earnings.

Together with some other smaller adjustments, the total tax benefit excluded for purposes of calculating adjusted earnings is $670 million. Results for the quarter also included a number of other items outside of our core earnings that are typically excluded by the investment community in published earnings estimates.

These include a $26 million unrealized mark-to-market gain on our commodity price hedge positions, $25 million of unproved acreage impairment and $18 million of loss related to recent divestitures. Excluding these and other items, our adjusted loss for the quarter was $79 million or $0.21 per share.

Note, this adjusted earnings still includes the effect of dry-hole costs incurred of $46 million or $0.08 per share after tax. Cash flow from operations in the quarter was $751 million. This includes a working capital benefit of $148 million. Our cash position on June 30 was $1.7 billion, a slight increase from the previous quarter.

Turning to costs, lease operating expenses in the second quarter were $8.81 per parallel of oil equivalent, an increase over the first quarter rate. This increase was anticipated and is primarily attributable to seasonal maintenance activity in our North Sea business.

Our first half 2017 LOE was $8.27 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 second quarter was $108 million, $85 million of which was attributable to dry-hole expense and unproved leasehold impairments.

Now I'll move to guidance, and today we are mending several of our 2017 guidance ranges to reflect the impact of Apache's pending exit from Canada. As previously announced, we are exiting our Canada business via three separate transactions. Our 2017 updated guidance is provided on pages 22 and 23 of the supplement.

All new guidance now reflects Canada results through the actual or anticipated transaction closing dates. As a reminder, the first of these three transactions closed on June 30, and the other two transactions are expected to close in August.

Additionally, on pages 19 through 21 of our supplement, we have provided new adjusted quarterly production guidance which excludes Canada from all quarters in 2017. I will walk through some of these guidance items, but my comments will be relatively brief. So feel free to follow up with Gary and his team with any questions you may have.

Beginning with our adjusted North American production guidance on page 19 of the supplement, we have removed actual and projected Canadian production for all of the periods shown. We have also tightened our forward-looking guidance ranges reflecting more clarity around our second half production ramp, particularly at Alpine High.

On the international side, our adjusted production guidance remains essentially unchanged. However, I would like to note that Egypt tax barrel guidance for reporting purposes has decreased by 10,000 BOEs per day, which is primarily driven by a lower commodity price outlook and thus lower taxable income in Egypt.

With regard to capital, our $3.1 billion 2017 budget is not impacted by the Canada exit, since most of the capital allocated to the Canada region this year will have been spend by the time the transactions have closed. The exit from Canada will reduce our planned 2018 capital budget by approximately $125 million.

Turning to guidance for expenses, on page 23 of the supplement, you will note that we reduced annual guidance for G&A expenses by $25 million and for gathering and transportation expenses by $20 million to $30 million, both primarily to reflect the Canada exit.

Note that our DD&A guidance for 2017 has increased slightly on a BOE basis since our Canada business had a relatively low carrying value. Moving now to hedging, in addition to our oil PUDs, we have begun adding some gas hedges.

For the second half of 2017, we have now swapped an average of 33,750 MMBtu per day of gas volumes at an average price of $3.36. More significantly, we have begun hedging our first quarter 2018 gas volumes with 150,000 MMBtu per day swapped at an average price of $3.39.

As a reminder, the primary goal of our hedging activity is to protect the pace and delivery of a strategically important capital program at Alpine High. This continues to be the case as we look to 2018. We do not use hedging to speculate on price. I would like to conclude by emphasizing Apache's financial strength.

This is a product of our disciplined approach over the last few years. As I indicated previously, our cash position has been growing and net debt is down $355 million since the beginning of the year.

For the remainder of the year, our cash flow is well protected with our price hedges, so our ability to fund the capital program and dividend payment without utilizing the balance sheet is secure. We are well prepared for continued volatility in oil and gas prices.

We continue to balance the need to flex the capital program commensurate with the price environment, while also funding our long-term strategy. Throughout this effort, we focus on investments that will deliver sound full-cycle economics at current or even lower commodity prices. With that, I will turn the call over to the operator for Q&A..

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

A question on the Midland Basin. There's been a lot of talk amongst investors about rising gas-oil ratios in that play and the potential that they're displacing forecasted oil type curves.

What's your view on that? How do we think about your GORs in the Midland?.

This is Tim. In the Midland Basin, our shale wells, they're performing in line with our type curves. We really haven't been surprised by the GORs. We understand the producing characteristics of our different areas that we operate in. And our GORs are performing as we would have expected..

Okay, great. Thanks.

The other is, do you have an estimate of where you were Alpine High sort of end of – or currently or call it the end of 2Q?.

Actually in the prepared remarks, Bob, we said we produced 7,400 BOEs a day net to Apache. 10% of that was liquids and almost all of that was oil in the month of June..

Got you. Thank you..

You bet. Thank you..

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

Yeah. Good afternoon. John, I wondered if you could give us a little bit more detail. In your prepared comments you talked a little bit about how you expect Alpine High to perform in the northern part of the field versus the south. So I wondered if you can give us a little bit more color around that..

I mean, Arun, I think the good news is, is we got online early. We were scheduled to bring everything on July 1. We have some of the stuff to talk about in the second quarter, because we were able to bring things on in early May. Things are progressing really as planned. We were able to sell net to Apache 7,400 BOEs a day in the month of June.

And like I said, we've been bringing up the CPFs. If you look at kind of where we are today on the infrastructure, we now have 35 miles of the 30-inch trunkline in. We've got over 40 miles of gathering in. There are two CPFs that are operating with eight tank batteries.

And then in August and September, we've got our third CPF coming in – coming on in August, fourth and fifth in September, as well as a connection to the south. And so what we've said is, our volumes are – we're currently producing about 60 million a day net to Apache. You're going to see that grow to 100 by September.

And you're going to see the liquids ratio grow as well, especially as we start to bring on more NGLs. So a lot of exciting things. We only had 11 wells on in the quarter, and really five of those have been constrained. So we're really, really just getting started..

Got you. Got you. And then, just in terms of – you talked about by year-end getting to six CPFs.

What type of productive capacity do you get from six CPFs?.

We've said that we're going to be bringing on these CPFs in increments, 50 million to 100 million a day. They're all going to be able to be incrementally added. So what we've done is given you volume forecast and guidance. Right now, we are constrained, but we hope to resolve that as we catch up, as these things come on in the next couple of months.

And then, from there, we hope to have more capacity than we'll have volumes..

Got you.

And just my follow-up is just in Egypt, what is your plan to explore on some of the new licensed acreage that you've received, I think, earlier this year?.

It's going to – it depends on the timing. Right now, as we've said, we're shooting a brand new high-res 3-D across our existing acreage. And as well, we'll be shooting the new permits as soon as we get the final documents signed. Everything's approved. We're just waiting on the final documents. So that should happen here pretty soon.

We'll get started on the seismic in this fall, and we could potentially drill our first well this fall. We see a lot of low-hanging fruit, and we're very, very excited about the potential. I mean, they're very large concessions. We know a lot about them. And – I mean, they're going to be a real, real shot in the arm.

You got to go back to over 10 years since we've had two new concessions. Not anything of this size either, so it's going to be a real shot in the arm for our Egypt production, maybe late this year, most likely as you start to go into 2018, 2019, and beyond..

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

All right, good afternoon.

John, could you talk about – do you guys have a definitive timeline as far as when we'll get more clarity around the potential resource at Alpine High?.

David, as we've said, we're ramping up most of our wells, like the wells we disclosed on the last earnings call. We cleaned them up and shut them in. Most wells have been waiting. We've got – as Tim said in his notes, we've got a lot of wells waiting on the infrastructure.

Now that we have the facilities and things, it doesn't make a lot of sense to be flaring volumes and things. And so, as we bring more things on, I think you're going to continue to see a lot of data coming.

And when we get to a point that it makes sense to talk more definitively, what we really want to do is get the processing facilities lined out, get more time behind the wells, continue with our optimization work, and at some point, we'll come back with something very meaningful and very definitive.

But I think what we've continued to state is that we feel very, very good that we have more than 3,000 wet gas locations. Your best EURs would be to look at what we disclosed at Barclays almost a year ago.

And now we said with the two Wolfcamp wells that are, by the way, in two different zones in the Wolfcamp, in a significant distance between those wells, we feel very confident now that we have hundreds of locations in the Wolfcamp, so – that will be oil locations. And – so we'll come back as we get more data.

We're really just getting started with our infrastructure and being able to bring things on and produce them into ideal production situations..

Okay. I think – let me just stay with Alpine High then. Midstream, future funding, there's been a lot of talk about whether you sell it, whether you bring a partner in, whether you're going to go out alone.

Any additional color you can give us on that?.

Well, I think what you've seen is this year we had an outspend on our infrastructure side and now we've more than covered that. As we look at 2018, we – the 2018 budget had originally looked at $55 as a price target. We've said that there are lots of options we have on that. Our spend in 2018 is planned around $500 million.

We're probably going to pull some of that into this year as we stated within our $3.1 billion budget. So we feel very comfortable that we're going to be able to handle that funding without having to stress the balance sheet, issue equity, or really put ourselves in a bind..

All right, thanks..

Our next question is from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt..

Good afternoon, thanks. In the Alpine High, specifically on the oil zone test, I realize that it's early.

But can you speak to your initial thoughts on the deposition of both the Wolfcamp and Bone Spring across your position?.

It's going be very similar, the parasequences. So they were laid down at a time when you had very rapidly rising sea level. And so there is some discontinuity in them just like there is in all of the Delaware Basin, so very similar. And so you've got a lot of mixed things in there. But we're very excited about what we've got.

And these two wells are going to perform very similar to the other wells in the Delaware Basin..

Great.

And then staying in the Alpine High but on optimized completions, can you give us some detail on what you're testing, when we can expect to hear more, and what early indications you have, if any?.

When we talk about optimization, there's really a lot of things. It involves targeting, spacing tests, pattern tests, landing zone, lateral length, the orientation, and in the completion design. And even in the completion design, you've got your fluids in terms of your volumes, your sand concentrations, the stages, clusters, everything.

So we have begun the optimization process. We've actually had 11 wells into the system at the end of the quarter. As we bring more in, clearly we're going about it very methodically like we have the whole play. And as we get to points where we draw some conclusions, we'll start to make those more clear. But we're doing a lot of things.

We've got some longer laterals. We've got some larger fracs, targeting, azimuth, everything..

Thank you..

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

Good afternoon..

Hey, Brian..

A couple follow-ups on the capital allocation question.

When you say moderate outspend for the near term, can you add more color on the length and threshold for that outspending? And I guess relatedly, if Alpine High midstream is where you see the outspend happening, when does the midstream achieve critical mass, and then when would we expect the outspend to end?.

When we think about – right now we're just talking 2017 and 2018 is what we've been looking at. So if you look at 2017 and 2018, that would be that time period.

I think the important thing with our infrastructure at Alpine High is it's going reach a critical mass where we really believe middle of next year we could be in a position to start to monetize a portion of it or do something there.

So we'll look at 2018 as we start to roll into – later this year or early next year, we'll start to give another look into 2018 and beyond. But we're looking right now at 2018. The other thing I'll say about 2018 as our original budget had it – which is really flat activity to this year, had a $55 deck in there.

$5 in oil price means about $350 million of cash flow to us. And so we see we have a lot of flexibility with our program. One, we can reduce activity. Two, if we really are in a sub-$55 world next year, then our cost structure is going be lower than what we have in that budget. So there will be the ability to get more for that activity set.

I think we've shown this year we can do some non-material asset sales, which I would not put the strategic exit from Canada in that bucket. I've touched on the Alpine High midstream, and then we also have a very nice $1.7 billion of cash on the balance sheet..

Great, thank you. And then switching to the Alpine High Wolfcamp oil well, the first well that you announced where you talked about 1,000 BOE a day, it looks like that would imply about 700 barrels a day of oil in the first month, and then about 350 to 360 barrels a day for the remainder of the 75 days.

I just wanted to check in on both your expectations for well costs for these wells and then if these rates are in line with your type curve and what rates you're looking for from the next batch of wells..

It looks really good. I think the thing we'll say, number one, it's approximately 4,500 foot lateral. It has come on 70% oil. And the 30-day average is actually greater than 1,000 BOEs a day, and it did produce 37,000 barrels of oil in the first 75 days. A lot of the research this morning has come out tagging that as BOE, which is not correct.

Very typical profile to a lot of the other Delaware wells. Good charge. We'll have more water than we'll have in our resource zones in the Woodford, Barnett to pin, so it's going to be very typical characteristics and very, very strong profile, and performing very, very well..

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

Good afternoon, John, to you and the rest of your team there..

Hi, Charles..

Thank you. You guys have fielded a lot of Alpine High questions, so I'm going to go a slightly different direction. I think you – perhaps Tim hinted at this in some of his earlier comments.

When I look at the wells you guys have drilled already, you've drilled 1-mile laterals with a significantly lower completed well cost than your peers have been delivering in the area.

But I think what I heard is that going forward, at least in the back half of 2017, you guys are going be going after longer laterals which presumably will have some higher completed well costs.

And I wonder if you could characterize for us where you think you are on your optimization of your well design and your completion time design for those Midland Basin wells..

Charles, what we've been doing primarily is we've been drilling mile laterals in our three core focus areas; Wildfire, Powell, and Azalea. If you go back to 2016, we changed our completions dramatically since then.

And one thing I might note though, if you look at our completed costs from 2016 to today on those mile laterals, our completed well costs have remained relatively unchanged at about $4.5 million.

And a lot of that has been the conversion from drilling one-offs to going to pad drilling and getting the efficiencies obviously from batch drilling and the savings that we see there. Going forward, we've got about 30 wells.

We've got about five different pads that we anticipate we're going bring online in the second half, and most of those are going be mile and a half type laterals. And we are still doing a little bit of spacing testing and landing zone testing along with this development drilling that we're doing as well.

So the completions are still – we're still working on them, and every area is a little bit different, so I don't think we'll ever get to one completion design that will be standardized across the entire play. It's going be tailored to the type of rock that we've got at each field that we have.

So it's something that we will continue to optimize, and we'll really never be done with that process..

Okay, thank you for that, Tim. And then if I could ask a question about the North Sea, and you had those impressive well results with Callater. And I'm wondering if you can guide our expectations a bit with respect to North Sea results going forward.

Should we look at Callater and particularly at the idea that this most impressive well was on offset fault block? Should we be looking for more sorts of results like this, or is this a one-off sort of thing that we ought not look for a repeat?.

Callater is a well we disclosed in 2015. It was a new discovery. There will be some offsets. We announced another fault block there with that, so we're very excited about the area. I think the best thing to do in terms of forecast is just look at what we've guided to, Charles. I mean, we've had this well planned in and this development baked in.

It's really a function of the exploration program. We've had a series of announced discoveries over the last couple of years that are in the queue to be coming on in the future, and Callater is kind of in the first of those that we're tying in, in 2017, so....

Our next question is from the line of Evan Calio with Morgan Stanley..

Hey. Good afternoon, guys. Maybe I'll bring it back to the Alpine High.

And maybe I missed it, but when do you guys expect to reveal the larger development plan you discussed in the call? Is it – is that in connection with the 2018 CapEx budget? And if there's no specific date, what still needs to happen there before you feel confident in that plan?.

Well, we feel confident in the plan, Evan. I mean, obviously, we gave guidance this year for a two-year look. We've given you a 2018 4Q exit rate, and we didn't touch any of those numbers this quarter. In fact, didn't really touch our guidance at all, other than adjusting for Canada. So we have a plan that we're working on.

We're always updating it with new data. We've still got a lot of areas we are testing and bringing things in, but we have a base plan and we gave you a two-year look at it this year. Obviously, we'll choose as we're phasing in and bringing things on. We've said we're at 60 million a day net today, and we'll be north of 100 million in September.

And as we get more color and continue, we'll come at it sometime in the future and give you a longer look. But we gave you a good two-year look, and for now, we have a lot of confidence in that..

And maybe to follow up on that, the 100 million guide, can you walk us through how that estimate is billed? Meaning, how many wells are connected and what percentage of them will be on constrained flow because it's harder to – it's harder to kind of model for us?.

The better thing to do is look at the numbers we gave you and run off of those, because we've gone end of the first – end of the second quarter we had 11 wells on and five of them are constrained. And we should get to a point where we don't have constrained wells as we get these next three CPFs up over the August and September timeframe.

But we haven't given an absolute well count, as that's dynamic. But what we have given you is ranges, Evan. And we said, in June we produced 7,400 barrels of oil equivalent a day net. It's not gross; that's net. And it was 10% liquids, and almost all of that was oil. And the liquids ratio is going to grow as the volume grows in the future..

Our next question is from the line of James Sullivan with Alembic Global Advisors..

Hey. Good morning – good afternoon, guys, there. I just wanted to go back to that Wolfcamp oil well real quick. You talked, John, about there being a nice charge in that well there, and a couple of comments on the overpressure there.

Could you just talk about how you released that well, I mean, in terms of initial chokes and how you were kind of letting it out there? Any color you can give on that would be great. And on pressure drawdowns, too..

It's just a very, very strong well. We've flown it back naturally, and there is a sub pump in there today. And it's very typical to the other wells we have and the other areas of the Delaware Basin..

Okay. Great. Sounds good. Just on – over to the North Sea real quick, you guys did the turnaround over there.

Can you quantify the amount of volume that was offline there for the quarter?.

For the second quarter, it was just under 7,000 barrels of oil equivalent per day. That was offline. Some of that turnaround got pushed into the third quarter. So we'll see some downtime from turnarounds in the third quarter as well..

Okay.

And then Q4 will be more like your run rate?.

Correct..

Great, thanks so much..

Our next question is from the line of Michael Hall with Heikkinen Energy Advisors..

Thanks. I guess just a couple on my end.

As it relates to the DUCs and wells waiting on infrastructure and just I guess general backlog in the Alpine High, how many of those at present are currently in the oilier zone?.

Yeah. Right now, Michael, we've got a mix. We haven't given breakdowns on that. You've got a range, some of those are going be wet gas wells. Some of them are going to be – there's a few we've got several that are in flow-back. So it will be a mix kind of like we have across our play..

Okay.

But specific to the Wolfcamp or Bone Spring, you don't, by chance, have that available?.

There's going be more than two, and I'll just say that..

Okay, fair enough. And then I guess the other was just still on the Permian, but higher level. I was just curious when you guys think you'll see oil volumes in the Permian turn around? They've been obviously on decline, but you've got a big back-half ramp that you've outlined.

Do you think we'll see sequential growth in oil volumes in the third quarter or how should we think about that?.

Yeah. So, we have turned the corner now on growth, not only in international and in North America, but just on North – our Permian oil growth will be – continually grow quarter-after-quarter..

Okay. Appreciate it. Thank you..

Our next question is from the line of Jeffrey Campbell with Tuohy Brothers..

Good afternoon..

Hey, Jeff..

Hey, John. In the Permian Basin, many producers are moving towards completing all the locations of a given zone or maybe even several zones and wants to avoid well interference and enhance efficiencies. I was just wondering what is your completion approach as you're increasingly focusing on drilling more wells and zones per pad..

That's a novel idea. We've always talked about – ultimately you do your testing, so you can get to pad development, and that is the optimal way to do that. So you want to get in the pads where you can develop the rock and produce it in the best way, shape or form. So it's exactly the approach we're taking.

That's – we've got some 10, 11 well pads coming on later this year in Midland Basin. So I mean it's clearly the direction you want to go with all of it..

Okay. Thanks. And my other question is in Egypt. With the large increase in acreage, how will you allocate capital there over the next year or two? I mean, obviously you're having great success in the areas where you have concentrated operations.

So I'm just wondering how will exploration spend on the new acreage look relative to the spending as a whole..

It's probably going be pretty similar to how it's been. I mean, we drill quite a few exploration wells in Egypt every year anyways. So as Egypt continues to generate more free cash flow, potentially you could see more capital. But we're not going to change philosophically how we're thinking about that. But it's an exciting place.

I mean, I think we're going to find ourselves with better – some pretty strong deliverability things, much like Ptah and Berenice have been over the last couple of years. So a lot of low-hanging fruit that should help us with volumes and also with the ability to generate more free cash flow and also reinvest more..

Okay. Thank you..

And our last question is from the line of Doug Leggate with Bank of America..

Thanks, everybody. Good afternoon and thank you for getting me on, John. John, you guys are....

Only for you, Doug..

I'm trying to take advantage of you a little bit here, John, because you're uniquely qualified with your background and your vertical well inventory for the history of Apache to really opine on this issue that, I guess, Bob brought up earlier. Obviously, sector is getting annihilated in the back of this GOR issue.

So I'm wondering if you could take just a little bit of time and just maybe do the market a favor and explain what you meant by the type curve or the gas breakout, the GOR has not changed adverse to your expectations.

And what I'm getting at is the difference between the pressure drawdown in the vertical versus the pressure drawdown in the horizontal.

What are you seeing there? Is there anything different in the oil recovery in your Midland Basin wells versus what you expected and versus what you've planned on based on that vertical well history? Because there seems to be a little bit of a panic going on that this is actually a deterioration of oil recovery as opposed to an enhancement of gas and NGL recovery.

Could I ask you to....

I'll say a few things. Number one, we've always forecasted our oil and gas streams separately. Like – I mean, it's just fundamental petroleum engineering. Anybody forecasting BOE curves and you've got changing dynamics out there you have to model it. I mean, it's like anything else though, Doug.

You do your core work, you do your fluid analysis, you look at your pressure and temperature data. And we can model that. We've got a lot of history and we do a lot of time modeling that. And so our wells are producing and – as our type curves are laid out.

And we have not had any surprises in terms of the forecasted volumes with how they are performing. Areas behave differently. And if we go back to some of our earlier areas where we drilled some wells in 2010 and 2011, they were in a little less mature area, a little higher GORs, they're going to behave differently.

We've got a lot of history and have a deep understanding of how this works. And so we're not surprised by the GORs and you have to examine those very carefully.

And – but every rock, every area, the rocks will differ depending on the play, and that's why it takes time to collect the data properly, do the core work, do the fluid work, do the pressure work and create your material balance just like you would in conventional rock. But there's a difference..

I appreciate that..

There's just a real difference between how conventional and unconventional reservoirs behave and there's a difference how they behave over time. And you'll see contribution from different types of the fabric as it goes forward..

So just to be clear, I know we're out of time here.

So if I could just add two quick pieces to that, one is, related to that, the vertical pressure drawdown versus a horizontal pressure drawdown, would you concur with the idea that the horizontal is getting the gas breakout quicker but not changing the material balance?.

I wouldn't say that rock is going to drawdown and break out exactly how it's exposed to the surface. So that's just a function of temperature and pressure and the drawdown. The orientation of the well isn't going to have as big of an impact as just how the rock is going to behave under pressure and temperature and how the makeup of it is..

Okay. And my last one is more Apache-specific. What do you need to see to declare a broader oil inventory in the Alpine High? Obviously, you've given another couple of wells today.

And if I may, when that happens, I assume it's going to happen at some point, would it change your targeting on how your initial development plan versus – oil versus gas? And I'll leave it there. Thank you..

I'd say any incremental well, obviously, you tweak your plans as you go through it. You'll see more from us as we bring more wells out. We've had 11 wells on the end of June, half of them, or five of them were flowing constrained. We've just got a lot of data coming over the next couple of quarters. But it's very exciting.

We're going to be very deliberate on what we disclose. We're not going to come out with big location counts unless we're confident in those location counts. And there's a lot of rock to test even in our parasequence zones. So there's a lot of exciting things.

We've got a big thick column, 5,000 feet of hydrocarbons over a 65-mile area down there, and a lot of rock to work with, so you're going to see a lot more locations coming out of us in the future..

And that does conclude the Q&A portion of this call today. Thank you for your participation. Ladies and gentlemen, you may now disconnect..