Gary T. Clark - Vice President-Investor Relations John J. Christmann - President and Chief Executive Officer Stephen J. Riney - Chief Financial Officer & Executive Vice President.

Doug Leggate - Bank of America – Merrill Lynch David R. Tameron - Wells Fargo Securities LLC Leo Mariani - RBC Capital Markets LLC Bob Alan Brackett - Sanford C. Bernstein & Co. LLC Arun Jayaram - Credit Suisse Securities (USA) LLC (Broker) Charles A. Meade - Johnson Rice & Co. LLC Paul Benedict Sankey - Wolfe Research LLC Pearce W.

Hammond - Simmons & Co. International James Sullivan - Alembic Global Advisors LLC Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc..

Good afternoon. My name is Fia and I will be the conference operator today. At this time, I would like to welcome everyone to the Apache Corporation First Quarter Earnings 2015 Conference. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. Thank you.

At this time, I would like to turn the conference over to Mr. Gary Clark. Sir, you may begin..

Good afternoon, everyone, and thank you for joining us on Apache Corporation's first quarter 2015 earnings conference call. Speakers making prepared remarks on today's call will be Apache's CEO and President, John Christmann; and CFO, Steve Riney. Also joining in the room today is Tom Voytovich, Executive Vice President and COO of International.

In conjunction with this morning's press release, I hope you have had the opportunity to review our quarterly earnings supplement, which summarizes our operational activities and well highlights across various Apache operating regions.

The supplement also includes information on our capital expenditures for the quarter, as well as a chart that illustrates cash sources and uses, and reconciles Apache's change in net debt during the first quarter of 2015.

Our earnings release, the accompanying financial tables and non-GAAP reconciliations, and our quarterly earnings supplement can all be found on our website at www.apachecorp.com. I'd like to remind everyone that today's discussions will contain forward-looking estimates and assumptions based on our current views and most 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.

This morning, we reported a first quarter 2015 loss of $4.7 billion or $12.34 per diluted share, which includes an after-tax ceiling-test write down of $4.7 billion, primarily related to the impact of declining oil and gas prices.

When adjusted for certain items that impact the comparability of results, the first-quarter loss totaled $139 million or $0.37 per diluted share. Cash flow from operations before changes in working capital totaled $900 million during the quarter.

Worldwide reported net production averaged 601,000 barrels of oil equivalent per day, with liquids production constituting 62% of the total. I would now like to turn the call over to John..

Thank you, Gary. Good afternoon, and thank you all for joining us today. I'm pleased to report that we had a successful first quarter on several fronts. Operationally, we executed a very rapid and efficient downsizing of our drilling program.

On a go-forward basis, our reduced program better aligns capital expenditures with cash flow in this depressed oil and gas price environment. Specifically, we decreased our North American rig count by 77%, from 65 rigs on December 31 to 15 rigs by the end of the first quarter. We are highly focused on reducing all elements of our cost structure.

On the capital side, we were fortunate to enter this downturn with minimal long-term rig contracts and very few acreage exploration issues.

As a result, we were able to quickly adjust our costs, and now project that total drilling and completion costs will ultimately be down between 20% and 40% in 2015 from the levels we disclosed for our key plays at our North American update in November.

And compared to 2014, we are on track to achieve an overall 25% reduction in average drilling and completion costs. As the year progresses, we anticipate capturing potentially more savings. With regard to G&A, over the past 18 months Apache has divested a substantial number of operated properties and exited several operational areas.

Our smaller footprint now requires less overhead and a more prudent approach to spending. Every dollar we save in corporate overhead can be recycled into our asset base to generate a return for our shareholders.

We are structuring Apache's organization, planning functions and operational teams to provide maximum flexibility to respond to commodity price changes and cash flow availability. We have budgeted conservatively at $50 WTI for the year. And while first quarter oil prices came in a little below that level, the second quarter is off to a good start.

Should oil prices stabilize at these higher levels and cash flow increase accordingly, we are well-positioned to ramp up the drilling program in an efficient and cost-effective manner.

Despite a significant reduction in drilling and completion activity, we were able to minimize our first quarter production decline in North America from record fourth quarter levels. We also encountered some significant weather challenges in our Permian and Central regions during the quarter.

However, North American onshore production still exceeded the high end of our guidance range. On the international side, Egypt and the North Sea both outperformed our expectations during the quarter, primarily on the strength of successful delineation drilling and better than expected well performance.

Australian operations were generally on track in Q1. However, production was adversely impacted by two cyclones that hit late in the quarter. Turning to our capital spending; during the quarter, capital expenditures before LNG, capitalized interest and Egypt's minority interest was $1.3 billion.

This represents approximately 36% of our full-year 2015 capital budget, the midpoint of which has been reduced to $3.65 billion. CapEx was in line with our expectations for the quarter and consistent with our commentary on last quarter's call that we were coming into 2015 hot on activity and capital.

Given the magnitude and success of our first quarter activity and spending ramp down, we remain confident in our 2015 CapEx guidance. Also, despite our significantly lower activity levels for the rest of the year, we remain comfortable with our pro forma North American onshore production guidance of relatively flat compared to 2014.

In summary, it was a very good quarter both domestically and internationally. And I'll provide a little more detail on the regions in a moment. Since the last earnings call, we have made excellent progress on our portfolio repositioning initiatives.

In April, we announced the closing of our Wheatstone and Kitimat LNG assets along with a definitive agreement to sell the remainder of our Australian oil and gas assets.

We expect to close the Australian asset sale around mid-year and our updated capital and production guidance provided in this morning's press release takes into account this assumption. In his prepared remarks, Steve Riney will discuss how we plan to utilize the $5.8 billion of proceeds from these transactions.

I'd like to now make some comments about our operating regions and also provide some color on our projected year-end horizontal well backlog. As I noted earlier, we substantially reduced our drilling and completion activity during the first quarter. In North America, we completed 42% fewer total wells compared to the fourth quarter of 2014.

More importantly, we deferred our scheduled horizontal completion count in anticipation of better pressure pumping pricing from our third-party vendors. For example, we completed only 84 operated horizontal wells in North America during the first quarter compared to 153 operated horizontals during the fourth quarter of 2014.

Despite these activity reductions, our first quarter North American production averaged 307,000 BOEs per day and exceeded our guidance range of 300,000 BOEs per day to 305,000 BOEs per day.

In our Permian region, production grew 6% compared to the first quarter of 2014, but decreased by roughly 10,000 BOEs per day or approximately 6% from record levels in the fourth quarter of 2014. The majority of this sequential quarterly decrease of approximately 7,800 BOEs per day is attributable to severe winter weather-related downturn.

In fact, had we not encountered weather-related shut-ins during the quarter, our oil volumes in the Permian would have been roughly flat compared to the fourth quarter.

Assuming no change from our currently budget activity levels, we anticipate the Permian oil production will increase gradually for the remainder of the year, while natural gas production should remain relatively flat.

The Permian production increase in 2015 will be driven by the Delaware Basin, where we anticipate generating significant volume growth from 28 wells scheduled for completion in the second and the fourth quarter.

Key Permian Basin well completions during the quarter included two very strong Delaware Basin horizontal wells; the Condor 205H and 206H in our Pecos Bend area and three solid horizontal wells with relatively short laterals at our Powell-Miller area of the Southern Midland Basin.

On a lateral adjusted foot basis, all of these wells produced at 30-day average IP rates above the representative tight curves, which were presented at our November update. In particular, the Condor wells in Delaware Basin, which have been online for just over two months are substantially outperforming expectations.

We look forward to drilling more wells in both of these areas during 2015 and reporting results in the coming quarters. We are making good progress in reducing drilling and completion costs, particularly in the Delaware Basin, where we plan to be the most active this year.

The previously mentioned Condor wells were drilled and completed for around $6 million. This represents a 25% reduction from the $8 million well costs we provided in our November update.

On the Central Basin Platform, we completed a large number of very economic vertical wells from our 2014 backlog and completed two exceptional horizontal wells in our North Monahans area that produced a 30-day average IPs in excess of 1,000 BOEs per day.

In April, we completed our highest IP well ever in our Barnhart area, the Scott Sugg West Unit H11U, which is producing more than 1,000 BOEs per day. Also in April, we put on production our first four Midland County wells in the Wildfire area along with our first well in the Azalea area near the Midland-Glasscock County line.

Early results from these core Midland County wells look very encouraging, and it's fair to say that this activity has positioned us well for a good start in the second quarter in the Permian. Turning to the Central region, production was down 2% sequentially from the fourth quarter after adjusting for asset sales.

This was expected following our significant reduction in activity. During the first quarter, we completed only 24 gross operated wells compared to 51 gross operated wells during the fourth quarter. Apache's primary focuses today in the Central region are the Canyon Lime and the Woodford plays.

The Canyon Lime is a tremendous source rock with significant oil in place, but due to the recent drop in oil prices, we have slowed our drilling pace and turned our attention to optimizing our approach and reducing costs in the area. We have made some significant breakthroughs on the cost side in the Canyon Lime.

Drilling costs in our two most recent wells came in around $4.25 million. Completion costs on these well should be roughly $2.75 million each, which means that all in, we believe we can develop this play for about $7 million per well excluding facilities costs.

This is also almost 20% lower than the $8.5 million well costs that we showed at our November update. We brought online our 93H pad during the first quarter and the flow back has been somewhat limited as a result of an extended third-party plant outage. Regardless, these wells appear to be tracking in line with their type curve.

We have various tests underway in the Canyon Lime that will help optimize the play and prepare for future rig ramp up. Under the improved cost structure I noted above, our Canyon Lime inventory starts to become economic at around $60 or $65 per barrel, and we believe there is significant opportunity to improve the economics as we advance the play.

That said, the Canyon Lime will still need to compete for capital on an NPV and rate of return basis with our other plays. To-date, we have drilled 14 wells in the lower Canyon Lime, 12 of which are online and producing. As of March 31, we had a backlog of four wells drilled but uncompleted in the play.

In the Anadarko Basin, we are currently acquiring seismic and delineating roughly 50,000 net acres in the Woodford Springer play, also referred to industry as the SCOOP. We're currently drilling a two-well pad in Grady County and are planning to drill and complete a few additional Woodford wells later in the year.

A tremendous amount of science and testing is also underway in our Eagle Ford play. To-date, we have drilled in four primary operating areas; Reveille, Ferguson Crossing, Remington and Brazos Riverside and have materially advanced our understanding of this intricate resource play.

We have now drilled a total of 86 wells in the Eagle Ford, 45 of which are online and producing. Lithology and hydrocarbon phases change fairly significantly in Northern Eagle Ford. We're continuing to test optimal drilling and completion methods, frac designs and well spacing.

Each of these inputs can vary materially depending on the hydrocarbon phase window and clay count of the area. In Area A, which is generally characterized by higher gas/oil ratios, the drilling is a bit more complex and expensive due to depletion in the chalk above the Eagle Ford.

Our current drilling and completion cost target is around $6.5 million, which is down more than 20% from the $8.4 million we cited back in November. In Area B, which is a bit shallower, we estimate drilling and completion costs will be around $6 million per well, which is down roughly 15% from previous estimates.

We have a large backlog of wells to complete in the Eagle Ford, and while we may not get to all of them this year, we can expect this play will contribute to our North American oil growth in 2015 and 2016. Like the Canyon Lime, we anticipate becoming a more active driller in the Eagle Ford when oil price approaches the $65 per barrel level.

In Canada, we had a good quarter. Weather-related downtime was minimal, and production decreased only modestly from the fourth quarter 2014 levels, despite reduced completion activity. During the quarter, we generated positive results in a new lower-cost oil-rich area of the Montney, which we call Ante Creek.

We have some running room there; however, more infrastructure will be needed to bring these wells online. We also successfully tested the very thick lower Montney formation for the first time in our Wapiti area and believe it will have minimal communication with the currently productive horizons in the upper Montney.

In the Duvernay, we just completed drilling our first seven-well pad in the Kaybob area and look forward to completing those wells and bringing on some significant volumes during the quarter. Turning to our international operations; in Australia, our production averaged 59,400 BOEs per day, which was down from the fourth quarter.

During the quarter, we had unanticipated production shut-ins for approximately 2,600 BOEs per day due to the impact of two cyclones that hit the region. Otherwise, the ramp up of our Coniston and Van Gogh fields remains on schedule, as does the planned sale of all of our Australian oil and gas assets by mid-year.

In Egypt, the successful delineation of our Ptah and Berenice fields has led to a recent gross production rate of more than 19,600 barrels of oil per day from seven wells. This month, we plan to place one more delineation well online and increase production to approximately 22,000 barrels of oil per day.

Several other new field discoveries have been made across multiple concession areas subsequent to quarter-end. As a result, Egypt is tracking very well against our production outlook from February 12.

Apache's production in the North Sea decreased as expected from a record high in the fourth quarter of 2014, but was up 5% relative to the first quarter of 2014. One of the two main electrical transformers failed on our Beryl Alpha platform, resulting in two weeks of unplanned downtime.

This translated into a 2,600 BOE per day net production hit for the first quarter. Our North Sea team responded quickly and commendably to this incident and managed to keep our production tracking in line with plan.

Subsequent to quarter-end, we logged significant pay at new wells in both the Beryls and Forties areas, and there's a high degree of confidence in our 2015 North Sea production outlook, after adjusting for the sale of our non-op interest in the Scott and Telford fields.

We're excited about our recently processed 700 square mile 3D seismic survey covering the Beryl field complex and adjoining area. This is the first seismic survey conducted over this field since 1997.

From the higher resolution of the extensive data set, a number of interesting features have surfaced in terms of potentially material exploration targets and lower risk in field drilling opportunities. We look forward to testing these later in the year and in 2016.

Since our fourth quarter call back in February, we've received a lot of questions about our inventory work off in 2015 and our projected drilled but uncompleted well inventory going into 2016. Let me quickly provide you a few numbers that may be helpful for modeling purposes.

We entered 2015 with 207 drilled but uncompleted wells at our North American onshore backlog, 80% of which were horizontals. Based on our current plan, we expect to exit 2015 with between 80 and 100 drilled but uncompleted wells, essentially all of which will be horizontals.

I would stress that this assumes that we do not add any additional rigs in the second half of the year. During this period of depressed oil and gas prices, Apache is not standing still. Though, we have reduced our rig count, we continue to move forward on multiple initiatives that will strengthen the company.

I believe these initiatives will help transform our operational and financial results and ultimately drive incremental shareholder value. I mentioned them last quarter and would like to close by reiterating them here again today. We are realigning our North American incentive program to reward continuous improvement and cost discipline.

We are developing detailed medium and longer term field development plans and continue to high grade and build our drilling inventory at multiple price scenarios.

We are continuing to invest heavily in seismic acquisition, processing, and other technical services to provide a more thorough understanding of our acreage and optimize our drilling and completion techniques.

We are focused on quick payout, high return work over and re-completion projects that protect our North American production base, and we're consolidating and enhancing our portfolio through opportunistic acreage additions, where there is less competition and lower prices.

I have confidence in the positive impact of these initiatives and I'm excited about our people, our acreage, and our strategy. Despite the commodity price challenges the entire industry faces, I believe Apache will finish this year as a much stronger company then when we began it.

I will now turn the call over to our new CFO, Steve Riney, who I am very pleased to have on board. He has only been here a few short months, but has already made a significant impact on our organizational capabilities.

Steve?.

a low case of flat $50 WTI; a high case of a rise to $80 WTI, and then flat; and a base case of the five-year strip. Recent oil price volatility reminds us we have little control over the price environment and underscores the importance of being prepared to take any necessary steps to correct our course.

We are redesigning the planning process to significantly improve our visibility into the potential impacts of price movements across the portfolio, so we are prepared to rebalance the activity set accordingly.

Of course, price does not move in a vacuum, and we will take into account that costs move in tandem with prices, and may do so in very different ways for the various pieces of our portfolio. In some places, costs can move very quickly with price movements, potentially providing a natural hedge.

In other places, the cost reaction could move much slower. The capital allocation process is how the plan gets implemented. We have a tremendous variety of opportunities in our global portfolio, and we are working to improve our understanding of how the economics of every element of the portfolio work.

It can be more complicated than it is sometimes portrayed and an appropriate depth of understanding gives confidence that the best opportunities are getting funded, and they are truly adding value for our shareholders. We're also working to establish a strong linkage between the investment economics view of the portfolio and the long-term plan view.

It is not enough to understand the depth of economic opportunities in the portfolio. We need to understand how that depth changes in different price environments. And finally, the various price assumptions in the plan and the corresponding cash flow generation will establish the pace at which the portfolio of opportunities can actually be funded.

So, we have a lot of important work to do, but we are already on our way and we have a plan for taking this forward. Now, let me turn to some of the details of our first quarter results.

John and Gary reviewed our earnings and key operational drivers for the quarter, so I'll make a few comments about our ceiling-test write down, planned use of proceeds from recent asset sales, and our 2015 capital spending outlook. I'll then finish up with some directional guidance for the year on a few other items.

As noted in this morning's press release, we reported an after-tax ceiling-test write down of $4.7 billion or $12.48 per share for the first quarter of 2015. This is a result of the current commodity price environment. Under full cost accounting, our upstream assets are carried at historical cost.

Each quarter, we compare this cost basis to a calculated PV-10 value. To the extent the net book value exceeds the PV-10 valuation, the result is a ceiling-test write down. The ceiling-test employs a methodology prescribed by the SEC, which uses trailing 12-month average oil and gas prices.

The PV-10 calculation assumes these average prices are held flat into perpetuity. The prices for the last two quarters have dramatically reduced our PV-10 calculation. In addition, since today's trailing 12-month prices still reflects several months of higher prices from last year.

If prices do not recover materially, you can expect further impairments during the remainder of 2015. In terms of our planned use of asset divestment proceeds, in April we received $3.7 billion of proceeds from our LNG transaction with Woodside, and approximately $560 million of U.S.

income taxes has become payable as a result of repatriating these funds. Of the remaining $3.1 billion, $2.6 billion were used in April to pay off commercial paper in short-term bank loans, which you will see on the balance sheet at the end of the first quarter.

Around mid-year, we anticipate receiving an additional $2.1 billion, subject to customary post-closing adjustments, upon closing the sale of our remaining Australian oil and gas assets. We plan to use these proceeds in combination of further debt reduction and cash retention.

On page three of our earnings supplement, we provide a net debt reconciliation for the first quarter. On that same page, we present a pro forma view of our actual net debt at March 31 to reflect the asset sale proceeds expected in the second quarter.

With this pro forma view, you'll see that our net debt is less than $7 billion, which is less than two times our projected 2015 EBITDA, assuming $50 WTI and $53 Brent. Turning to capital spending; we continue to anticipate North American CapEx, excluding LNG, to be in a range of $2.1 billion to 2.3 billion.

We have no current intentions to expand the planned activity set in North America during 2015. However, if rising oil prices and continued capital efficiency result in 2015 cash flow significantly above plan levels, this may change, and as John indicated, we'll be prepared to respond.

Our anticipated spending levels in the North Sea and Egypt remain unchanged. As we noted in this morning's press release, we're reducing our full-year international capital budget by $150 million as a result of the pending sale of our remaining oil and gas assets in Australia.

Accordingly, our revised guidance for international and Gulf of Mexico capital spending is between $1.3 billion and $1.6 billion. On the cost side, both LOE and G&A are experiencing downward pressure in 2015. These operating expenses came in at just under $10 per BOE during the first quarter, which is 5% lower than 2014 actuals.

For G&A, as John indicated, with the reduction in the scale of the portfolio and reduced activities around the globe, overhead costs should be coming down and they are being specifically targeted for reductions. Some of this has already been accomplished, but there is more to do.

Following the closing of our Australian sales, we will prevent present a more in-depth view of our cost-cutting efforts, especially in the area of G&A spend. Interest expense for the year is projected to be around $460 million. Approximately 50% to 60% of this will be capitalized.

On the tax side, we anticipate our effective tax rate on adjusted earnings in 2015 will be between 25% and 30%. Note that this does not include the one-off benefit in deferred taxes for the recently enacted UK tax rate change, which we expect to be a little over $600 million.

Operationally, you'll see on page two of the first quarter earnings supplement, our North America onshore production guidance is unchanged and is expected to be relatively flat compared to 2014.

You'll also see in the earnings supplement that we have updated our pro forma production guidance for the Gulf of Mexico and international operations to be slightly up from 2014. Please note this guidance now excludes Australia production volumes entirely. I'd like to close by echoing what John said in his remarks.

Our goal for the remainder of 2015 is to maintain a strong balance sheet, to live within our cash flow, and to prepare the organization for an efficient ramp up in activity, when the cash flows dictate.

We will also continue to be opportunistic, but highly disciplined in evaluating new opportunities that may unfold in this challenging price environment. I am very excited to be a part of the Apache team, and I look forward to meeting with many of you down the road. I will now turn the call over to the operator to begin Q&A..

We'll pause for just a moment to compile the Q&A roster. The first question will come from Doug Leggate with Bank of America..

Thank you. Good afternoon, everybody. John, I wonder if I could take the activity step-up question, if I may, and it's not so much about – you've laid out what oil price, I think, you would start to go back to work, but you still have a fairly intricate portfolio. You've got a lot of opportunities.

How would you think about the incremental allocation of capital? For example, you're running more rigs in the Eagle Ford right now, but if you did go back to work, what would be the first call on spending? And I've got a follow-up on the international, please..

Okay. Well, Doug, thank you. We have actually worked hard to be in this position to get our activity levels adjusted and obviously address the cost structure. So, it puts us in the position now where we can be opportunistic. Obviously, prices on the strip right are now running ahead of where we planned, so it puts us in a position to make some choices.

The first and easiest thing, obviously, to do would be to put a couple of frack crews in and recomplete some of our drilled but uncompleted wells, but we want to be very prudent, we want to be opportunistic, we're starting to see some acreage things that pop up that might be very additive to long-term shareholder value, so, Doug, we want to be very prudent, because we worked hard to get into this position, and want to kind of monitor that as the second half of the year unfolds.

We're working through a detailed planning process right now, as Steve lined out, with three price scenarios, and one at $50 flat on the low side, the other one at $80 bracketed, and then the strip, and so that will help us give some guidance in terms of those directions.

Clearly, when I look at the portfolio, the Delaware Basin is an area, and the Permian is an area that we can go in quickly with cash flow in terms of additional activity as we plan to run quite a few more rigs there. And then also both the Canyon Lime and the Eagle Ford at higher prices, we'd scale in there.

But, we've got lots of opportunity in front of us, and we want to be opportunistic and very careful on where we go forward..

Just to qualify, John, is the backlog concentrated in one particular area? Or is it pretty much spread around?.

It's spread around. The lion's share that we mentioned, we came into the year with 207, and 80% of it was horizontal. We will work off the vertical backlog, which was predominantly in the Permian, by year-end. And we said, we'd come in – exit right now, our plan would be to exit the year with between 80 and the 100 uncompleted wells.

A big chunk of those will remain in the Permian, and obviously we've got some in the Eagle Ford and then the other areas..

Okay. My follow-up, John, is on the North Sea. Obviously, you had some interruptions this quarter, but in the absence of exploration success, what is the production prognosis for the North Sea? And maybe if you could just frame into that how you see your backlog of opportunities to hold production flat? I'll leave it there. Thank you..

Well, we're very excited about what we've been able to accomplish in the North Sea. We're coming off of a Q4 record high for us of over 80,000 BOEs a day. We've got a deep inventory there. As part of our capital reductions, we did scale back in the North Sea as well. We've got over 200 identified prospects and locations. We've got deep inventory.

And for the year, Doug, from where we are right now, we would envision it being relatively flat on a go-forward basis..

Okay. Thanks a lot. I'll leave it there, John..

The next question will come from David Tameron with Wells Fargo..

Good morning, John. I guess afternoon.

What's changed as far as the Delaware? Can you just give a little more detail what you're seeing, why you're getting more aggressive there, and why is the remainder of the Permian program going to be focused there?.

Well, we'll be focused in two areas. Obviously, the Delaware, even if you go back to our November update, we're planning to run four to five rigs there. That's where we were maintained today, and honestly, right now the economics there are just slightly higher. We've also got some testing we're doing there, which we think can be differential.

Right now, we've only brought on two wells this year. We plan to drill another, or actually complete another 28 wells for the rest of the year. So, we're excited about our position there, and we see lots of opportunity. But, we will also be active in the Midland Basin as well as our Central Basin Platform.

About half of our Permian rigs will be in the Delaware and the other half are going to be spread out. But, we're moving into the Midland County, Southern Midland Basin area, our Wildfire area, Powell, Miller. We're excited about those.

We'll actually be doing a Spraberry test later this year in the Wildfire area, and we've also been drilling great wells on the Central Basin Platform. So, it's just part of our portfolio, and right now the economics over there are slightly better than they'd be in the other areas. But, we're excited about all the areas..

Okay. And just as a follow-up, if I think about the Delaware, it looks like the couple of wells that you highlighted during the quarter in the supplement were in the third Bone spring.

Can you give us any color as to where you plan to focus – those four rigs? Is there any zone in particular standing out? Can give us any color on that?.

Well, it really depends on the area. If you look at our Pecos Bend area, where the two Condor wells are, we drilled 31 wells to-date. 21 of those have been in the third Bone springs. We've had six in the Wolfcamp and four in the second Bone springs.

Right now, we're kind of dialed in on the third Bone springs, and there's a couple landing zones in there. You move into the other areas, and that's the nice thing about the Delaware is you've got multiple targets, anywhere from the Avalon to the first, second, or third Bone springs or down to the Wolfcamp and some other zones.

So, the nice thing is it kind of depends on the area you're in, but with where those rigs are focused..

All right. Thanks..

The next question will come from Leo Mariani with RBC Capital Markets..

Hey. You guys came out in your prepared comments and talked about having a position at 50,000 acres, kind of in the Woodford Springer area. I'm just trying to get a sense if this was a legacy position in the portfolio or something that you guys leased recently.

And maybe if you can just provide a little bit more color regarding your comments about some leasing opportunities that have been picking up here?.

Well, I'll start out with the Woodford. It is predominantly legacy acreage. Last year, we did sprinkle in some sections around there. And we have been blocking that up as we have been most of our key core areas. Currently we've got one well, the Ellis 14-4-6 number 1Hs, it's right now on completion.

We've got two rigs out there and we're drilling two wells, the Ellis 14 number 2H and the Truman well. So we've got three wells we'll be bringing on in the very near future. We're very excited about the rates. We've got about 200,000 acres there gross and about 50,000 net, and it's a nice little position that can be very material for us.

In general, obviously, we're seeing some opportunities in all of our core areas. And that where we're busy trying to core up acreage, prep things, and be prepared for when we allocate more capital to some of the high-value areas..

All right. And I guess you guys obviously spoke about some really nice cost reductions here that you've seen here recently on your wells. And a lot of that was focused in the Permian with some of the costs coming down.

I wanted to get a sense if you guys are also not only seeing cost reductions, but are you seeing improvements in the wells, just better efficiency as you guys tweak frac design, and you're seeing the wells in the Permian get better here of late.

Maybe you can speak to that?.

Yeah, I mean, the first thing is we did a very detailed dive on the EURs in the plays in November. And since that time, we've brought on some wells, but not many. You look at the Delaware, we brought on two wells. They are outperforming our type curve, so we're doing some things there technically which we think can improve those.

But with two wells on, they've only been on 60 days, I'm not in a position right now to be updating type curves. And the same is pretty much true in our other areas. Our Canyon Lime wells are coming on relative to type curves. In the Eagle Ford, we've got some slightly above, some under. So, we feel really good about those areas.

We are seeing cost, we've kind of dialed in 10% to 15% on the last call when we talked about the plan for 2015. Clearly, we said that they're going to range from 20% to 40% right now. We're seeing on average about 25%. A lot of that's attributable to the service side.

But, a lot of it's just more people now focused on ways to drive cost out and doing a better job planning our wells. And clearly, if prices remain where they are, we're going to see costs further align and come down for the rest of 2015..

I guess, previously you folks had spoken in the past, predominantly last year, about separating North American business from the rest of the international properties. I just wanted to see, if there's any kind of status update on that or if you've got kind of a new way of thinking about any type of separation of the business lines..

Well, we addressed that on the first quarter call. But the key objectives with us on our international portfolio were two. One, unload our LNG, which we have done, signed, closed. And then we announced the sale of Australia. I think that leaves us with a portfolio now that we plan to stick with, we're excited to have. We're 60% to 70% North America.

If you look at our North Sea and our Egypt operations, we've got world-class people there as well as leading positions. And the nice thing about both the international assets, they complement our North American portfolio, they're Brent pricing.

And the other thing is the way the PSCs and the tax regimes work, you've actually got less sensitivity to lower oil prices in terms of after tax cash flow.

So, going forward, we're going to, as we work through our planning process, we're working through North America, we're also working through Egypt and the North Sea, and we will be outlining longer-term plans. But, we're very happy with the portfolio as it stands today..

Thank you very much..

The next question will come from Bob Brackett with Bernstein Research..

Good afternoon. Question on that impairment, the $4.7 billion.

Can you give some detail what assets were involved there?.

Yeah, Bob. So, the primary assets that were involved there were the U.S., Canada and the North Sea. There was about a $7.2 billion gross impairment. You'll see in the 10-Q, it'll be released later today, that $5.2 billion of that was in the U.S., $1.4 billion of that was in Canada, and about $600 million of that was in the North Sea.

All of that's on a pre-tax basis..

Okay. And the U.S.

assets how would those split?.

Yeah, we're not providing a breakdown of that into the U.S..

Okay.

And then a follow-up, on the net proceeds, what's the ultimate use of those net proceeds that you've collected from Australia?.

So, we collected $3.7 billion pre-tax proceeds. We've got about a $600 million tax liability that will get paid later this year, so the $3.1 billion net, $2.6 billion of that went in the month of April to pay down the debt, the short-term debt that existed on the balance sheet at the end of 1Q.

The $2.1 billion that will be coming in sometime right around midyear for the second Australia transaction, that $2.1 billion will be used as a combination of debt pay down and some cash retention. We haven't decided exactly the ratio of that yet, but I would say the majority of that will be going to debt pay down..

Okay. Thank you..

The next question will come from Arun Jayaram from Credit Suisse..

Good afternoon, John and Steve. My first question regards the new planning process that's under way. I think you articulated maybe three different pricing scenarios that you would look at.

I was just wondering if you could give us a sense of when this planning process is completed, what will be – will there be a new set of targets that you'll communicate to the Street, and could this potentially impact your views on 2015 production and capital?.

Yeah, Arun, at this point we're working through that. Obviously, we've got early looks, but we're taking a really deep dive at the portfolio and one of the keys is, it's an iterative process as you have to try to really synchronize cost with price environment for each of those.

So, what we're really trying to do is put some sidebars on the world we'll be operating in as we start to take a longer-term view. I don't envision anything impacting 2015 from where we sit today for how we budgeted it.

And so, we feel good about where we are, but we'll be working through that, and over the next several months we'll get to where we have an internal view as we start to think about how we react going into 2016..

Great. Great. Obviously, John, the balance sheet is in a different place, or will be once you complete the transactions. You commented in the press release about potentially being opportunistic yet disciplined.

Historically, Apache has been a counter-cyclical investor, so where is your head at in thinking about potential acquisitions, and would you be focused in on your core area, or look for new areas?.

Well, Arun, where my head is right now is delivering value for the shareholders and trying to maximize that. And I think we have positioned ourselves very nicely.

The nice thing is we have high-quality assets and deep inventory, but we also are always opportunistic and always in looking at opportunities, so if there was something that we thought made sense and incrementally might add value, then we might be willing to move forward on it.

But, in general, we're happy with our asset base and we're going to be very selective, but clearly we're in a position where we have a lot of flexibility, and you'd never know what might present itself..

Okay.

Just my final question, as you think about capital allocation to the Permian this year, could you give us a sense of what percentage of your CapEx, perhaps ballpark, is going for Midland versus Delaware and how that could shift over time given your comments on the Delaware today?.

Well, I mean, when we look at where we sit right now, kind of like even like what we lined out in November, about 60% of our CapEx on North America is in the Permian. When you look at what we've done with the price environment, we've slowed down much more so than we had planned in the Eagle Ford and the Canyon Lime, and even Canada.

So, for the bulk of the year, the majority of our capital is going to be going into the Permian. I would say that in terms of, if we were to add incrementally, the Southern Midland Basin would be an area we've got the best – most flexibility and things ready to drill that we could move quicker on.

We had kind of planned even in higher capital and prices to run the number of rigs we're running in the Delaware. So, we like our pace right there given our asset base, so I would say incrementally we'd probably add first in the Delaware or we might choose to accelerate in the Delaware or add in the Midland Basin..

Okay. Thanks a lot, John..

The next question will come from Charles Meade with Johnson Rice..

Good afternoon, John, and to the rest of your team there. If I could ask a question about those Wildfire wells that you just mentioned in your operations report. Presumably, if you were ready to share already you would have put it in there.

But, you did I believe say that the early flow back was very favorable on those four wells, so I wonder if you could perhaps condition us a bit on – give us a background on, did you batch drill and batch complete those four wells? Did they just come on in the last week or so, and what is it? Is it the total fluid volume that's being moved that has you feeling it's favorable?.

Well, Charles, what I'll say is, I'll go ahead and give a little bit of color. We've got four, roughly 7,500 foot Wolfcamp B wells that are in what we call the Lynch Unit. All four wells were completed in late March.

We've got all of them on in less than three weeks, so we're not ready to talk about 30-day rates, they're going to be second quarter wells. But they've been encouraging. In general, we've had an average kind of peak IP of around 1,400 BOEs a day, they're 70% to 80% oil. So, we're very excited about them, and we're flowing them back very conservatively.

So, we're very, very encouraged. Additionally, we've got about three wells there, we'll drill in 2015 and delineate and optimize and test our fracs, and then it sets us up for quite a drilling program there going forward when we decided to scale up.

We also plan to test a Spraberry shale well there, probably in the third or fourth quarter of this year..

Got it. Got it. That's great additional detail, John. And then, if I could ask another question. This goes back to the drilled uncompleted count that you expect to have at year-end 2015. I think you said it was 80 to 100.

Perhaps you could tell me, if I'm thinking about this the right way, but if you're running 15 rigs, and just to make the math easy, let's say, your average drill time or drill and complete time is – I guess spud to rig release would be the appropriate thing, is 30-days, that would imply kind of a six-month backlog there.

And if you cut it in half and say, okay, well our spud to rig release is 15 days, it gets down to about a three-month backlog.

So, both of those seem sort of high to me, and it makes me wonder if you plan to continue to work down that backlog as you go into 2016, and could you tell me, is that the right way to look at that?.

Well, what I'll say is, what it tells you is we're going to carry. We're not just aggressively moving through our backlog. And that's a function of cash flow and being very disciplined. Clearly, we could go complete a lot of wells today, if we wanted to. We're going to take a very measured approach.

We're being very careful with how we allocate our capital and how we handle it this year, but it puts us in a position where we will enter 2016 with a lot of flexibility, just like we entered 2015..

Got it. That's what I was after. Thanks a lot, John..

The next question will come from Paul Sankey with Wolfe Research..

Hi. Good afternoon, everybody. I was just wondering, you've talked about cost improvement and performance improvement.

Around these oil prices, with this level of spending, where would you anticipate your volumes to be growing or not growing in 2016? And is there a price of oil that you can share with us, where you feel that if we saw that price, you would start to reaccelerate the activity? Thanks..

Well, good questions, Paul. What I'd say is, number one, it's cash flow for us that matters. I don't worry as much about oil price. What I'll say is, we're taking a very hard look right now and going through a very rigorous planning process, which kind of brackets some scenarios.

And we're looking at a range, which we would mirror – kind of mirror the cost structure to those oil prices and look at that. So, as we get further into the year, into the next quarter, and we get closer to 2016 and things crystallize, we'll start to be more candid on where we are for 2016..

Right.

So, I was just wondering if we could get a sense, given the way performance is improving, let's say for example, you held your CapEx at these levels, how would you anticipate your performance in volumes to be next year?.

What I'll say is, clearly, if we're in a low price environment, capital in 2016's going to go further than it went in 2015, because costs are going to be lower, we're seeing efficiencies. Additionally, with the G&A reductions and things we're targeting, we will be able to put more dollars in.

So, through the efficiencies and that sort of thing, it's going to take less in 2016 to deliver than we have in 2015, but beyond that, we're working through a rigorous process, we're going to stay committed to bracketing kind of the environment we're in and then communicating that at a later date..

Understood. I can kind of sense that you're in the process, so it's hard to talk about, but I'll just try one more. Could you just put some numbers around the cost savings that you've achieved, and maybe where you think we may be by the end of the year? And I'll leave it there, thanks..

Well, we outlined in February a 15% reductions from our November levels on our well-by-well basis. If you look at it today, I've said today we'd be at least 25%. So, the one thing is we came into the 2015 hot.

We spent a lot of our capital, so if you look at our go-forward capital for 2015, we're seeing down 25% on average from the levels that we had in November 20..

Okay.

And you think there's more to come?.

Absolutely..

All right. Thanks..

The next question will come from Pearce Hammond with Simmons & Co..

Yeah. Good afternoon, John. Thank you for taking my questions.

John, just following up on Paul's question there, just to clarify, so if you were to hold CapEx flat in 2016 versus 2015, in North America, do you think you'd be able to grow production?.

Pearce, we're early. I don't want to give you overall numbers, because we're working through planning. I'm just – my point was, if I hold CapEx flat, I'm going to get more out of it in 2016 than I got out of it in 2015..

Okay. Great. And then on Egypt, it seems like the political environment has become more stable. You had some – the permits that you got on the concessions were faster, it looked like, this most recent round.

Is the arrow pointed up in Egypt? And if so, could you end up allocating more capital there?.

Yeah, I think clearly the investment area there is improving, and if you go back, even though the Arab Spring, we've never skipped a beat. So, it's in general, the investment has always been good for us.

We've got a great relationship with the Egyptian government, and we did set record times and bring in Ptah and Berenice on, but we've been that way in the past. So, lot of advantages.

It's, clearly the sentiment is turning, and like the rest of our business we're excited about it, and that's one of the options we'll have on the table as we start to think about if we have incremental cash flow, where would we put it..

The next question will come from James Sullivan with Alembic Global Advisors..

Hey, good afternoon, folks. I just want to go back for a second to the Condor wells in the Delaware.

Just want to see – the 30-day IP you gave of those was not, is not normalized for lateral and the short lateral length, is that right?.

That is correct..

Okay. Great. So, that's a good number. Just to follow-up on that, your position out in the Delaware seems to consist more of the smaller lease configurations. What is the appetite? You guys have talked about bolt-ons and leasehold.

What's your appetite or can you describe the environment for trying to block up your acreage? Obviously, I'm sure there's always appetite to do it, but with firming up in prices are the bid asks just too tough, and would you migrate over the river into Reeves to try to do that, and where you might get a better pricing?.

Well, I mean, I think we're obviously very high in the Delaware. We've got lots of room to build off of, and we've got inventory for many years on our existing acreage position. It's one of the areas that clearly that if we felt like we could add something at attractive prices that we'd look at..

Okay. Sounds good. Just to go to the international piece. Obviously, since you guys are thinking about the North Sea and Egypt as a retained part of the portfolio, could you just remind me, this is probably something I should know, but could you just tell me what the challenges are associated with the cycling that free cash flow back to the U.S.

under kind of a normal retained asset accounting? I know that those should be free cash flowing generally, if you think about a normalized price environment, so the idea that feeding the U.S.

will be a positive thing, but just want to see what the tax implications would be of that?.

Yeah, James. We don't see any significant issues with cycling cash back to the U.S. now, especially with eliminating the election to permanently reinvest earnings overseas, and we'll be able to do that with a significant amount of foreign tax credits as well going forward..

The next question will come from Jeffrey Campbell with Tuohy Brothers Investment Research..

Howdy?.

Hi, Jim..

Hi, John, I wanted to ask you first a broad question, and then a specific one. You mentioned a couple of times on the call today that $65 a barrel was an encouraging number, let's say.

I'm just wondering, do we mean that you're looking at it as something that you have an ability to hedge at $65, or do you have a certain amount of time you want to see stability around $65 a barrel, before you begin to start pulling levers?.

What I would say is right now, we're not hedged. Our best hedge is our activity levels, which we are able to mirror. Clearly, we would look at – hedging is a tool that we could use before we started to make some longer-term commitments in terms of activity levels as we went into these plays.

The point is, for the Canyon Lime and the Eagle Ford, when you get into the $60 to $65 range, that's an area where they become very attractive for us to put capital back to work. But as I said in my prepared notes, they'd have to compete with the other opportunity set..

Right. And the other question I wanted to ask was about the Eagle Ford itself. I think you gave a little bit more color, or at least maybe I noticed it this time, a little more color and complexity in the play. Now you've got a lot of 3D seismic covers.

And I also remember last quarter, you said sometimes it's not such a bad thing to be forced to slow down a little bit.

And I'm wondering if the path forward here for a little while is to use this 3D, to try to figure out the better places to not only – better ways to complete your wells, but maybe even thinking about better places to drill preparatory to the time when you return rigs there?.

Well, actually, would you look at the Eagle Ford, we're dealing with four phases across our acreage position. We've got black oil, we've got volatile oil, we've got wet gas, and we've got obviously dry gas, which we're not obviously focused on.

As you look across those three areas, you've got 38 wells to complete, Jeff, 17 in Area A, as we lined out back in November and 21 in Area B. We've been focused on our cost side. I think we have made significant progress on the drilling side. So, it's just optimizing completions and working on improving the economics.

So, we'll be working on that and providing updates later in the year..

The final question will come from Michael Rowe with Tudor, Pickering..

Thanks for squeezing me in here. I just had one quick question on the Permian.

Can you talk a little bit more about the growth in oil volumes for the rest of the year, while gas stays flat? Is that a function of the weather impact reversing itself here, or is it that you're leading on your completion backlog? How should we think about the growth there in oil, with the reduced capital spending?.

Well, there's two things. Number one, obviously, from where we are first quarter, we did have weather impacts. So, there's a piece of that. The other thing is, though, we only brought on two Delaware Basin wells. So, we've got pretty good inventory ahead of us. In fact, if you go back to our Q4, we did not bring on a lot.

So, we're sitting with some nice things coming on and as you get into the second quarter and into the summer months, we've got some key pads and some things we'll be bringing on which are going to help drive the liquids in the Permian coming forward. So, we've just got a lot of our stuff in front of us.

We've moved into the Southern Midland Basin Wolfcamp, so we've got a lot of exciting things to bring on, even at the reduced activity levels in the Permian. And then I can't underscore our base decline.

We've got 25%, 26% across North America, and a nice thing about us relative to our peers is having a big Central Basin Platform position where our decline rates and the water floods, we've got 45 water floods, we've got seven CO2 floods, having a lot of that low decline base really helps in terms of our volumes out there..

That's helpful. Appreciate the detail there, and then one quick question on the North Sea. Was curious about the 3D seismic survey that you're doing there at the Beryl field, because you're working on some drilling plans. And subject to more capital availability, you would maybe consider drilling some more wells there.

Does that savings of $150 million from selling Australia, does that kind of give you the capital availability to potentially put a few more North Sea wells in the 2015 program, or is that more planning for 2016 drilling?.

I would say we've got a plan right now. We've got brand-new 3D there which we're excited about. The 150 comes out of Australia reductions. So clearly, anything we decide to add anywhere is going to be a function of future generation off our existing base. But, there is opportunity in the North Sea.

We've got some exciting things we will be testing later this year and well into 2016 and beyond. So, it gets back to the depth and the opportunity to generate value over the long haul.

The thing I would add about the North Sea that's differential for us is in both of our big complexes, we have made significant investments in our infrastructure that pushes our abandonment timeframe way out into the 2030 range. And we've spent over $1 billion at Forties, which gives us long, long runway there.

And the same thing at Beryls, we've spent $300 million there over the last few years, which gives us lots of runway in time, and we're very excited about the opportunity set..

Ladies and gentlemen, this concludes today's conference call. You may now disconnect..