Gary T. Clark - Vice President-Investor Relations John J. Christmann - President, Chief Executive Officer & Director Stephen J. Riney - Chief Financial Officer & Executive Vice President Timothy J. Sullivan - Executive Vice President – Operations Support.

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) David R. Tameron - Wells Fargo Securities LLC Pearce Hammond - Piper Jaffray & Co. (Broker) Evan Calio - Morgan Stanley & Co. LLC John P.

Herrlin - SG Americas Securities LLC Arun Jayaram - JPMorgan Securities LLC Scott Hanold - RBC Capital Markets LLC Doug Leggate - Bank of America Merrill Lynch John A. Freeman - Raymond James & Associates, Inc. Paul Sankey - Wolfe Research LLC Charles A. Meade - Johnson Rice & Co. LLC Michael Anthony Hall - Heikkinen Energy Advisors LLC Michael J.

Rowe - Tudor, Pickering, Holt & Co. Securities, Inc. Richard Merlin Tullis - Capital One Securities, Inc..

Good afternoon. My name is Regina and I will be your conference operator today. At this time I would like to welcome everyone to the Apache Corporation First Quarter 2016 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

I would now like to turn the conference over to Mr. Gary Clark, Vice President of Investor Relations. Sir, you may begin..

Good afternoon, and thank you for joining us on Apache Corp.'s First Quarter 2016 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 us in the room is Tim Sullivan, Executive Vice President of Operations.

In conjunction with this morning's press release, I hope you have had the opportunity to review our quarterly earnings supplement, which summarizes key financial and operational data for the first quarter, along with details regarding our updated 2016 production outlook.

Our earnings release and quarterly earnings supplement can be found on our website at www.apachecorp.com/financials-reporting.aspx. I would like to remind everyone that today's discussions will contain forward-looking estimates and assumptions based on our current views and reasonable expectations.

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

Thank you, Gary. Good afternoon, and thank you for joining us. In the first quarter, Apache delivered solid operational results, strong financial performance, and notable drilling outcomes, all of which were supported by our relentless focus on continuous improvement and cost reductions.

Today I would like to start with a brief recap of first quarter results, and an update to Apaches 2016 production guidance. I will then provide an operational overview with particular emphasis on some of the exceptional well-cost reductions we are achieving at our key North American onshore plays.

I will conclude with thoughts on our current activity level and the potential for increasing capital investment in the near future. As noted in this morning's press release, companywide, pro forma production of 479,000 barrels of oil equivalent per day was at the high end of our quarterly guidance range of 470,000 BOEs to 480,000 BOEs per day.

Outperformance came primarily from North America onshore, which produced 298,000 barrels of oil equivalent per day and exceeded our 290,000 to 295,000 BOE per day guidance range. Each of Apache's North American operating areas performed well, despite a significant reduction in capital.

The Permian in particular delivered robust results with strong performance from the underlying base, coupled with solid contributions from both newly drilled wells and base maintenance projects.

In light of first quarter production strength, we are raising our full-year 2016 North American onshore guidance range by 5,000 BOEs per day, to 268,000 BOEs to 278,000 BOEs per day.

On the international and offshore side, pro forma production was 180,000 BOEs per day, which was at the low end of our guidance range of 180,000 BOEs to 185,000 BOEs per day. This is primarily attributable to unplanned third party plant and pipeline outages in the North Sea.

We remain on track to achieve our full-year 2016 international and offshore guidance of 170,000 BOEs to 180,000 BOEs per day. As we have stated previously, our 2016 North American onshore drilling program is primarily focused on strategic testing and acreage delineation to build and high-grade inventory.

Nevertheless, we are continuing to see some remarkable progress on drilling efficiencies. For example, in key areas of North America, where Apache was actively drilling during the first quarter, the average drilled and completed well costs were down approximately 45%, as compared to average well costs in 2014.

On the expense side, continuing with our efforts from last year, we saw further reductions in both lease operating expenses and gross G&A. Looking ahead, we anticipate further benefits from aligning our cost with the scale of our business and the commodity price environment.

As you will recall, Apache is targeting cash flow neutrality in 2016 under our current budget, which assumes flat $35 oil and $2.35 gas. As expected, we were not cash flow neutral in the first quarter; however, we do anticipate generating a net cash flow surplus through the remainder of the year.

As such, we remain on track for unchanged or lower net debt levels at year end. Steve Riney will elaborate further on this in his prepared remarks. With the recent improvements in strip oil prices, we are prepared to increase capital spending but will refrain until we are confident cash flows have sustainably improved relative to our 2016 plan.

Although we have the financial capacity to increase capital spending today, we believe that preserving our strong financial position and our credit quality through cash flow neutrality is the best approach for our shareholders in this price environment. I will provide more color on our thinking around this in a few minutes.

Turning to our operations, in the Permian Basin, first quarter production held up well despite a significant decrease in the number of wells placed on production. We produced 171,000 BOE per day, which represents a 2% sequential decrease from the fourth quarter.

In the Delaware, we placed five gross operated wells on production, primarily targeting Bone Spring formations in the Pecos Bend area. One very notable well, the Seagull 103-HR, produced an exceptional 30-day average peak rate of nearly 2,800 barrels of oil equivalent per day from a lateral length of approximately 4,600 feet.

In its first 60 days of production, the Seagull 103-HR accumulated 78,000 barrels of oil, which makes it Apache's best well to date in the Delaware Basin. The success of the Seagull 103-HR is a function of our thorough understanding of the hydrocarbon system and continuous efforts to improve our results of these complex reservoirs.

Thus far, our efforts in the Pecos Bend area of the Delaware have been focused on two primary landing zones in the Third Bone Spring formation. During the first quarter, we tested a promising new landing zone within the Third Bone Spring that could significantly enhance our running room in the area.

In the Midland Basin, Central Basin Platform, and Northwest Shelf, we placed 25 gross operated wells on production, which is approximately 40% fewer wells than in the fourth quarter.

During the first quarter, Apache generated good results from six Wolfcamp wells in the Powell area, two Wolfcamp completions at Wildfire, and four horizontal Yeso wells on the Northwest Shelf, all of which are summarized in our quarterly earnings supplement.

Before moving on to Egypt and the North Sea, I would like to highlight our North American well cost reduction efforts, which continue to exceed our expectations. Last quarter, I noted that we have dedicated a considerable amount of time, energy and resources toward reinvigorating Apache's strong culture of cost and returns discipline.

This quarter, we are seeing some very tangible results from these initiatives which I would like to share with you. As I mentioned earlier, in key areas of North America where Apache was actively drilling, our average drilled and completed well costs were down approximately 45% in the first quarter compared to average 2014 levels.

Notably in the Delaware Basin, our most recent well costs are now down approximately 60%. Although we have made great strides throughout 2015, I am truly amazed by the ongoing positive cost trends in our North American onshore drilling program. Six quarters into the downturn, we are still achieving significant quarter-on-quarter cost improvements.

For example, in the Delaware Basin, we recently drilled and completed a Third Bone Spring well for $3.5 million. In the Midland Basin, one mile horizontal Wolfcamp and one-and-a-half mile Lower Spraberry drilling and completion costs are now projected to be less than $4 million and $4.5 million, respectively.

In the horizontal Yeso play on the Northwest Shelf in the Permian, recent well costs are trending below $2.3 million. And in the Woodford SCOOP, our latest pacesetter well was drilled and completed for only $6.6 million.

Achieving these lower well costs both expands our drillable inventory and significantly enhances our returns for future development programs. Recently, we received questions about the sustainability of our well cost improvements once demand for oilfield services begins to rebound.

The high level answer is that more than 50% of our average well cost decrease since the 2014 peak has come from design and efficiency improvements and should therefore be viewed as permanent cost savings.

In our earnings supplement this quarter, we have provided exhibits for our key North American onshore plays that highlight the breakdown between service price and efficiency improvements. Apache's cost achievements to date are more than just belt tightening efforts in response to the downturn.

We seek to continuously implement structural changes and improvements which accrue to the bottom line and enhance our long term returns regardless of where oil prices and services costs go in the future.

Now turning to our International operations, in the North Sea, first quarter production was slightly above 70,000 barrels of oil equivalent per day, which represents a 2% decline sequentially from the fourth quarter of 2015.

Unplanned downtime associated with outages on the third-party operated Forties Pipeline system negatively impacted our sales volumes by approximately 1,700 BOEs per day during the quarter. These outages reduced our production uptime from what would have been 94% down to 90%. As a reminder, U.K.

North Sea industry average production uptime has been between 60% and 70% over the last several years. Therefore, Apache maintains a significant competitive advantage in this regard. Despite the higher-than-expected downtime during the quarter, Apache still achieved exceptional LOE costs of approximately $11 per BOE.

Our first quarter development drilling program in the North Sea delivered four successful new wells, all of which were placed online in the second half of the quarter. This set up a strong production rebound during the month of April.

The nature of North Sea operations and production is such that there will always be monthly and quarterly lumpiness, but we are confident in our full year 2016 production guidance which we stated would decline slightly year-over-year from 2015 levels.

Our subsea tieback of the Kaliter (11:46) discovery is proceeding on time and on budget, and we continue to expect this project will begin production in mid-2017. We are also looking forward to drilling our Storr and Kinord exploration prospects, which we highlighted in our North Sea webcast last November.

In Egypt, our gross production of approximately 353,000 barrels of oil equivalent per day was essentially flat with the fourth quarter. Steve will provide more color on Egypt production reporting in a few minutes, but excluding tax barrels and minority interests, pro forma production in Egypt was up slightly versus the fourth quarter.

Apache's drilling program in Egypt continues to deliver successful and reliable results. We placed 23 wells on production during the first quarter and achieved a drilling success rate of 88%, which is in line with our historical success rates in Egypt.

At our prolific Ptah and Berenice fields, we placed two more wells on production, bringing the total number of producing wells in the complex to 13. We have a few additional locations remaining to fully develop Ptah and Berenice, but facilities are currently constrained.

Before I move on, I would like to leave you with a few high-level observations on Egypt. Apache's operation in Egypt remains stable. Our drilling, workover and water flood programs continue to deliver quarter after quarter. When compared to North America, our well costs are relatively low and our netbacks and margins are relatively high.

And lastly, cash flow generation in Egypt demonstrates much less price-related volatility than North America, despite reported net production volatility from quarter-to-quarter.

As we all contemplate the timing and magnitude of an oil price recovery, I want to leave you with a few key points around our thinking with regard to 2016 capital spending and the potential for incremental activity above our current plan. Cash flow is the governor on Apache's capital spending and activity levels in 2016.

We still plan to manage to cash flow neutrality and exit the year with unchanged or lower net debt levels. We entered 2016 with an industry cost structure that was still out of sync with the low oil price environment.

The recent rally in oil prices coupled with our cost reductions means that development drilling in North America is now generating acceptable returns in many areas. We believe these returns will continue to improve as costs come into better alignment with price. Recent improvements in oil prices are encouraging.

We are now looking for a sustainably improved pricing structure that would generate the cash flow visibility for us to confidently increase our capital program. The potential timing and magnitude of this increase is the topic of significant planning and discussion right now at Apache and with our board.

In the meantime, the vast majority of Apache's North America and onshore spending is focused on target testing, acreage evaluation and expanding our low-cost inventory locations to be exploited in an environment that offers higher returns.

When the time is appropriate, our first priorities for increased investment will be to add development rigs in the Permian. We will also accelerate North American acreage testing, and we'll keep our two platform rigs running in the North Sea. Beyond that, the Woodford SCOOP play and Egypt are next in line for incremental capital.

Importantly, Apache has maintained the organizational capacity and personnel to operate a significantly higher number of rigs and we are well prepared to ramp-up activity when appropriate. Lastly, we are very mindful of the fact that we are in a highly cyclical and highly capital-intensive business.

As such, any ramp in investment activity will pass rigorous hurdles on returns and net present value. In closing, Apache's portfolio and capital allocation approach is designed to withstand volatility over the long term, which is evident in our results.

We look forward to demonstrating the capability of our North American assets and efficiency of our capital allocation process in the next upturn.

I want to reiterate what I stated on last quarter's earnings call; our plan is to emerge from this commodity price downturn with top-tier financial strength, a robust inventory of high rate of return drilling opportunities and a sustained capacity to generate free cash flow from our international assets in Egypt and the North Sea.

We have made great progress in these efforts. Over the long term, our goal is to offer competitive debt adjusted per-share production, reserve and cash flow growth rates and to achieve a top quartile cost position in terms of average well cost, G&A, and LOE per BOE.

We will accomplish this with an intense focus on long term, full-cycle returns for our investment programs. Through the cycle, we believe this will translate into significantly improved returns and an appreciation in our share price. I will now turn the call over to Steve Riney..

Thank you, John, and good afternoon. In addition to reviewing our financial results for the first quarter of 2016, I would like to highlight our progress on several key financial objectives.

These include continuing to aggressively drive down well costs, lease operating expense and G&A, achieving cash flow neutrality, inclusive of dividends under a flat $35 oil price, protecting our strong liquidity and financial position, and ending the year with unchanged or reduced net debt.

Additionally, I will speak to our 2016 outlook for capital spending, LOE and G&A. And finally, I would like to review Egypt production volume reporting to address some potential confusion about the difference between reported volumes and the pro forma volumes we typically reference. So let's begin with the first quarter financial results.

As noted in our press release, under Generally Accepted Accounting Principles, Apache reported a loss of $489 million, or $1.29 per common share.

Our results for the quarter include a number of items outside of our core earnings that are typically excluded by the investment community in published earnings estimates, the most significant of which are ceiling test write downs.

These items total $337 million after tax, in the first quarter and as in prior periods, resulted primarily from the continued low commodity price environment. Our loss for the quarter adjusted for these items, was $152 million, or $0.40 per share.

As John mentioned, better than expected onshore North American production and solid operating cost performance worldwide, were key contributors to our first quarter, 2016 financial results.

Apache's continuing focus on driving cost efficiencies resulted in capital spending of $466 million during the first quarter, which excludes non-controlling interest. This is well below our guidance range of $500 million to $550 million. Capital costs in all of our North American regions were lower than we budgeted, with Permian leading the way.

Our capital spending guidance of $1.4 billion to $1.8 billion for the full year of 2016 remains unchanged. We are clearly achieving better than expected capital efficiencies, thus absent an increase in planned activity, I would expect us to end the year somewhere in the bottom half of this range.

That said, if the current oil price environment prevails, it's more likely that we will maintain or even increase drilling and completion activity from current levels, which would result in increased capital spending. Lease operating expenses in the first quarter were $7.81 per barrel of oil equivalent, 22% lower than the fourth quarter of 2015.

Underlying improvement in this metric is primarily attributable to greater efficiency in North American onshore production and the timing of workovers and other expenditures in the Permian and North Sea.

While we are very pleased with this cost performance, certain one-time items and timing issues benefited us in a way that will not continue through the year. Last quarter, we provided guidance that full year 2016 LOE per BOE would be roughly flat compared to full year 2015. This implied a target of approximately $9.50 per BOE.

With the progress we have already seen this year, we now believe 2016 LOE will be closer to $9.25 per BOE. On the G&A side, total cost continue to decline as we remain diligently focused on aligning overhead with capital spending levels. Our goal for the year was to further reduce gross cash overhead costs to a range of $650 million to $700 million.

We are currently tracking towards the low end of this range, and we continue finding opportunities to further reduce these costs. In the first quarter of 2016, recurring DD&A was $11.42 per BOE, 34% lower than the fourth quarter of 2015.

Our DD&A costs over the last several quarters have been on a clear downward trend as the result of price-related asset write-downs. Lastly on costs, we incurred $90 million of net interest expense in the first quarter. You will note a trend of increasing expense interest and decreasing capitalized interest over the last several quarters.

This is a result of unproved property impairments and reduce capital investment activity. Next I would like to make a few comments regarding our financial strength and liquidity position. In 2015, we worked very hard to strengthen our financial position and maintain our investment-grade credit rating with the three primary rating agencies.

Having accomplished this, one of our key financial objectives is to protect this position by maintaining unchanged or even reduced net debt by year-end 2016. During the first quarter, cash uses exceeded sources by approximately $463 million.

This was primarily the result of commodity realizations coming in below our plan, a front-end loaded capital program, and a build in working capital due to the timing of some nonrecurring working capital items. We anticipate these negative impacts early in the year will be more than offset later in the year.

Even with this shortfall in first-quarter cash flows, we ended the quarter with approximately $1 billion in cash. In summary, our financial condition and liquidity remain very strong.

We have created this position through disciplined capital spending and aggressive cost management rather than issuing equity, reducing the dividend or selling poor assets. Importantly, we still have good visibility to cash flow neutrality at our $35 plan level. Finally, I would like to take a moment to discuss Egypt production volume reporting.

As you are aware, we most often refer you to pro forma production volumes which for Egypt, excludes two items, the one-third minority share of volumes attributable to our partner and tax barrels. Throughout 2014, and the first three quarters of 2015, our reported tax barrel production averaged approximately 26,500 barrels of oil equivalent per day.

Asset impairments in the fourth quarter of 2015 and in the first quarter of 2016, combined with low oil prices, created a significant amount of noise in these tax barrel volumes. In the fourth quarter of 2015, these items resulted in negative tax barrel reported production of 47,000 barrels of oil equivalent per day.

In the first quarter of 2016, they resulted in Apache recording only 1,000 barrels of oil equivalent per day of production. As a reminder, tax barrels have no economic effect on our net cash flow from the business.

Combined with the fact that they can lead to this type of reporting volatility, we believe investors should focus primarily on pro forma production in Egypt. A more thorough description of this will be on our website along with a brief history of the difference between Egypt reported and pro forma volumes.

We have also included this information for your reference in this quarter's earnings supplement. In closing, we took great efforts over the past 18 months to position Apache prudently for a prolonged downturn.

After successfully navigating the challenges that confronted the industry in 2015, Apache is well-prepared to capitalize on the opportunities that we believe will ultimately emerge. We have delivered a strong start to 2016 and look forward to continued progress throughout the year. Our primary goals for 2016 remain unchanged.

We will live within our means, maintain our strong financial position, continue to build high-quality development inventory for the future, and invest to improve long-term returns and add shareholder value.

While we remain conservative in our budgeting and planned activity, we are prepared to respond when the environment is right to increase investment. I would now like to turn the call over to the operator for Q&A..

Our first question comes from the line of Ed Westlake with Credit Suisse. Please go ahead..

Congratulations on the cost reduction, really quite impressive. Quick question on cash.

You've got $1 billion of cash on the balance sheet, so just wondering what's the optimal level? I mean, obviously, peers have done some of the things you said, like issue equity and sell assets to get to their cash balances high, and people expect oil prices may still be volatile..

Yes. Thanks, Ed. This is Steve. I think at this point in time, I don't know what the optimal amount of cash on the balance sheet is, but I kind of like at this point in time having $1 billion of cash on the balance sheet. It's good for liquidity; I think it's a good time to have liquidity.

It's a good time to have the cash ready for deployment, either in terms of paying down debt if we decide we need to do that, or for deployment into the capital program if we see the price scenario in the future improving. Or, for that matter, I am happy just to hold cash.

We do believe that the cash balance will go back up to $1.5 billion by the end of this year, based on our plan for the year..

I guess a different way of asking it is there are obviously across the broad North American portfolio a lot of assets which potentially may be of interest to others, and as commodity prices lift their head a little bit, are you looking to be more aggressive on perhaps disposals of Tier 2?.

The answer to that is we are always looking at the portfolio. We have done some small one-offs that are not really material to production. But at this point, we are always looking at our internal assets.

We grade those against other things, we look at what could be added and what would add incremental value, but right now it's a pretty hard litmus test because of the types of projects we've deferred. So we sit on a pretty good set of assets, a really good deep inventory that we're very excited about, and we'll look how do we improve it going forward.

But nothing major planned on either side..

Your next question will from the line of David Tameron with Wells Fargo. Please go ahead..

Yes. Good morning. Nice quarter. A couple of questions, first I guess just on the horizontal Yeso.

John, can you talk about what your plans are there, after seeing the results in the first quarter? What should we look for from that asset over the next few months or next few quarters, I guess?.

Well, thanks, David. That is one of the areas that we've got inventory that we could put back to work. I mean, right now we do not have a rig that's over there. We've drilled some fantastic wells with, where the cost structure is moving now and when price has gone. That would be one of the areas that we could do, add some future activity to.

But right now we don't have anything immediately planned to do, but we've got a lot of nice inventory..

Okay. And then as a follow up, bigger picture, if I think about, last conference call you made the comment that you could have kept 2016 production flat at $45, obviously I think your service cost and efficiencies have improved since then.

Can you talk about looking forward, either give us an apples-to-apples numbers for 2016 or kind of projecting the forward for 2017, what that range would look like?.

Well, I will take you back to what I said on the last call was, in 2016 another $900 million, which would have put our capital budget midpoint around 2.5, would have kept his flat in 2016. As we look at 2017, clearly we continue to make progress on the efficiency side, which would lower that.

Our decline on our base is flattening, it's a function of, we're now 18 months into a slowdown in terms of the numbers of wells we've been bringing on, so that helps. Plus the base rate is a little lower that you have got to keep flat. So we see clearly less capital in 2017 to keep it flat, but it's kind of a moving target at this point.

And then obviously the other factor is we've got some projects that we are advancing, Kaliter (29:28) in the North Sea is on track, which would give us a big kick in the middle of 2017. So it's going to be less, but it's pretty dynamic and we're in the middle of working through a planning process at this point.

So at this point I'll just say it's going to be less than it would have been this year and you're right, $900 million or $45 base plan versus our $35 would have kept us neutral in 2016. But it will be a lower number for 2017..

Your next question will come from the line of Pearce Hammond with Simmons/Piper Jaffray. Please go ahead..

Hi, good afternoon, and thanks for taking my questions.

My first question, John, what is driving the steep decline in LOE, and then how sustainable are those cost declines?.

Well, and I'll let Steve chime in, in a minute, a lot of its timing of how things came up first quarter. We had a big drop in a couple of areas.

It is not something that will be there for the rest of the year, which is kind of why we moved our number down from $9.50 guidance to about $9.25, but we're making progress, and I've got confidence the guys can keep working on those numbers..

Yeah, I'll just....

Yeah, go ahead. Sorry..

Yes, just in echoing John's comments, we had good cost results in Egypt, in the Permian and the North Sea. All three have been very strong. I think there is a good mix of that that's just timing related, and you'll note that that kind of a reduction doesn't show up in the guidance reduction to $9.25 per BOE..

Great. Thank you.

And then my follow-up is given the improvement in commodity price, any updated thoughts on hedging?.

At this point, the environment's getting much better. I mean, we like the direction on the cost, we like the direction on the oil price, so I think we're at a point where things are starting to look pretty darn attractive. But right now, our best hedge is we haven't committed to a lot of rigs or a big program at this point.

So it's one of those things we will be discussing as we start to look at plans, but at this point, we're not quite where I would feel good about locking in a scenario..

Your next question will come from the line of Evan Calio with Morgan Stanley. Please go ahead..

Hey. Good morning, guys. Good afternoon to you, sorry. I appreciate all the color. I just wanted to make sure I understand the activity re-acceleration, which sounds closer.

You accelerated around current levels, or are you looking for market fundamentals to clean up and then that acceleration will be governed, or the pace of that acceleration will be governed to remain cash flow neutral? Is that right?.

Well, I mean, I think the key is, Evan, we budgeted to be cash flow neutral this year at $35 and a $2.35 gas price. We're a little bit behind that in the first quarter on oil, we're behind it on gas. Clearly, in April we've seen a little bit of a rebound.

So if the strip were to hold up, clearly we're going to be in a position to have some cash to deploy in the back half of the year, and those are the types of things we would look at. But there's lots of things out there. I mean, we've got debt we could address or the program.

But the plan would be to – cash flow is going to be the governor, we plan to stay cash neutral, and we'll have some options to choose from if the current conditions hold..

Great. You also discussed your North American capital allocation in the recovery, but you didn't mention the Eagle Ford, which I had thought was a higher hurdle from your previous comments. Yet in Q1, you completed four Eagle Ford wells with competitive results.

Can you discuss what the driver there was? Is that some science or lease-related activity?.

Well, we mentioned we'd been doing a lot of strategic testing. I mean, most of our North American capital is designed to that. We had some wells that were down that we wanted to complete and, you know, to be able to evaluate those. The Eagle Ford will require a little higher hurdle than some of the other plays.

So as we start to think about in the future potentially putting capital back to work, right now it would not be the first place it would go. But we're seeing great progress in the Eagle Ford as well and have made a lot of progress over the last 18 months. So it's something I think can be an option in the future..

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

Yeah, I had a question for you on the shales. Obviously, you've had a lot of improvement.

How much capital have you really dedicated from the science side of things to better optimize, like density studies, things like that?.

John, I'd say if you look at our strategic testing, it really falls into several buckets, and I don't have an exact split on how much of it is in that portion of it, but we're doing three things, really. We're testing new acreage, we're testing new zones and then we're optimizing within zones.

And if you look at our completions in the – a lot of the Permian as well as the Woodford or even the Eagle Ford, I mean, we're taking and integrating seismic data, core data, petrophysics, landing zones, everything.

And so we're doing a lot of time on that, and I think that's where you're seeing some of the productivity things that are showing up from that time that we're taking to do things properly, and we've learned an awful lot..

Okay.

Next one for me, with the services companies, do you find that your conversations about future activity levels and costs are different? Is it more collegial, less adversarial, or...?.

Yes, I would say that really, since the fall of last year, it's become a lot more collaborative.

I mean, we've had some really good sit-down discussions with some of the small service companies as well as some of the very big ones and have had some really, really constructive conversations on how do we lower the cost structure in North America, and a lot of progress on that front.

And I think a willingness to recognize that that's what is going to take going forward. And you're seeing some of the fruits show up, not just in terms of cost reductions from the service side, but in terms of execution, efficiencies, structural things, a lot of these things that are going to be permanent. And that's what's important..

Your next question comes from the line of Arun Jayaram with JPMorgan. Please go ahead..

Yes, good afternoon.

John, I was wondering if you could perhaps comment on some of the steps you're taking kind of to manage your base decline in the Permian? You had a pretty skinny sequential decline, right? So in addition to new drilling activity, what are you doing to manage that base?.

Well, I mean, I think one of the big things is we've stepped back.

We've gone from trying to bring on a lot of wells and completing a lot of wells to really getting back to managing your base, and looking at fluid levels, looking at optimizing how we're producing these wells, changing some of the lift, it's amazing what you can do when you take the time. Compression, optimizing water shut offs, little things.

And there's not a lot of money, but boy, it sure makes a big, big difference. I mean, we've got back in, cleaned out some injectors in some of our water floods, some of the old bread and butter, classic Apache things that we've done for decades..

John, I remember you commenting, maybe in a previous call, that you thought that your overall base decline rate was in the low 20% range? Any thoughts on that number, is it a coming down?.

Well, I mean, clearly, as we started the year, we said it was in the 25%, 26% range. As we bring on fewer wells, which is what we've done, it has flattened and is flattening. That's a good topic of discussion with me and our reservoir engineers, because we are always working on that.

But clearly it is coming off and clearly in terms of flattening, and then also all these projects help too. So I think you'll see us continue to focus on that. It gets back to the quality of having some conventional, and a big chunk of our Permian is water floods and CO2 floods and things that just don't decline as rapidly.

There's a lot of things you can do, scale cleanouts, all kinds of things, moving more water, there's just a lot – you have a lot more options to pull on your conventional asset base and you're seeing us pull those. So I think you will see it flatten..

Your next question will come from the line of Scott Hanold with RBC Capital Markets. Please go ahead..

Thanks. Good afternoon.

Just specifically on some North Sea activity, did the Storr and Kinord wells, did those move into this year? And if you could comment if changes in the PRT tax over there have changed your view on how active you get?.

Yes, I would say that the changes in the PRT are very helpful. It does not change where we are in terms of the game plan. I mean, we've got such a low cost structure there relative to the rest of the industry, and we're going to generate cash flow out of the North Sea, much like Egypt, on our international portfolio.

So it does not change big picture the steps we're taking, but it does make things more attractive, and provides us incremental cash flow, it lets us do a few more things. We do plan to bring Storr and Kinord into the back half of this year at this point.

So that would be – the plan would be to at least get the wells drilled at this back half of the year or could spill into next year..

Okay. Thanks. And as my follow-up, turning to the Permian and really good results on that Seagull well.

Could you give a little color on what you all might have done differently there and maybe a little bit of color, too, on that new zone within the Third Bone Spring that you're looking at?.

Well, I mean, the Seagull is a pretty – it's only a 4,600 foot lateral. It's really target testing and modification. As we continue to understand the hydrocarbon system, we're figuring out exactly where to land those wells and how to modify our fracs.

And, Tim, do you have any color you want to add?.

Yes, really, the results of the Seagull well incorporate the integration of the team, and that really takes into consideration the 3-D and targeting fracture intensity there.

And it's had tremendous results and I think it's repeatable as we've just recently put a well online, or Bluejay 103, that's flowing over 2000 barrels of oil per day, very similar geologic environment..

Your next question will come from the line of Doug Leggate with Bank of America. Please go ahead..

Thank you. Guys, I don't know if you could give this or not, but Egypt and the North Sea are your big cash cows in the portfolio.

I wonder if you could give us an idea of what the operating cash and free cash flows out of those assets this quarter?.

Yeah, Doug. We typically don't give that type of information down to the asset level. You obviously can figure that out at the end of each year. We are thinking about some – potentially expanding our – both our guidance and our detailed reporting around things like that for the future. But we're not ready to start doing that at this point in time.

I can tell you that both of those asset areas this year will be cash flow generators for us..

Were they free cash flow positive in Q1?.

Not going to say whether they were or not. I can say that they will be for the year, that's for sure..

Your next question comes from the line of John Freeman with Raymond James. Please go ahead..

Good afternoon.

On the Bluejay 103H that you just mentioned came on at over 2,000-barrels a day and also set a record and completed at $3.5 million, what were the specs on that well, like the lateral length?.

That's just a single mile lateral..

And then where specifically is it located in your position?.

It's our target one in the Third Bone Springs interval..

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

Yes, apologies, I'm going to keep going on the Bluejay and the Seagull, if I could. But if we put it in the wider context, you talked about design and efficiency gaining you in costs considerably since 2014. Has there been a step change there or is that a linear progression? And further to that, you mentioned the results at Bluejay were very strong.

I was going to ask you if they were less than the Seagull, where you had such strong volume performance.

Can we go – I guess what I'm driving at with the linear and the step is can we actually go a whole lot lower than that $3.5 million? Does it have a similar split between drilling and completion that we typically see? How much more do you think we can get out for less money? Is it a question of more volume, or can you actually even go less money? Thanks..

Yes. I mean, when you look at – we put in the supplement a good bar chart that shows the steps in terms of how the costs have come down really over the last five or six quarters. So I continue to be amazed at what we can do. Obviously, there are certain things that, as you get lower and lower, it gets harder to keep having those sorts of reductions.

I mean, I think $3.5 million for a mile-long lateral in the Delaware is pretty strong, especially with the type of productivity the well's come on. It tells you we're not cutting corners on the completion or anything like that. So, yeah, we'll clearly keep driving.

The guys will tell you they can keep taking off small chunks, but how far – how much further can we go, I think that will be a function – we'll just have to wait and see what we can do. In terms of performance, it's going to end up being pretty similar to the Seagull. The 2,800 BOEs a day included gas, the 2,000.

As Tim referenced, it's very early on the Bluejay, and that's just on the oil side. So I think it's going to be a pretty similar well before it's all said and done. But we'll have to wait and see..

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

Good afternoon, John, and to the rest of your team there. I'd like to go back to the question of the possible acceleration in the back half of 2016.

I know you spent a lot of your prepared comments on this and you've already had a couple questions in Q&A here, but number of other companies have spoken about this decision, this kind of a – maybe being in two pieces.

The first question is do you have the capacity to accelerate? And then the second would be do you have the appetite to or do you have the returns to? And I wonder if you could speak more to that second piece.

I understand that you want to keep staying cash flow neutral on the year, but in this current environment, is $45 enough for – you would have the cash flow – but is it enough on the returns front on these plays to really entice you to up your rig count?.

Charles, a couple of things. Number one, we've seen tremendous progress and now we've got a lot of wells with returns actually full cycle, fully burdened, look pretty darn good. So I think we've got plenty of inventory. If you go back a year ago, everybody started ramping up and adding rigs quickly and expecting prices to hold.

And unfortunately, those that outspent significantly in anticipation of what I'll call visibility into more flat, longer sustainable price environment, ended up having to go back to the debt markets or the equity markets, that sort of thing. So I mean we're going to be cautious. We're going to be very thoughtful and disciplined.

And like I said, we're going to want to see some cash flow accrue before we start putting things back to work. But we'll have a lot of conversations over the next couple of months and weeks, actually starting next week with the Board. A lot to talk about, and the nice thing is we have a lot of attractive options right now.

We've also got a lot of things we want to test. And quite frankly as I look at the results and I look at the well cost, I'm glad I didn't outspend in some of the other quarters, because we've got wells that we didn't drill. I mean, we continue to make progress and we'll do things differently.

So there's a fine line of feeling when we're ready to move forward. We clearly had the financial capacity to do so. The returns are starting to look pretty darn good, and it's a function of managing and balancing your financial structure..

Got it. That's helpful detail, John.

And am I understanding you correctly that it's not just the level of the oil price, but you want to see it settle in there with less volatility? Is that am I hearing that correctly?.

Yeah, no. We're going to have to be prepared to live in volatile bands. But I just want to see more visibility into more belief we're going to have the cash flow that's going to come with the price, and it's going to stay there a little bit, so..

Your next question will come from the line of Michael Hall with Heikkinen Energy Advisors. Please go ahead..

Yes. Thanks. If I could, just a couple accounting-related questions for me.

First, on Egypt, am I understanding it right, you basically had, on a recurring net income basis, about a $17 million loss, if I just back off the $54 million write down from the $71 million non-controlling interest? I'm just talking about the non-controlling interest side, that $17 million.

And if that's right, I'm just trying to think through, what price level is that business net income breakeven?.

Yes. Sorry, Michael.

You're looking at what number for Egypt?.

So, on the non-controlling interest side, the $71 million loss that was backed out, if you just adjust that for the $54 million write down in the adjustment, you get $17 million loss on that third of the business.

Is that the right way to think about it? And if so, what price level brings net income to breakeven?.

Yes. If you corrected that for the Egypt's non-controlling portion of the impairment in Egypt, you said..

Right. Exactly, yes.

Is that the right way to think about it?.

Yes, so – and the question is what would it take to do what?.

My question is, number one, is that right way to think about if that's the net income on that third of the business? And then number two, what price level would be required to drive a net income breakeven for that business?.

Yeah, okay. So I think that for the quarter, yes, that's a reasonable way to think about that. I think when you reduce operating results down to a single quarter, you're going to get lots of noise in that quarter.

But for example I think we had a significant piece of noise on the revenue side in Egypt for the quarter to the tune of about $8 million on gas revenue side that we're in some dispute on, and we're looking at.

I think that obviously the issue with the price that would breakeven, so how much lower can the price go to breakeven from an accounting perspective. I think that's obviously very difficult to do because of the cost sharing arrangement in the PSC.

So I'm not really prepared to say how far down prices would have to go in order for that number to become zero. But suffice it to say, it would have to go down a bit more from where it is in the first quarter in order for that to happen..

Yes, that's what I was getting at, that's helpful. Maybe I'll follow up more offline.

And then the other piece was just on the North Sea, again accounting-related, but the $27 million PRT refund, was that adjusted out of net income in that $55 million tax adjustment, or is that still in the net income line? Is that expected to recur, or any more of those coming this year?.

No, it's not adjusted out of net income. It is a PRT refund because of, there are some costs related to prior year items. That's not an unusual type of thing to happen in the North Sea. We have that happen on a regular basis, we never adjust that out, whether it's a benefit to us or a detriment to us.

We don't adjust it out for calculating adjusted earnings or adjusted EBITDA. It is – it's a large item this quarter relative to typical PRT simply because PRT is now approaching zero with the price environment that we have. But it's not – if you go back two or three years, you'll find PRT expense of nearly $300 million in some years..

Your next question will come from the line of Michael Rowe with Tudor Pickering Holt. Please go ahead..

Thanks. Good afternoon. First question I have is on cash flow. You highlighted in your prepared remarks there was a big swing in working capital during the first quarter, as well as an excess of cash CapEx over accrual CapEx.

So just to confirm, we should expect those items to reverse throughout the year so that you don't have any net debt additions, all else equal, according to the budget?.

That's right. So if we assume we don't pay down any debt this year, we expect to end closer to the $1.5 billion of cash where we started. We had about, a little over $450 million of cash consumption in the first quarter.

Roughly two thirds of that, if you just take, if you look at first quarter actual versus the plan that it would take for the year to get to cash flow neutrality, of that $450 million, and about two thirds of that is because we built working capital in the first quarter and we had practically zero sale proceeds in the first quarter.

We expect both of those items to be cash flow generators for us by the time we get to the end of the year. So, about two thirds of the $450 million is simply because of that. We had a pretty significant build in working capital during the quarter.

The other one-third of the $450 million would be split roughly 50-50 between the overspend on capital in the year, versus kind of an average quarterly run rate for the year and the shortfall on revenues, less OpEx, because of the fact that prices were below our $35, $2.35 Henry Hub plan for the year.

On the working capital side, I mean, so why did we build working capital in the first quarter? The primary reason for that is because of the pay down of payables and accrued costs between the end of the fourth quarter last year and the end of first quarter this year.

And that's primarily because activity is slowing down so much, so our payables are coming down. Activity won't continue to slow down quite at the pace that it did through that timeframe, and we expect inventory and accounts receivables, which tend to lag a bit, the pay down of payables, those to also come down through the year.

And then we've got some pretty significant unique items, if you will, on the working capital side that we expect late this year, probably in the fourth quarter. Those are primarily in the form of tax refunds on loss carrybacks that – one has been filed, one is about to be filed.

And then also, we do anticipate some asset sales, which will also take place later this year, the proceeds of which will come in late in 2016. So all of those things combine to offset the $460 million cash deficit that we incurred in the first quarter..

Great. That's helpful..

A very longwinded way of saying, yes, we anticipate getting back to $1.5 billion cash with the same debt level by the end of this year..

Great. Thanks for the clarity there. And my second question, or follow-up, is you talked about adding capital potentially back to the Permian first if you got some stability on the oil price and felt good about the cost structure.

But I was wondering if you all are comfortable allocating that towards strategic testing first, kind of like you're already doing this year, rather than full development or development drilling? Just curious on how you compare the capital efficiency between strategic testing and development drilling. Thanks..

And, Michael, in my prepared comments, we said obviously there would be some that went into the development side of Permian as well as some acceleration of some of the testing. And then also you've got a couple platform rigs in the North Sea that we'd like to keep active. And then you've got Egypt – projects in Egypt as well as the Woodford.

So we look at what sets us up best for the future, and we look at the timing under which we want to go drill some development wells as well. So it'd be a balance, but you'd see some of it going to development potentially and then some of it would accelerate some testing..

Your next question will come from the line of Richard Tullis with Capital One Securities. Please go ahead..

Hi. Thanks, John, and thanks for taking a call at this late hour. I'll be quick. Obviously, you've had some nice well results over the past several quarters in that Pecos Bend area.

Roughly how much surface acres do you have there and how many estimated drilling locations, given the various targets, at this point?.

The Pecos Bend area is a very small area that we've got, and we've been pretty active there. I think it shows you, it's a block of acreage that's less than 10,000 acres. And quite frankly, the other nice thing there is we have a high mineral interest. So we don't have many royalty owners we have to share anything with.

But it just shows you the depth and the number of wells and so forth that we can continue to drill. We've got a good, I would say, probably 40 to 50 wells there easily that even the one zone would add..

Okay.

And just staying that same theme, looking at some of your best areas in the Permian, I guess that would be Pecos Bend, Barnhart, Deadwood, Wild Flower, how much acreage in total is made up from all of those different areas?.

Well, I mean, the best thing I can do is point you back to our November 2014 Analyst Day where we broke the areas down. I mean, we've got 3.3 million gross acres in the Permian. We've got about 1.6 million to 1.7 million net. The four-county area we showed in the southern Midland Basin, we've got over 200,000 acres.

That did not really include even the Audrian County stuff. So the best place to go look at those acreage counts would be going back to our analysts update from late 2014..

At this time I will turn the conference back over to management for any closing remarks..

Thank you, Regina. Well, that's going to conclude the call the day. We've reached the top of the hour. We look forward to speaking with everybody on next quarter's call. If you have any follow ups, please call Christopher Cortez or myself. Thanks..

Ladies and gentlemen, this concludes today's conference. Thank you all for joining, and you may now disconnect..