Anadarko Petroleum (APC) R. A. Walker on Q2 2016 Results - Earnings Call Transcript

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Anadarko Petroleum Corp. (NYSE:APC)

Q2 2016 Earnings Call

July 27, 2016 9:00 am ET

Executives

John M. Colglazier - Senior VP-Investor Relations & Communications

R. A. Walker - Chairman, President & Chief Executive Officer

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

Robert P. Daniels - Executive VP-International & Deepwater Exploration

Robert G. Gwin - Executive Vice President-Finance & Chief Financial Officer

James J. Kleckner - EVP-International & Deepwater Operations

Analysts

Evan Calio - Morgan Stanley & Co. LLC

Doug Leggate - Bank of America Merrill Lynch

Charles A. Meade - Johnson Rice & Co. LLC

Edward George Westlake - Credit Suisse Securities (NYSE:USA) LLC (Broker)

Ryan Todd - Deutsche Bank Securities, Inc.

Brian Singer - Goldman Sachs & Co.

David R. Tameron - Wells Fargo Securities LLC

Paul Sankey - Wolfe Research LLC

John P. Herrlin - SG Americas Securities LLC

Arun Jayaram - JPMorgan Securities LLC

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

James Sullivan - Alembic Global Advisors LLC

Jonathan D. Wolff - Jefferies LLC

Operator

Good morning, and welcome to the Anadarko Petroleum Second Quarter 2016 Earnings Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please also note today's event is being recorded.

I would now like to turn the conference over to John. Please go ahead, sir.

John M. Colglazier - Senior VP-Investor Relations & Communications

Thank you, Rocco. Good morning, everyone. We're glad you could join us today for Anadarko's Second Quarter 2016 Conference Calls. I would like to remind you that today's presentation includes forward-looking statements and certain non-GAAP financial measures. And be aware that a number of factors could cause results to differ materially from what we discuss today. So I encourage you to read our full disclosure on forward-looking statements and the GAAP reconciliations located on our website and attached to yesterday's earnings release.

In just a moment I'll turn the call over to Al Walker for some brief opening remarks. But first I want to thank Jeremy Smith for his contributions he's made to the IR group over the last couple years. Jeremy is now in his new role as Vice President of Mozambique Project Finance.

And along with that, I'd like to introduce Pete Zagrzecki, who has joined IR and will be available to assist with questions later this afternoon along with the rest of our team. I will also remind you we have a lot of additional detail in our quarterly ops report, available on our website. And following Al's prepared remarks, we'll open it up for questions with our executive team. Al?

R. A. Walker - Chairman, President & Chief Executive Officer

Thanks, John, and good morning. As we turn the corner into the second half of 2016, we've made exceptional progress on the goals we established for this year of enhancing value, strengthening the balance sheet, hydrating the portfolio, and reducing costs.

In terms of enhancing value our operating organization has done a tremendous job achieving several milestones during the quarter. As you can see in our operations report available online, we had outstanding performance in the Gulf of Mexico. This is an area where we hold several competitive advantages: a successful exploration track record, an industry-leading project management capability, and a large operated infrastructure position.

Our Gulf assets provide us a capital efficient value driver. And our record production achievements at Constitution and K2 are great examples of that. Our operator of the Lucius facility also achieved record production during the quarter with oil volumes exceeding nameplate capacity. As I suspect you noticed in our ops report, we drilled another appraisal well at Shenandoah. The Shenandoah-5 well encountered more than 1,000 feet of net oil pay and expanded the eastern extent of the field with planning of the Shen-6 now underway.

We have a 33% working interest in Shenandoah after participating in a pref right process. And through that process we picked up some additional blocks and exploration opportunities at no cost.

Record production levels were also achieved in the DJ and the Delaware Basins. And we were able to increase our activity over our initial expectations, while still keeping capital expenditures within guidance.

In the Delaware Basin we have further reduced our DC&E costs per well and improved our drilling cycle times, while advancing our delineation program across a very large acreage position. In the DJ Basin we achieved record production, while lowering our LOE by about 15% year over year.

Our outstanding operating results are complemented by another year of strong monetization results. In the first quarter we announced approximately $1.3 billion of monetizations. Since then we've achieved and have received an additional $1.2 billion of proceeds and executed a successful secondary offering of WGP units. We now expect total proceeds to be at or above $3.5 billion for the full year.

So far this year, through the cost structure improvements I have mentioned, as well as the dividend reduction and monetization efforts, we have significantly strengthened the balance sheet. We've done this by retiring $3 billion of near-term maturities with our first quarter fixed income issuance and planning to retire the remaining $750 million of 2017 maturities from our monetization proceeds.

The cautious approach we outlined for oil price recovery at the beginning of 2015 has played out much as we anticipated. It now appears U.S. oil supply peaked at around 9.6 million barrels per day. And we expect it to bottom out around 8 million barrels per day, all the while with global demand now exceeding expectations.

Given this dynamic, I am now encouraged that a sustained $60 oil price environment is likely to emerge as we move into 2017. This price level should provide the necessary cash margins and resulting cash cycle improvements to encourage us to accelerate activity and achieve strong returns. In this scenario we would evaluate redeploying some of the incremental proceeds from asset sales towards our highest quality U.S. onshore assets later this year.

Our unique positions in the DJ and Delaware Basins, combined with the tieback opportunities in the Gulf of Mexico, give us strong line of sight for attractive, capital efficient, short cycle oil investments, as crude prices recover.

With that, we would love to take your questions. And thanks for joining us this morning.

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. Today's first question comes from Evan Calio of Morgan Stanley. Please go ahead.

Evan Calio - Morgan Stanley & Co. LLC

Hey. Good morning, guys. You guys continue to run six rigs in the Delaware. I know you mentioned it in some of your opening comments, but you'd previously mentioned lowering it to four. Should we expect six rigs all year? And that's where you're recycling some of the cost savings in the flat CapEx guidance or is there a ramp for even potentially a higher rig count with asset sales?

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

Yeah, Evan. This is Darrell. The plan was four. But I can tell you we've seen continued reductions in some of our cost structure and some increased efficiencies. And so we've just elected to continue to get more activities done with that same capital that was allocated at the beginning of the year. And so as far as other activities looking forward, it really just depends on the progress we make from here on.

Evan Calio - Morgan Stanley & Co. LLC

Okay. So at least with regard to the six, I mean should we expect completion activity to match the rig count in 2H and was that factored into your current higher guidance?

R. A. Walker - Chairman, President & Chief Executive Officer

If I could – this is Al. I think a lot of that's going to be very dependent upon what we anticipate to be a recovery in oil prices. But we're going to watch that pretty closely before we commit beyond the comments we're giving you this morning.

But I'm – for the first time since January of 2015 I think we see a window to better oil prices. And I foreshadowed this a little bit at the Wells [Fargo] conference a few months ago when I made the comments there that we anticipated we'd have a leg down as the market tried to absorb the 3 million barrels associated with disruptions from Venezuela, Nigeria, and Canada. And as the market went through that congestion, we were going to see the leg down that we're seeing right now. And I think once we get that behind us – to use an economics term, ceteris paribus – we think we're looking at a sustained $60 oil price environment for next year.

But I think to the question you're asking, until we see greater evidence that our thoughts are in fact true, we'll be a little slow and probably more likely to be willing to communicate that with greater clarity next quarter.

Evan Calio - Morgan Stanley & Co. LLC

That's helpful. Maybe one more if I could. Moving offshore, which also dovetails, I think, with your oil price outlook. You reported positive appraisal results from Shenandoah-5 with 6 upcoming. I mean post 6, what else do you need here to reach FID? Either from an appraisal or technical information gathered or from an oil price environment to – again to get to FID?

Robert P. Daniels - Executive VP-International & Deepwater Exploration

Yeah. Evan, we were real pleased with what we saw on the Number 5 well. Not surprised, but we were very pleased to see it come in as we had predicted it would, 1,040-plus feet of pay. We're about a half mile east of the Number 2 well. And then we're going to move farther east and downdip with the Number 6.

With your question of what else it's going to take, we really have to see what the Number 6 tells us. If the Number 6 comes in as we project with the oil/water contacts, we'll probably need to then do a sidetrack out of that, try to go updip, get in – a full oil column in that. And so the ultimate planning has to be after Number 6.

We've got a lot of work that's going on right now, though, related to how we might develop this field. But again we're still in the appraisal mode. And so we need to get the rest of the information in front of us.

Evan Calio - Morgan Stanley & Co. LLC

Right so I guess within your – I guess you'd...

Robert P. Daniels - Executive VP-International & Deepwater Exploration

I'm sorry, Evan. We talked over you. But go ahead. What was your question?

Evan Calio - Morgan Stanley & Co. LLC

Yeah. I was just going to say, I was going to try and understand. It sounds like it's a longer term project as it fits in your portfolio as you – lots of invested capital and now a 33% interest. Is that kind of right way to think about when this – when you're developing here? I know it's obviously path dependent on appraisal information.

R. A. Walker - Chairman, President & Chief Executive Officer

Well, I think all the things Bob just gave you are going to be kind of ingredients that are going to be important to understand. I'd point to Mad Dog, which I believe BP has publicly discussed the fact they're going to take a decision on this year. And have indicated that sanctioning is likely.

And I think there's just a couple of takeaways from that, not necessarily that they're related to Shenandoah. One is they reduce the production solution costs from $20 billion to $8 billion. So that helps with the economics. And two, they think they've got an estimated ultimate recovery that's pretty significant. And so the EUR combined with the lower cost probably gives you a threshold for a price that would not have been anticipated a few years ago for sanctioning.

So we're hopeful that some of those ingredients will work into our favor as that decision comes to us over the next couple of years.

Evan Calio - Morgan Stanley & Co. LLC

Great. That's helpful, guys.

R. A. Walker - Chairman, President & Chief Executive Officer

You bet.

Operator

And our next question comes from Doug Leggate of Bank of America. Please go ahead.

Doug Leggate - Bank of America Merrill Lynch

Thanks. Good morning, everybody. Morning, Al.

R. A. Walker - Chairman, President & Chief Executive Officer

Morning.

Doug Leggate - Bank of America Merrill Lynch

Al, one of the things I guess that makes guidance a little challenging, at least in terms of the production outlook, is the tieback schedule that you've obviously been quite successful in, in the Gulf of Mexico. I'm just wondering if you could give us some help on relative capital allocation? And I guess the way I would ask the question is on K2 and Constitution in particular, what is the haulage (11:51) that you could seek to fill? And how does the relative priority of tiebacks stack up relative to adding capital onshore? I've got a follow-up, please.

R. A. Walker - Chairman, President & Chief Executive Officer

Well if you go back to our March presentation, the allocation that we laid out at that time gives you a pretty clear understanding. I think the only thing we would say that would change from that is just simply if we find ourselves in an improving oil price environment, which I said earlier I think's very likely, we will deploy that initially for the debt retirement for the maturities in 2017, and then we'll look to the two principal onshore assets in the DJ and Delaware Basins for that capital.

That aside, Doug, I can't see any other additional percentage allocation going differently than what we laid out in March. And it's too early to say at this juncture what we'll do for 2017.

Doug Leggate - Bank of America Merrill Lynch

Okay. I appreciate the attempt at the answer. I wanted, a second follow-up if I may, is on the Delaware Basin. I know there's been a lot of chatter about whether and if you could ever see an opportunity to acquire your partner's interest there.

But if I may, I want to try and ask that question a little differently. Can you give us some color as to what the operated and non-operated activity looks like? And what I'm really getting at is whether – how many wells have been proposed by Anadarko versus Shell? And what kind of participation you're getting from your partner? Because my understanding is that you may end up with higher working interest in some of those incremental wells.

R. A. Walker - Chairman, President & Chief Executive Officer

Well I'm going to let Darrell fill in some of the details. But that's a question that's really hard to answer, because every package of AFEs that they send to us or we send to them causes that – sort of change the landscape a little bit.

We don't have a great insight into what sort of plans they have for developing those wells that they want to push AFEs towards us on. And ours – in terms of what we're planning to do, I think by evidence of the fact we're standing up a few more rigs, speaks to our confidence in the field, as well as gives you some insight into what we think the oil prices are going to do.

I think beyond that, let me let Darrell fill you in just a little bit more on the details. But philosophically, Doug, I don't think it's likely that our partner there is a seller, as best we can tell it. It doesn't seem like they're motivated to do so. And frankly, given the quality of the asset, I can understand that.

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

Yeah, Doug, probably to follow on with that. From a working interest standpoint I think assuming the 50-50 is about where we're going to end up and really are today. I don't see that really changing, because of the additional drilling that's going on. I can't speak to the future and the balance of the year. But I can tell you that as today we got six rigs stood up, and Shell has two rigs stood up.

Doug Leggate - Bank of America Merrill Lynch

So is Shell participating in all the wells that you're putting forward?

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

Yes, they are.

Doug Leggate - Bank of America Merrill Lynch

Great stuff. Thanks, guys.

Operator

And our next question comes from Charles Meade of Johnson Rice. Please go ahead.

Charles A. Meade - Johnson Rice & Co. LLC

Good morning, Al, and to the rest of your team there. I wanted to ask about your view on the A&D marketplace. And specifically, you guys have been very successful selling assets. But at some point there was also talk of perhaps buying in the Delaware Basin. So could you talk about what you're seeing on the asset sale side? And what implications that might have for your ability to add in the Delaware Basin?

R. A. Walker - Chairman, President & Chief Executive Officer

Sure. I think Bob Gwin's probably in a better position to answer that for you. And I'll just say before I pass it to him I think he and Jerry Windlinger and the folks that have been working that for us over the last several years, particularly in the last 24 months when the market conditions have been pretty challenging, have done an exceptional job.

And we often talk about it being a core strength of ours in how we manage our A&D portfolio and how well I think we can do it even in times of challenging and stressful pricing. I know there's been a lot of investor concern that, can you continue to sell assets in a very depressed market? And I couldn't be happier with what I think what Bob and Jerry have done the last couple of years.

So, Bob, let me turn it over to you to answer the question specifically.

Robert G. Gwin - Executive Vice President-Finance & Chief Financial Officer

Okay. Thanks. Charles, it's really a market today where we are buying and selling, but in a lot of small transactions. So it's things that are small enough they generally don't get reported. The ones that we're summarizing in our asset divestor program are generally our larger transactions.

Or in some cases like even recently in the Permian, where we saw some acreage that we had in the portfolio. Felt like we wouldn't get to that acreage for quite a while. And that it didn't necessarily fit as well relative to our development plans. And so we saw it as a unique opportunity to sell something.

I think it's fair to say that the market should continue to be receptive. Based on the dynamics we're seeing, it should continue to be receptive for the types of assets that we're bringing to market. Those assets share a common characteristic that they're generally not going to attract capital in our portfolio, really at virtually any gas price. And I mention the gas price, because they're mostly dry gas assets. We will retain a lot of exposure to gas through the associated gas of our two primary U.S. onshore assets.

But the dry gas assets have pretty good economics, intrinsic economics at strip pricing. And so we've seen buyers that see it as a – need assets relative to the size of their firm and the types of things they're trying to do. Not as attractive to us, and they make a lot of sense for us to sell.

On the margin we however are a buyer of assets, and if they're priced right and if they're in the right location. And really the three core areas where we're putting capital and we believe we have competitive advantages in the Delaware and in the Wattenberg and in the Gulf of Mexico are places where we continue to look at packages. We look at packages elsewhere. But in many cases we don't see what our competitive advantage will be or what the synergy is with our existing operations. And so we have not been successful bidders on those packages where we've chosen to submit a bid.

Charles A. Meade - Johnson Rice & Co. LLC

Got it. That's helpful detail. Thank you. And then, picking up on – perhaps on that thread of the Wattenberg or the DJ Basin, I want to say it was maybe a year and a half or two years ago that you started the conference call talking about the enigma or the puzzle of what was going on with the California – or excuse me, the Colorado ballot initiatives.

And it's a little different story this time around. But it feels like déjà vu for a lot of people. And the question is – the question on some people's mind is, are we going to be stuck in this kind of loop in Colorado? So can you offer your thoughts on that front? And on the political process and the environment in Colorado? And perhaps if that interacts with your decision or your future decisions to accelerate in the DJ?

R. A. Walker - Chairman, President & Chief Executive Officer

Okay. Let me take a comment or two on that. One is, we take what we do in the DJ Basin in Colorado, broadly defined, very seriously. And we try very hard every day to be a part of educating the electorate in the state.

We feel like with knowledge of and understanding and appreciation for what the industry does and how we're doing it, and the issues associated with what setbacks really mean, that an educated voter is more likely to understand why this is important and why the ballot initiative as structured, particularly this year, would do so much damage to the state.

We think that's very important. We see both the U.S. senators from the state as well as the governor being very understanding of this issue. In fact, I saw Governor Hickenlooper was on CNBC earlier this morning. And I think he's considered one of the better governors in the United States and certainly is very thoughtful around these issues, being a part of the oil and gas industry much earlier in his career as a geologist.

So I think politically we have, I think, a very good understanding from both a Democratic governor, a Democratic senator, and a Republican senator. And I think the politics in the state are such that we just need to continue to do what we can do with the help of other industry participants to educate the voters in a way, when they do go to the ballot, and if a ballot were in fact on the docket for this fall, that they understand what they're voting on. And we take that very seriously every day, as well as Noble and a lot of other companies. And I think to that end that is the best way I can address your question.

Charles A. Meade - Johnson Rice & Co. LLC

Okay. Thank you, Al.

Operator

And our next question comes from Ed Westlake of Credit Suisse. Please go ahead.

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker)

Yeah. Good morning. I'm intrigued by the schematic that you put in the Delaware this ops report. I mean 24 wells, 28 wells a section, across obviously the three to four different zones. Other companies are showing similar stuff.

But my question is really around your 2 billion BOE resource number; it seems low versus the number of well locations, and then you own an acreage position. So just thinking about, is it because this – some of the acreage is non-core or is it just a progress on delineation of this large resource and complex geology? And then I have a follow-on.

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

Yeah, Ed. This is Darrell. I do think that's a conservative number, as we spoke about last quarter. That 2 billion BOE of resource, that's on a net basis. And I think when we look at it and with the amount of BOEs in place per each section, I mean we're looking at something less than a 5% recovery. And we truly feel we'll get a lot more than that. So I do think there's a lot more upside in the numbers that we've reported today.

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker)

Okay. And then specifically I guess on the – most of the focus has been on the Wolfcamp for the obvious reasons, but on the shallower zones, the Avalon and the Second Bone Spring, any sort of indication of sort of EURs that you'd expect from those? Thank you.

R. A. Walker - Chairman, President & Chief Executive Officer

I think all of those are going to be part of our future plan. When we talked about the resources last quarter, we are only talking about Wolfcamp. And if you think about – largely what we're drilling today is down to the Wolfcamp in terms of making sure we retain acreage. We're having to drill down some of the deeper depths. And so we haven't spent as much time on the Avalon and Bone Springs. But I can tell you we're very high on those as well. We think those EURs are still going to be 600 million plus range in those sections. And so they will be part of our future and part of our future resource, but not quoted in the numbers we're talking today.

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker)

Okay. Thanks. Very clear.

Operator

And our next question comes from Ryan Todd of Deutsche Bank. Please go ahead.

Ryan Todd - Deutsche Bank Securities, Inc.

Great. Thanks. Maybe if I could do one follow-up on capital allocation over the next – and acceleration over the next couple years. I appreciate the comments in terms of potential acceleration into 2017.

Should we think about – I mean how should we think about the balance between capital acceleration and debt paydown or balance sheet repair? Should we generally just view it as, you'll pay down debt as debt maturities progress over the next couple years and anything incremental could go into capital acceleration or how do you look at acceleration versus balance sheet repair I guess over the next two years to three years?

R. A. Walker - Chairman, President & Chief Executive Officer

Well let me just reiterate. I mean what we see today is that the maturities in 2017, of which there's approximately $750 million, the monetization proceeds will initially go to that. And then as we see what we believe to be an improving oil price scenario, for the reasons I've outlined, then the two principal onshore basins of DJ and Delaware is where we would anticipate, if there is good economics, good cash cycle and capabilities, that we would – that's where we would put our additional expenditures and additional capital. And maybe with that in terms of just – if there's questions around the debt, I'd be happy to let Bob address those. But if there's additional questions on the debt, is that part of what you're asking me?

Ryan Todd - Deutsche Bank Securities, Inc.

Yeah. I mean I think the general view is just how should we – I mean I think you have a longer term target to get to – to get back to kind of a 30% debt-to-cap ratio I believe. And so how do you think about, as you look forward over the next few years – and I get that this is highly dependent on oil price as well. But how do you think about your ability to accelerate, versus a desire to eventually kind of get the balance sheet back into kind of long term target ranges?

Robert G. Gwin - Executive Vice President-Finance & Chief Financial Officer

Well we use a variety of metrics beyond just debt-to-cap. And debt-to-cap is somewhat less relevant, the old targets are somewhat less relevant, given that with the way that commodity prices have backed up, we and everyone else have taken a lot of write-downs of assets on the balance sheet that have affected that – what that debt-to-cap number might look like in the future.

But when we look at debt-to-cash flow in particular, and we look at debt per barrel and producing barrel, it is – we feel that the balance sheet is not that far out of whack of where we'd like for it to be. The difference versus the past is that we don't expect a commodity price recovery to, I don't know, $90, $100 oil [per barrel], whatever we were facing at a point in time when debt-to-EBITDA metrics across the industry were so much lower.

And so the way we're looking at it is to try to match our pro forma metrics to our pro forma activity levels. And that pro forma commodity price, as Al mentioned, where we go back to work. So it's a bit of a moving target.

Now what we know with certainty we'll do is take – is repay the $750 million of debt that we've stated publicly repeatedly that we are going to repay at the 2017 maturities. And we believe that there should be an opportunity to reduce gross debt further through some liability management programs around many of our smaller, less liquid issues. But in many cases, the holders are very happy with those issues. And we certainly wouldn't expect to pay a material premium just to retire them.

We do have a put bond out there that is not callable. But it's puttable to us once a year. Certainly there, you can negotiate around some of that type of debt, if we wanted to take our gross debt number down further. But it's our clear intent, as we've stated in the past, to continue to build cash and to ensure that we're reducing that net debt number. That we continue to remain focused on liquidity. And we're very comfortable that the liquidity position, the leverage position allows us to accelerate drilling, should the commodity price warrant it.

But to accelerate within reason. We're talking in the hundreds of millions of dollars, not massive changes of outspending cash flow. We're pretty close, even at current discretionary cash flow, to spending within discretionary cash flow.

So the delta here is asset sales. If we're successful with asset sales the way we have been, then it gives us a lot of flexibility, based on the commodity environment and outlook that we see at the time, to moderately reduce leverage, consistent with that commodity price environment. And to moderately accelerate spending in places where we have really attractive returns, to begin to move our production back toward growth and away from maintenance.

Ryan Todd - Deutsche Bank Securities, Inc.

That's very helpful. I appreciate all the detail on that. Maybe if I could follow up on some of the – on a previous question on the Delaware Basin. We've seen great results out of you guys across the Wolfcamp. And you had 11 10,000-foot long laterals I think in the Wolfcamp that you brought on so far. Can you talk a little bit about what your – how much running room you think you have in terms of acreage that's conducive to 10,000-foot laterals?

And then maybe as a follow-up to that as well on the Second Bone Springs and the Avalon, any rough estimates as to how much of your acreage that those horizons might be prevalent across?

R. A. Walker - Chairman, President & Chief Executive Officer

Well let me just start with our focus is clearly going to be the Wolfcamp. And we've got a lot of our acreage that is conducive to at least mids and in many cases longs, but surely not all of it. And we'll continue to look at ways in which we can sort of trade acreage and build that land position, such that we can go with the longer laterals.

But I think what you've seen over time is we started with many of the shorts. And today our average is closer to the mids, only because we've been able to do a number of longs, some mids, and some shorts. And so clearly it's beneficial for us to do the longer laterals where we can. And we're looking at every opportunity where we can, like I said, trade acreage, maybe such that we can get in that position.

As far as Avalon and Bone Springs, again I'd just reiterate, we're not focused on as much that right now. We've done some Bone Springs. But clearly our prize is the Wolfcamp today. And whatever land position we create ourselves for the Wolfcamp, we'll get the benefit in both Avalon and Bone Springs.

Ryan Todd - Deutsche Bank Securities, Inc.

Perfect. Thank you.

Operator

And our next question comes from Brian Singer of Goldman Sachs. Please go ahead.

Brian Singer - Goldman Sachs & Co.

Thank you. Good morning.

R. A. Walker - Chairman, President & Chief Executive Officer

Morning, Brian.

Brian Singer - Goldman Sachs & Co.

Wanted to follow up on some of the Wolfcamp questions here. Can you just give us a bit of a lay of the land on how pervasive over your acreage is the 12 wells per section from a development perspective? Are there areas that aren't prospective? Or are prospective at fewer than 12 wells per section? And then in the Lower Wolfcamp, what's the timing and potential aerial significance from the testing that's currently ongoing?

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

Yeah, Brian. This is Darrell again. As we look at it today – and understand that a lot of the drilling we're doing is to make sure we understand our entire acreage position. But if we – if I had to give you a number today, I'd say at least three-quarters of our Wolfcamp position is what we would consider tier one and would have at least 12 wells per section.

I mean some of that's going to be driven by economics. And so as prices go up, we may find ourselves with a lot more wells in those sections beyond the 12. Because you could understand there's many benches inside the Wolfcamp. So as demonstrated on that one sheet, we're basically talking four wells per bench. But it clearly could be more than that.

Brian Singer - Goldman Sachs & Co.

Great. And the Lower Wolfcamp testing, how aerially significant would that be? And what's the timing there?

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

In the case of the Lower, it's not as nearly as prolific as what we see as the Wolfcamp A. But again we hadn't done as much testing there. But clearly it's going to be one of our targets in the future as well. But if you look at the Wolfcamp A, in our case we've got many benches in there. So it's our primary target

Brian Singer - Goldman Sachs & Co.

Great. Thanks. And, Al, you highlighted your optimism for oil prices next year and your hope and interest in bringing back activity. Can you talk more specifically about what you're looking for to make that decision to bring production back on? How much of it would be based on your own projections for commodity prices, versus either real-time inventories, what the forward curve is saying or the front month price? Particularly given the lead time till you actually see that production come on from pad drilling?

R. A. Walker - Chairman, President & Chief Executive Officer

Well I'll give you my thoughts, Brian, on that. And it's simply as we see U.S. oil production cascading towards that 8 million barrels a day that I made reference to in terms of where I think it will bottom out before it starts to go back up. That will in my estimation help a lot.

And if on the demand side we continue to see 1.2 million to 1.4 million barrels per day of demand per annum through the balance of the decade, I think the combination of the two are quite significant. It's been our view that we will see this be a price recovery when it's demand-driven, rather than supply-constrained. Market forces don't work real well when you're relying on supply constraints to drive price.

But I think if you think about it as a demand function that improves annually at the cliff of 1.2 million to 1.3 million barrels a day, you can see pretty quickly that in an expanding demand relative to supply, the demand's going to move up the curve. And the intersection that creates P will put pressure on prices to move up to a level of around $60 a barrel.

After that point I mean we're going to have to see what happens from, A, a demand standpoint, B, from a cost. Are we going to see margin erosion? Are there returns and the cycling characteristics that we particularly follow with our onshore investing, are they still going to be as attractive as we thought?

So I'm not going to go beyond $60. But I think clearly in our estimation the ingredients are there for a recovery to sustain $60 price environment for next year. And I've probably been as big a bear around oil price expectations as anyone since early 2015. And I think with this, if we continue to see the characteristics I just laid out continue to be prevalent in the market, that will be a great indication to us as for what we want to do.

Looking at the forward curve, I think you know as well as I do, that's a little fragile. And as you look out further, particularly in light of our – the world we live in today and the lack of real – the lack of players in the market for the forward curve, it looks flat for a reason. Because we don't have the same participants in the curve today that we had five years or certainly 10 years ago.

So the curve itself probably is not going to be as much of an indicator of activity as the other things I just made reference to.

Brian Singer - Goldman Sachs & Co.

Great. Thank you.

R. A. Walker - Chairman, President & Chief Executive Officer

You bet.

Operator

And our next question comes from David Tameron of Wells Fargo. Please go ahead.

David R. Tameron - Wells Fargo Securities LLC

Great. Al, can I just go back to that $60 number? You had previously said margins were kind of what drive your decisions. So can you talk about if we're in a $60, would you expect service costs to close that gap on the margin? Or how should we think about that dynamic?

R. A. Walker - Chairman, President & Chief Executive Officer

David, I may very well be wrong, but I don't see from, call it $43 today to $60, a lot of service cost price inflation. I do think as we approach $60, we will start to see it, depending upon the activity in the principal basins that would be driving our U.S. oil price – or U.S. production.

We're just continuing I think as an industry to see price concessions on service costs today. I think it will take a while for activity levels and the use of services to put a lot of pressure on having service costs go up. At some point service costs will go up. But I think as you think about it and the way I think about it, from a margin perspective we don't anticipate a lot of wellhead margin erosion between here and $60.

David R. Tameron - Wells Fargo Securities LLC

Okay. That's helpful. And then back to the Delaware. One of the concerns I guess has been capacity and constraints and ability to get production out of the basin. I look at your numbers, and it looks like you exited at a higher rate than you averaged for the quarter. Can you just talk about how much running room as far as just pipeline capacity and takeaway and infrastructure, of debt limits? And I'm just thinking later this year if oil heads back to $60, how much more room do you have to allocate into the Delaware?

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

David, this is Darrell. At this point we see no constraints. We haven't seen a sign of it. And we don't expect to. I think there's a lot of systems being built out. I know inside West (36:04) we're expanding our capacity every day. So we don't see that to be a problem any time soon.

David R. Tameron - Wells Fargo Securities LLC

All right. Thank you.

R. A. Walker - Chairman, President & Chief Executive Officer

Thanks, David.

Operator

And our next question comes from Paul Sankey of Wolfe Research. Please go ahead.

Paul Sankey - Wolfe Research LLC

Hi. Good morning, everyone. Al, just pulling together everything that we just heard. Firstly, on the 8 million barrels a day that you see the U.S. production level reaching, what's the timeframe for that?

And the follow-up is, it feels and looks very much from this result as if you balanced now cash flow, CapEx with flat volumes at around $45 to $50 a barrel. Firstly, if we do go lower than that, is there more to do? Or do we simply actually restart raising debt? And secondly, if we progress as you anticipate from $45 today, -ish, to $60, is that move then a debt pay down move until you restart growth at $60? Or is there a sort of progression in there? Thank you.

R. A. Walker - Chairman, President & Chief Executive Officer

You bet. Well let me try to take those as best I can. It's the timing for 8 million barrels a day – I'm no better at projecting that than a lot of people that are paid money just to do that by themselves in a vacuum of their own faults. But our view is it could happen as early as late this year. And that's why we made – I made the comment earlier we think it's likely that we could see a sustained price environment of $60 developing later this year.

Now if for reasons that I can't quite explain, but it takes a little bit longer to get to 8 million, that could get pushed into 2017. But you know better than I do how capital intensive our industry is, particularly for unconventional development and the sustaining of production levels. And we as the industry have not been investing at a level that allows production to be held flat.

Just exactly how fast it cascades is sort of a question I think each of us need to watch. But my comment to you would be I think it could be as early as the fourth quarter. And that's the basis by which I'm making my comments. Because I still see the demand side, using IEA as the basis for that, with having 1 million to 2 million – maybe 1.2 million to 1.4 million barrels per annum of additional demand.

It will be a demand recovery, not a supply recovery. And it's really the basis of that demand expansion or the large and increasing portion of the pie that I think will give us some comfort around how that actually will be sustained.

As it relates to capital planning, you're right. This is not a step function. It's not linear. And it's probably more likely logarithmic. As we approach $60, we'll invest more than we will at $43-ish in terms of where WTI is today. So we're already sort of telling you today that we anticipate with improvements that we think are forecasted, that we will start to reallocate some of our monetization proceeds, as we've described on this call.

I think if we – as we get into our planning for capital for next year and think about that in conjunction with the discussions with our board, the more we feel comfortable about that sustained $60 price environment, the more likely you will see us increasing capital, particularly in the areas that we're talking about on the margin, increasing capital too in anticipation of a price recovery. I hope that helps.

Paul Sankey - Wolfe Research LLC

Yeah. Thank you. And then...

R. A. Walker - Chairman, President & Chief Executive Officer

You got a question about – I'm sorry. You had a question about debt, and let me let Bob in for that.

Robert G. Gwin - Executive Vice President-Finance & Chief Financial Officer

Paul, there's one thing I want to point out though, is you asked if prices move the other way, if we're wrong and prices go down, does that mean we increase debt? Absolutely not. In fact, we continue to reduce debt through the asset monetization proceeds. So prices go down, the asset monetization proceeds go to debt reduction. As prices go up, we first reduce the debt along the lines I described earlier. And then we start to put the dollars back to work the way Al just described.

Paul Sankey - Wolfe Research LLC

Helpful. Thank you. And then the follow-up, the obvious follow-up is just can you talk about hedging in all that? Thank you.

Robert G. Gwin - Executive Vice President-Finance & Chief Financial Officer

Yeah. We've – as you guys saw in some of the information, we layered in some gas hedges that I think if you look at the structure, those three-way collars, it starts to inform as to our views on natural gas, which are not particularly bullish. But we think we've left ourselves some upside to benefit, in particular with our associated gas production that remains a pretty significant part of the portfolio.

We have not focused on layering any oil hedges. We don't like the structure of the market today to go ahead and lock in prices at all. And we've never looked at hedging as a way to justify drilling activity at any given price. We've instead looked at hedges as a way of providing some moderate protection to the balance sheet and reducing the volatility of our cash flows relative to the commodity price environment.

So as we've done historically, we'd probably like to layer in some oil hedges in the – at the right price, when we like the shape of the curve. And I think from a gas standpoint, whether we do any more or not, just also remains to be seen. We're pretty comfortable with what we got done for 2017 at this stage.

Paul Sankey - Wolfe Research LLC

Thank you. Helpful.

Operator

And our next question comes from John Herrlin of Société Générale. Please go ahead.

John P. Herrlin - SG Americas Securities LLC

Yeah. Hi. Just some unrelated ones. You added a new board member. What was the rationale there, Al?

R. A. Walker - Chairman, President & Chief Executive Officer

Well you are one of those people who watches everything, so I really do appreciate that about you. Sometimes when we put press releases out, you wonder if people look at them in any detail, so thanks for the question.

Yeah. We really felt like adding someone like David Constable to our board was very important from a skill set. David's got a long career at Fluor and then later at Sasol with big project management, understanding how big boxes need to be built and how the project management needs to be executed. I think his experience will be quite helpful as we approach and consider the day when we take FID in Mozambique. And he'll also be a wonderful board member for management to be able to go to and use as a resource as we consider that decision.

So I – not to say that we don't have board members today that are helpful in that area. We do. But we recognize the challenges associated with taking FID in Mozambique are fairly significant. And being able to add a board member like David with his skill set, we're very, very fortunate to be able to do that. And thank you, John, for asking the question

John P. Herrlin - SG Americas Securities LLC

Okay. My next one, Al. I appreciate everything you said about margins, but the services companies last week, the big ones that reported, were opining about the need for higher revenues for their offerings. How much of your savings, especially onshore, do you think will be sustained, because of the change of process and design going forward?

R. A. Walker - Chairman, President & Chief Executive Officer

Well I'm going to take this in part with Darrell. Because some of the process changes are going to be able – are going to be such that we can retain some of the efficiencies that we have today. In certain fields it's going to be very high, such as the Delaware – I mean the DJ Basin.

But I think what we're seeing, John, is that it's still a fairly aggressive service environment for what the service providers need and want in the way of market share. And we've got a new participant back in that market, given the unsuccessful consolidation of Halliburton and Baker Hughes. And I think you just have to appreciate in the near term that is a new dynamic into the marketplace that was not there earlier this year. And, Darrell, with that why don't you please take it to the next step?

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

Yeah, John, if I had to guess I would say we're going to at least maintain two-thirds of what we've been able to achieve. If you just recall what we've gone through almost every quarter is we continuously are finding more efficient ways to drill and complete these wells. And even the facility side we're getting better at that.

And so no doubt the cost structure coming down has helped, but our efficiencies has probably been the biggest driver. And with that I would say that just because we're here today doesn't mean we won't continue to find different ways to increase our efficiencies in what we're doing to help offset any pressure we may see going forward.

John P. Herrlin - SG Americas Securities LLC

Great. Thank you.

R. A. Walker - Chairman, President & Chief Executive Officer

Thanks, John.

Operator

And our next question comes from Arun Jayaram of JPMorgan. Please go ahead.

Arun Jayaram - JPMorgan Securities LLC

Good morning. I was wondering if you guys could give us an update on the TEN Project in Ghana? As well as maybe some of your gross volume expectations for 2016 and 2017? And any potential impacts from development from the border dispute?

James J. Kleckner - EVP-International & Deepwater Operations

Arun, this is Jim. As you've seen in the public release on the TEN project, they're about 97% complete with the hookup and commissioning of all aspects of the TEN development. The project is progressing very well. And initial production should begin early in the third quarter.

It's anticipated that the field will be brought online and start the sequencing, commissioning of water injection and production operations and ramp throughout the second half of the year. So we see the TEN Project on schedule and meeting expectations.

Arun Jayaram - JPMorgan Securities LLC

And, Jim, just the – kind of the volume expectations that you expect in the back half? And then 2017 just from a growth standpoint?

James J. Kleckner - EVP-International & Deepwater Operations

Well I think the TEN production volumes will ramp up as the operator has stated. And it's going to be a slow initiation of that production as they first bring on in the Enyenra field and then the Ntomme field and followed up by the Tweneboa field later on. So we'll have to see how that ramp up in production goes.

Arun Jayaram - JPMorgan Securities LLC

Okay. Fair enough. My second question is just regarding – and wonder if you guys could provide a bit of color on DUCs versus IDUCs. I know looking at the ops report, you tied in 40 wells in the Eagle Ford. And in the first half of the year you've been running one and a half rigs and tied in about 137 wells in the Wattenberg. I was just trying to understand if you can help us delineate between DUCs versus IDUCs, and where your IDUC balance stands today?

R. A. Walker - Chairman, President & Chief Executive Officer

Arun, are you telling me you didn't go look up in the standard Webster's dictionary the difference in those two?

Arun Jayaram - JPMorgan Securities LLC

I know it's given Colglazier a lot of fun, IDUCs versus DUCs.

R. A. Walker - Chairman, President & Chief Executive Officer

Yeah. Well yeah. At some point Webster's will include it in their dictionary I guess. But for now I understand the question. So yeah. Let me turn it over to Darrell, all being jocular aside.

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

Yeah, Arun. We quoted these IDUCs, and I think we came into the year with about 230. And I would argue we still have roughly the same. You look at something, to your point at Maverick. A lot of that had to do in the – it was more of a cost-saving measure. And a lot of this was done actually in 2015. And we took the opportunity to tie back to some of the existing equipment, as opposed to building new. And so some of that got delayed. And that's what you're seeing there. It really didn't affect our numbers.

But I think from a practical standpoint, to address your issue on IDUCs, we've got other wells that we usually have in the queue in terms of they're drilled and uncompleted. And so we have probably in excess of 500 wells like that.

And so I think from a practical standpoint, as Al was suggesting, as we look forward into the end of the year and into next year, and we have the opportunity to stand up rigs and additional crews, you will see that all of that really becomes the inventory in which we'll work off of. And in some cases it has to do with simultaneous operation. Some of it is going to have to do with what we want to test, so that we can learn additional information in places like the Delaware.

And so I think again looking forward, I would just look at it from the standpoint we've got about 500 wells in inventory like that, that we'll be using as we increase our programs going forward.

Arun Jayaram - JPMorgan Securities LLC

That's extremely helpful. Thanks a lot.

Operator

And our next question comes from Matt Portillo of TPH. Please go ahead.

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Good morning, guys. Just two quick questions on the Delaware Basin. First, just wanted to talk a little bit about the completion design change. You guys have made fairly significant strides in optimization since 2014. And I was wondering if you could talk about from a high level perspective the impact of your expectations from an EUR perspective within the Wolfcamp? I think the last kind of fulsome update we saw was really around early 2015. And then there was some discussion in the press releases around that EUR progressing higher late last year. I was just curious around the current design and thoughts on the rate of change on the EUR side?

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

Yeah, Matt, I'd say it's fair to say we have made a lot of improvements. But I tell you, we're learning all the time. We're in the midst right now of a 20-well test, if you will, all in one particular area where again the reason for the test is more for the completions than the drilling side of it.

And so we still have a lot to learn. But as we vary some of these stages, some of the sand we're pumping, even some of the water we're pumping in these intervals, we're learning all the time. But I think it is fair to say as we've got additional production data, we do feel the EURs continue to increase.

And so as I pointed out last year, a lot of these wells that have been online now for a while, we're seeing 800,000 to 1,000,000 barrels a well, so we're feeling really good about that. But there's still a lot to learn. And understand, we've got a huge acreage position. So we're going to see some variance across this as well.

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Great. And then just a follow-up question in regards to the Avalon. I was wondering if you could talk about the growth column that you see perspective? Where you've delineated that so far? And if there's any current plans this year to further delineate the play, potentially with the higher intensity fracs?

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

As far as the Avalon, you won't see us doing any more work on that this year, to my earlier point. In a lot of cases where we're preserving our leases, we've got to really drill down to the Wolfcamp. And that's really our big prize.

What we've seen in the past is these wells are sort of on the order of 1,500 BOE per day wells, 800,000 barrel EURs. So we think this is really going to be a productive area. But you're just not going to see us playing it any time soon.

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.

Great. Thank you very much.

Operator

And our next question comes from James Sullivan of Alembic Global Advisors. Please go ahead.

James Sullivan - Alembic Global Advisors LLC

Hey. Good morning, guys. Thanks for taking the question. Just a quick modeling one. You guys have obviously talked about Tullow's plan to permanently moor the Jubilee. And I guess that's a 2017 project. And I think you guys talk about deferring some El Merk maintenance into 2017 as well. You're deferring it from this year. Can you guys quantify at all the impact to your international oil from those two pieces of maintenance happening maybe at the same time, sometime in 2017?

John M. Colglazier - Senior VP-Investor Relations & Communications

Yeah, well we're still – this is Colglazier. We're still working through our 2017 guidance levels, based upon incorporating the information we got from Tullow on the timing of Jubilee, et cetera. You'll have the ramp-up as TEN, as Jim just talked about. And El Merk – and at El Merk re-evaluating the timing on when we need to do that turnaround.

I think if you look at what happened this year, I think the aspect of both the U.S. onshore, offshore, and Algeria have largely offset the entire impact we've seen from Ghana, which is pretty darn amazing.

So when we look at our aggregate crude production, we're still going to be relatively flat on a divestiture adjusted basis, both on a full year average as well as an exit rate. And as we move into next year, I think we're pretty well situated. And that only improves if we allocate incremental capital to our growth plays in the U.S.

James Sullivan - Alembic Global Advisors LLC

Okay. Great. Thanks. Appreciate that. Just another one that's sort of a strange question. But when you guys talked about the tieback opportunities that you have in the Gulf of Mexico, you guys gave us a couple different cuts on your capital program. You do it by area, but then also between base maintenance and the different cycle time projects. When you guys think about the tiebacks, do you categorize those as base maintenance or as development work?

John M. Colglazier - Senior VP-Investor Relations & Communications

It's embedded in our maintenance capital, because we need the volume contributions from those to help maintain our aggregate volume levels.

James Sullivan - Alembic Global Advisors LLC

Got it. Okay. Great. That's just what I was looking for. Appreciate it. Thanks, guys.

Operator

And our next question comes from Jon Wolff of Jefferies. Please go ahead.

Jonathan D. Wolff - Jefferies LLC

Hey, guys. Saw that you brought on a lot of wells in Maverick Basin and Eagle Ford in the second quarter, but no drilling activity. Wondering, thoughts around that asset? Production has stayed fairly flat. And then maybe the same question around Northern Louisiana, Chalk (53:56), where the activity levels are fairly low. Any thoughts around the positioning of those assets as you see them longer term in the portfolio?

R. A. Walker - Chairman, President & Chief Executive Officer

Jon, this is Al. Let me take part of it and let Darrell take part of it. Good question, good observation.

I think as it relates to Maverick right now, as you think about it from a portfolio standpoint, the Maverick Basin, the Eagle Ford Shale doesn't compete for capital as well as the other two basins we've been talking about this morning.

That doesn't mean that it doesn't create attractive rates of return. It just unfortunately is up against two exceptional assets that create better rates of return. And for a company that's trying to stay close to or on top of discretionary cash flow with CapEx, it just unfortunately as a result of that doesn't feed on capital and constantly is not being unallocated capital. So that would be the takeaway there. Darrell?

Darrell E. Hollek - Executive VP-U.S. Onshore Exploration & Production

Yeah, Jon, again the only comment I'd make is we did complete some wells in the first quarter. But the bulk of them were actually completed last year. And the reason that came on in the first and second quarter, a lot of that had to do with trying to tie back into existing infrastructure, as opposed to building new (55:19 – 55:21) wells. So it got delayed a little bit. But if you look at us today, we have no rigs, no completion... [Abrupt End]

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