Anadarko Petroleum (APC) Q4 2018 Earnings Conference Call Transcript

Anadarko Petroleum (APC)
Q4 2018 Earnings Conference Call
Feb. 6, 2019 9:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants
  
  See all our earnings call transcripts.

Prepared Remarks:

Operator

Good morning, and welcome to the Anadarko Petroleum Corporation fourth-quarter 2018 earnings conference call. [Operator instructions] Please note, this event is being recorded. I would now like to turn the conference over to Mike Pearl, senior vice president of investor relations. Please go ahead.

Mike Pearl -- Senior Vice President of Investor Relations

Good morning. We're glad you could join us for today's conference call to discuss 2018 results and our 2019 outlook. Today's presentation includes forward-looking statements and certain non-GAAP financial measures. We believe our expectations are based on reasonable assumptions, however, a number of factors could cause results to differ materially from what we discuss.

We encourage you to read our full disclosure on forward-looking statements in our SEC filings and the non-GAAP reconciliations located on our website and attached to yesterday's earnings release. Additionally, we have posted our 2019 investor book and fourth-quarter operations report on our website. After opening remarks from Al Walker, we will open the call for Q&A. Please direct any detailed modeling-type questions to the IR team after the call so that we can focus the Q&A on strategy-related topics, since there were no changes to the guidance that we provided last November.

With that, I'll turn the call over to Al for some opening remarks.

Al Walker -- Chairman and Chief Executive Officer

Thanks, Mike, and good morning. We thought we would spend some time this morning reemphasizing our philosophical view of Anadarko's business and how we think it is competitively positioned to support the goal of delivering cash returns to investors. Before we do that, I will briefly discuss our 2018 results within the context of the performance metrics we put in place last year to better align our company's performance with investor expectations. Anadarko performed well against performance metrics in 2018, particularly with regard to safety and environmental performance and our cash returns metric, where our cash flow return on invested capital exceeded 25%.

We were outside of the capital guidance for the fourth quarter and for the full year as we continued to see an increase in non-operated activity and highly economic non-consent opportunities. Non-consents in the Delaware basin are some of the most attractive acquisitions we can make given the performance of these wells. This dynamic combined with additional leasehold acquisitions resulted in about $175 million of additional capital in the fourth quarter. We have incorporated our 2018 experience for both non-operated and non-consent activity into our capital range for this year to reflect these trends and expect similar investment opportunities in 2019 will fall within our announced capital range as the midpoint of $4.5 billion is equal to our actual 2018 E&P capital spending.

Finally, while our fourth-quarter volumes were within guidance, our financial results were impacted by the significant and rapid decline in commodity prices in the fourth quarter, specifically NGL prices. Lower realized NGL prices are most apparently reflected in our NGL sales revenue and GPM margins. As we look at 2019, there are couple of things to keep in mind. First, we remain committed to returning cash to investors.

Last year, we delivered peer-leading cash return results to investors, and we will continue this dynamic going forward. And second, we have positioned our portfolio to support our durable strategy with a diversified mix of oil-levered high-margin assets that are capable of generating free cash flow and attractive returns in the $50 oil environment for both WTI and Brent. With the exception of the Delaware basin, all of our major operating assets are significantly cash flow positive today at $50 oil. At that price, we expect the Delaware basin to be free cash flow positive in 2020 as we are already seeing the benefits of operatorship captured and the establishment of our integrated midstream footprint.

I will provide an overview of our entire portfolio in a few minutes but we believe we are exceptionally well-positioned today and into the future to deliver on our commitment. Since we have announced our share repurchase and debt reduction programs in September 2017, we've returned more than $4.5 billion to investors. We've repurchased more than 65 million shares of Anadarko common stock, which represents just under 12% of total shares outstanding at the inception of the program. Debt has been reduced by more than $600 million, and we've increased our dividend by 500%, and there is more to come in 2019.

We ended 2018 with approximately $1.3 billion of cash, and expect to strengthen this position in the first quarter of 2019 when we close our previously announced $4 billion Midstream asset sale to Western Gas. This transaction will provide us with cash proceeds of $2 billion, along with an additional two billion of Western Gas units that will increase the expected cash distributions that we will receive to more than $600 million per year. These proceeds, combined with our portfolio's ability to generate cash flow, our cash position and the $8 billion of marketable securities we will hold post-closing, provide confidence in our ability to complete the remaining $1.25 billion authorized share repurchase and $1.4 billion debt reduction programs by mid-2020, as well as meet any incremental funding needs associated with Mozambique LNG post-FID. Our continued philosophy of investing within discretionary cash flow and a $50 oil environment and returning free cash flow above that level to investors is a durable long-term strategy.

While Anadarko's portfolio is free cash flow neutral at $50 oil, we add approximately $140 million of free cash flow for every dollar oil prices increased above $50 per annum. This oil price leverage enables us to generate a similar free cash flow yield to an S&P 500 at a mid-$50 oil price, with higher oil prices generating free cash flow yields significantly in excess of the S&P benchmark. As you can see in this graphic, even with a static commodity price assumption and the addition of dividends to our expected capital expenditures, we aim to attractively drive down our portfolios all-in cash flow breakeven oil price over time. Our portfolio allows for this capital efficiency by directing capital to maximize long-term free cash flow, delivering capital-efficient investments, harvesting stable free cash flow from our high-margin conventional assets, transition the Delaware basin to positive free cash flow and increasing our leverage to premium oil market.

It is worth highlighting, 55% of our fourth-quarter sales volume benefited from premium oil pricing, and we expect that number to increase to 70% after the Cactus II pipeline is in full service. As free cash flow materializes, we will prioritize additional share repurchases, debt reductions and dividend increases to fulfill our commitment to return cash to investors. I'd like to now turn your attention to our diversified and complementary portfolio that makes our commitment to returning cash to investors sustainable. Our conventional oil assets in the Gulf of Mexico, Algeria and Ghana provide approximately $2 billion of stable free cash flow at $50 oil.

Our conventional assets feature low-development breakeven prices, waterborne pricing and low-maintenance capital. These assets provide us with a competitive advantage and a source of resilient cash flow throughout the cycle. Steady free cash flow from our conventional assets supplements our investment into highly economic short-cycle opportunities within the U.S. onshore business, where we enjoy substantial scalability due to our premium acreage positions in the Delaware and DJ basins today, and in the Powder in the future.

These basins contain decades of cash flow enhancing inventory, supported by our midstream MLP that ensures APC's access to extensive infrastructure that provides flow assurance. Additionally, our U.S. onshore production has economically enhanced the base takeaway to premium markets along the Gulf Coast, as well as to export markets globally. We are extremely pleased by the strength and resiliency of our existing asset mix and are excited about our emerging assets, which represent future cash-generating additions to our portfolio.

As I have mentioned, the Powder River Basin is a coming attraction. This year, we plan to conduct an appraisal program on our recently built 300,000 gross acre position in Converse County, Wyoming. As you have heard from us and industry, this basin holds significant opportunity and attractive oil production characteristics. Outside the U.S., the Mozambique LNG project is nearing a final investment decision.

This portfolio development opportunity should have a game-changing impact on our company and in Mozambique for decades to come. Recent announcements of executed long-term sale and purchase agreements underscore the viability and credibility of this project. Offtake agreements with major Asian and European customers totaling more than 7.5 million tons per annum have been executed, and we have agreed to key terms for an additional two million tons, which we expect to convert to SPAs in the very near future. This combined with a number of milestone achievements in 2018 has positioned this world-class LNG project for a sanctioning decision in the first half of this year.

At that time, we will share additional detail around this opportunity. For now, I will note the following: a massive gas resource is already in place; offtake with premium buyers is already secured; and a very reasonable and manageable equity investment is required given our portfolio, balance sheet strength, liquidity and the project finance market's expression of interest to finance up to two-thirds of the project's cost. Much more to come on Mozambique over the next few months as we provide detail on this project's ability to deliver another source of resilient free cash flow to support our long-term goal of returning cash to investors. In closing, we've demonstrated our strong commitment to cash returns to investors, build the portfolio to generate free cash flow at low breakeven oil prices and have shown the depth of our portfolio to return cash to investors for years to come.

With that, I would like to thank the Anadarko employees for their hard work and long hours and delivering the strong results in 2018, and we look forward to taking your questions. 

Questions and Answers:

Operator

[Operator instructions] And our first question comes from Arun Jayaram of JPMorgan. Please go ahead.

Arun Jayaram -- J.P. Morgan & Co. -- Analyst

Good morning, Al. I'll table some of my questions on Mozambique for a little bit later. But I wanted to start a little bit in the Delaware Basin and with the Silvertip results which you highlight on Page -- Slide 16. Could you talk about some of the key learnings from the four different Wolfcamp A targets? And we noted that the wells kind of in the middle of the interval are outpacing some of the ones toward the upper and lower part.

But just if you could provide the key learnings from Silvertip?

Al Walker -- Chairman and Chief Executive Officer

Thanks, Arun. I think I'll have Danny address that, if you don't mind. But appreciate the questions. So, Danny, would you please?

Danny Brown -- Executive Vice President, U.S. Onshore Operations

Sure. Thanks for the question, Arun. Super happy to provide the Silvertip results. I'd say, we've been very, very pleased with what we've seen come out from that development.

The wells that you're referencing was referred to as Targets 2 and Targets 3 on the graph that we provided, represent what we term internally as the beta interval of our Wolfcamp A zone. It is the bread and butter of our program moving forward. So this represents the lion share of our Wolfcamp -- by far, the lion's share of our Wolfcamp activity. And what Silvertip did was really, I think, confirm our beliefs about the productivity of that zone.

So the results from that Target 2 and Target 3 were absolutely fantastic. Similarly, very pleased that some of the secondary targets in the extreme upper part of the Wolfcamp A and then our Target 4, which is down at the very lower part of the section almost in a Wolfcamp B zone, also performed essentially at or above our type curve expectations for our general Wolfcamp A target. So those were great confirming tests as well. We also had a good Bone Spring test, where we saw great production above our Wolfcamp A type curve there, too.

So very happy about the performance we've seen from Silvertip, and importantly, that beta zone performed just absolutely in a stellar fashion for us. And we're looking forward to continuing with that development over the course of the year.

Arun Jayaram -- J.P. Morgan & Co. -- Analyst

Great. And just my follow-up, Al, regarding some of the regulatory headwinds that the company and DJ Basin operators have faced over the past few years. I was wondering if you could comment if the industry has engaged with the new governor to come up with the solution here. We do understand that the Secretary of State is holding a hearing today on severance taxes on oil and gas, but any thoughts that you have in terms of this regulatory headwind, which has impacted clearly APC in 2018?

Al Walker -- Chairman and Chief Executive Officer

Arun, very understandable question. And probably like you, I see a lot of different media reports, and we're following those likely just as closely as you are. But then understanding that the legislature and the governor are working to try to come up with something they both feel comfortable with. I don't have any additional insight beyond the media reports, and we look forward to seeing what both the legislature and the governor want to do in the days ahead.

Arun Jayaram -- J.P. Morgan & Co. -- Analyst

Great. Thanks.

Al Walker -- Chairman and Chief Executive Officer

You bet.

Operator

Our next question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Thanks, sir. Good morning, everybody. Al, there was an interesting comment in your release last night about maximizing per barrel margins. And I'm wondering if you could speak to what looks like a little bit more of a pivot toward the Gulf of Mexico versus onshore.

I'm thinking, obviously, that's a play on Brent level barrels versus onshore discounted oil. I'm just wondering if you could speak to whether that's -- that is deliberate? And if so, how should we expect the relative activity to move in the Gulf going forward?

Al Walker -- Chairman and Chief Executive Officer

Well, Doug, good morning. And it's nice to have an operator finally pronounce your name correctly or your last name correctly. So that's positive. I'm going to ask Ben to try to address just exactly how that's looking in our numbers.

I wouldn't call it philosophically a pivot that's -- as you described. I think we see it more as this year being continuation of '18 both from the standpoint of how we're thinking about investing capital and the way in which we anticipate the asset that's performing. But, Ben, if you would maybe take a couple minutes and address the question Doug posed?

Ben Fink -- Executive Vice President, Finance AND Chief Financial Officer

Sure. Good morning, Doug. I would characterize that per margin improvement less as a pivot and more an intense focus on cost reduction and increasing premiums by getting more Delaware barrels to the coast. Remember when Cactus II gets online, we'll have the majority of our onshore barrels getting premium pricing, whether Houston, Poseidon, LLS, etc.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

OK. It's just, I think, in the November presentation you talked about seven to nine wells in the Gulf and obviously you're now talking about 10. I just wondered that was a modest uptake, obviously, but that's fine. My follow-up is I'm afraid it's also a Colorado question.

I'll -- it's a slightly different question though. Clearly, your -- our friends over at Noble talked about a five-year permanent line of sight to try and circumvent some of the risks of every two years having a political overhang. I'm just wondering, from Anadarko's standpoint, what dialogue are you having with local government or with the governor? Or however way you can provide greater surety on your ability to continue to execute there without having this problem if you like proceed every two years.

Al Walker -- Chairman and Chief Executive Officer

Well, I'll be honest and tell you I'm not that familiar with what Noble's doing so I can't really address that probably in a way that is constructive. I will say that as I indicated earlier with Arun's question, we are watching and listening to what's in the media reports. Sounds like the governor and the legislature are working on things that they feel like they would like to address largely through legislation. And frankly, they are having their own conversation at this point, and I can't give you a lot of additional insight other than the fact that it seems like from everything I read, Doug, and I try to read as much as I can, that they're looking for something that is more of a permanent fix.

One that doesn't have as much every two-year cycle to it. And I think that's just the coming attraction. We're just going to have to wait and see what the governor and legislature want to do.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Great stuff. Thanks for taking the questions.

Al Walker -- Chairman and Chief Executive Officer

You bet. Thank you.

Operator

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

Brian Singer -- Goldman Sachs -- Analyst

Thank you. Good morning. I wanted to go back to the Delaware and you talked earlier about the Silvertip results. Can you just talk more about how the strong Silvertip results translate into overall production growth? And then specifically, can you talk to the timing and the dynamics of the timing of growth as we move through the year and in the fourth quarter of last year? And then broadly, if you see the differentiation from Anadarko in the Permian being more on the well performance side from areas like Silvertip or more on the financial results total production and cash flow?

Al Walker -- Chairman and Chief Executive Officer

Well, thanks. I appreciate the question, Brian. And I think a combination of Ben and Danny probably is appropriate here. I think what you heard us say in November is being consistently applied this morning with our comments, and the growth as we've talked about before is an output of our model not an input.

The performance in the Delaware continues to do a lot of the things we anticipate and maybe Danny can address that part of the question, and I'll have Ben reflect a little bit on your thoughts around the financial impacts. So, Danny, why don't you start, and, Ben, why don't you conclude.

Danny Brown -- Executive Vice President, U.S. Onshore Operations

Great. Thanks, Brian. From a Delaware overall performance standpoint and the incorporation of the Silvertip results and what we're thinking about overall development plans in growth rates, I'll say from a fourth-quarter standpoint, we're sort of right on target with where we thought we would be. With Delaware, I think we had guided to a 70% annual oil growth, and we ended up around 71%.

So spot on from that standpoint. The Silvertip results are clearly great confirmation for us. It's also a lot of great information as we look toward development planning and think about spacing and how we are going to put all of the targets together and build out our development plans across the basin. Those development plans have always been founded upon this Wolfcamp beta zone, and so the fantastic results we've seen from Silvertip help underscore the -- those plans for us moving forward, and we anticipate to see good results from that.

I think it is important to note that as we look through Silvertip and look at the results we've seen in Silvertip, those were flowing into new infrastructure that was essentially empty. And so we had a lot of room to flow those wells and see the maximum performance from them. As we move forward, we will look at how do we optimize our infrastructure across the basin. And so the individual well results we've seen moving forward, we may not see the peak rates that we saw in Silvertip, but that will be because we're maximizing the value of the section and the overall development with the infrastructure that we have in place.

And so as we look for -- toward 2019, the strong results we've seen in 2018 and the trajectory we are on will carry through into next year. I think the performance in the delivery in Delaware, we should see quarter on quarter and then strong annual growth coming out of that basin. So 2018 was a great success for us in that basin. The Silvertip results were very strong, and we look to seeing to continuing that performance in the next year.

Ben Fink -- Executive Vice President, Finance AND Chief Financial Officer

Yes. The only thing I'll add, I think Danny have that well, is it's worth repeating that Silvertip is our very first multi-well pad without infrastructure constraints. So we really are at an inflection point in terms of building our efficiencies. So throughout the year, you'll see those efficiencies grow as you go to more away from operatorship capture and more toward multi-well pad development.

Brian Singer -- Goldman Sachs -- Analyst

Great. And then my follow-up is with regards to Mozambique. As you've highlighted you've taken the executed SPAs up to 7.5 MTPA. Very broadly, could you characterize based on the SPAs you've executed? What type of realized price you would get in a $55 versus $65 Brent price? And then are you looking to add to your contracted and executed SPAs above and beyond the two MTPA that you finalized but not yet executed?

Al Walker -- Chairman and Chief Executive Officer

Brian, thanks. That's a great question. I'm going to ask Mitch here in just a minute to address that little more specifically. But I will say this, we worked really hard over the last couple years to put these SPAs in place.

We're looking at hopefully taking that sanctioning decision to our board soon. And I think also, as we look out and recognize the likelihood of when this build will occur and the market we move into, because we don't have foundational buyers from other LNG projects, as you've heard me say on many occasion, we're kind of agnostic to the contractual terms and have been a little more capable of being flexible around what new buyers in the LNG market want. So, Mitch, maybe with that, if you could take it a little bit further.

Mitch Ingram -- Executive Vice President, International, Deepwater and Exploration

OK. Thanks, Al. And, Brian, just to answer your question with regards to the additional two million tons, obviously, those are deals that we anticipate sort of concluding very soon and we'll indicate that to the marketplace. With regards to additional volumes, we're always looking at opportunities to do that with premium foundation buyers.

So that's really an opportunity basis. They're really as we've indicated for some time our target was 9.5 million tons and that allowed us then to obviously launch project financing in December, and obviously taken us toward FID.

Brian Singer -- Goldman Sachs -- Analyst

And can you add on the realized prices broadly in a $55 versus $65 Brent price with what you think you might get?

Mitch Ingram -- Executive Vice President, International, Deepwater and Exploration

Well, obviously, our pricing is between ourselves and the buyer, and they -- as we've indicated in the past as well, they're all -- typically, they're oil-based pricing, as I've indicated. There's -- we have got because we know the book-based where to go to. We've been able to be quite flexible with what we're doing in terms of some of those gas-related European pricing but the majority is oil price basin.

Operator

Our next question comes from Bob Brackett of Bernstein Research. Please go ahead.

Bob Brackett -- Bernstein Research -- Analyst

Good morning. I had a follow-up on Mozambique. I understand you don't want to talk in great detail. But I'm trying to figure out from the investor book, the net of $2.5 billion capital investment over five years, that is net of project finance, which is about two-thirds project financed.

And therefore, the total $7.5 billion. Am I doing the math right? Or am I missing something?

Al Walker -- Chairman and Chief Executive Officer

Good morning, Bob. And it's a question we anticipated this morning. Somebody wanting to ask us, and I think Ben's prepared to address that for you. Keep in mind that we do plan if we find ourselves reaching and sanctioning decision in the coming months to have a very detailed discussion with investors and the investment communities associated with everything today we might be just a little short of giving you the detail on, because some of that is still work in progress.

So, Ben, if you would.

Ben Fink -- Executive Vice President, Finance AND Chief Financial Officer

Sure. Bob, you're correct. Our average of $400 million to $500 million a year is in fact net of project financing, and we do anticipate project financing to incorporate roughly two-thirds of the total project costs.

Bob Brackett -- Bernstein Research -- Analyst

Great. And if the onshore is $600 a ton, I can sort of back into the offshore cost?

Al Walker -- Chairman and Chief Executive Officer

Mitch, we haven't really given that number. I'm not sure exactly where you are in terms of willing to talk about it. But I'll just save the answer for Mitch, you're close to the right number. And again, Bob, I'll just ask if you would stick with us here for a couple more months and we'll give you a lot more detail.

But, Mitch, anything you'd like to add to Bob's question, feel free to.

Mitch Ingram -- Executive Vice President, International, Deepwater and Exploration

OK, Bob, this is Mitch. Just to give you total cost to look out includes everything from not just beyond onshore cost, which is at $600 per ton, you then add offshore, and we have indicated contractor we've selected. Obviously, the total then includes our project management team, all the financing fees to give us a total capital number. So you can't just back out the numbers that you just described.

So there are other components that are included in the total capital cost.

Bob Brackett -- Bernstein Research -- Analyst

Great. Thanks so much.

Operator

Our next question comes from David Deckelbaum of Cowen. Please go ahead.

David Deckelbaum -- Cowen -- Analyst

Good morning, everyone. Thank you for taking my questions. I just wanted to start -- just a quick housekeeping one on the DJ. The incremental $200,000 per well included in the cost now, can you talk about some of the benefits from those design changes? And what some of that costs being allocated to?

Al Walker -- Chairman and Chief Executive Officer

Sure, David. Some of that is just, as we look at '19 and learn from some of the things we saw in '18, is part of that change. And, Danny, if you would maybe walk him through those, if you don't mind.

Danny Brown -- Executive Vice President, U.S. Onshore Operations

Yes. No, that's great. Thanks for the question, David. Up in DJ, we did -- as you noticed in our book, we did make some changes to our overall type curve.

We've got a blended curve that we're providing now similar to what we got within the Delaware basin, and part of that change is an increase in lateral length, which clearly drives cost up as you have longer footage. In addition to that, we also changed a little bit of the completion style we have in DJ. So we're pumping slightly more proppant than we had historically. And we've also moved to having an all-quiet fleet.

And so what a quiet fleet is, is this is from a completion standpoint. These are specially designed completion crews that have much, much lower noise footprint than would -- than a normal fleet would have. And so with that design comes a little bit of additional cost. We think it's the right thing to do.

Allows us to be good stewards and neighbors within the greater DJ environment. So that quiet fleet change, plus some additional proppant that we're pushing through the system is leading to that increase.

David Deckelbaum -- Cowen -- Analyst

I appreciate that color. And then just had a question around your first-quarter guidance. Obviously, you see the volume impact from lower Algeria and Ghana volumes but sort of the U.S. bands that you come up with at the midpoint, you do show about 2% sequential growth.

The lower band is that would imply a decline sequentially. Is that just based on conservatism around results or nonproductive downtime? Or how are you thinking about the 1Q guide?

Al Walker -- Chairman and Chief Executive Officer

Well, I'm going to ask Ben to address this specifically for you, but quarter to quarter, our business, as you, I'm sure, quite appreciate is never going to be as smooth as people like it to be in their models, and consequently,, whether it's a lifting in a particular country or the things that we're doing in the field, we're looking at on an annual basis, we still believe, for 2019, the guidance we gave the market in November is still a good one. And I think as you think about it quarter to quarter, keep that in mind that we're not taking down the annual number that we guided to in November. So, Ben, if you would?

Ben Fink -- Executive Vice President, Finance AND Chief Financial Officer

Yes. The only thing I'll add is I think your suspicion is correct. There is some conservatism baked in within U.S. that includes both onshore and offshore and so you need to incorporate any type of unanticipated downtime.

And I'll have Danny, if he wants to add anything to that.

Danny Brown -- Executive Vice President, U.S. Onshore Operations

No, I think that's absolutely right. We get -- as you get into the winter months, it's not uncommon to have freezing situations out within the field. So we always like to have a little bit more conservatism in these early month forecast just like we may have some conservatism in summer months within Gulf of Mexico forecast for weather-related issues. And that's not uncommon for us to do.

Generally speaking, I think we -- from a U.S. onshore perspective as we move into the first quarter, as I indicated in Delaware, we're expecting to see great performance out of that asset as we move forward. From a DJ standpoint, as you think about our capital investment over the course of 2018, we had more capital investment toward the beginning of the year. We pulled some completion crews and some drilling activity out of that asset toward the latter part of the year.

So that lack of activity sort of rolls through. You'll see -- I think we'll see differential sort of growth in Delaware versus DJ as we look into the first quarter. And as we front-load a bit our capital program in DJ in 2019, we will continue to see those volumes will roll through the system toward the second and third quarter of next year. So little bit of color on that.

So I think everything from a -- a little bit of conservatism and a little bit of timing of capital investment is at play here.

David Deckelbaum -- Cowen -- Analyst

Thank you.

Al Walker -- Chairman and Chief Executive Officer

Thanks.

Operator

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

Charles Meade -- Johnson Rice -- Analyst

Good morning to you and your team there. One of the things that I noticed and I think you guys put in there on purpose is the last press releases you had on these SPAs, you specifically -- they all call out that they're in support of the Golfinho/Atum, which is 100% on your block. But can you characterize for us or give us some sense how well of it is to the Anadarko story going forward? Is the Prosperidade accumulation that you guys shared with that upward block? And is it something that we need to be thinking about as perhaps hidden value? Or is it something that's not going to be part of your story?

Al Walker -- Chairman and Chief Executive Officer

Well, it definitely is a part of our story, Charles. There's no if, ands or buts about that. The reality is, the first two-train development is focused on the resources that we have in the Golfinho/Atum, and you should expect in the future, latter part of the next decade, into early 2030s that the straddling reservoir between ourselves and Area 4 will be an area of tremendous interest for both concessionaires and both blocks. It also is the largest accumulation.

So a lot of what we talk about or what Area 4 talks about in terms of ultimate recovery from gas in place points to the accumulation that we collectively and individually see in that straddling reservoir. So while it's not the initial source of gas for these first two trains, it definitely provides us an ability for the next decade to come to have continued development from a very unusual gas accumulation with the investment that we're making today in both the fixed and variable associated with building those first two trains and all that goes with it, so that the subsequent trains actually have the benefit of having the fixed-cost investment. And, Mitch, feel free to add anything you'd like to in addition to that.

Mitch Ingram -- Executive Vice President, International, Deepwater and Exploration

Thanks, Al. The only thing I would add is the common infrastructure that we are installing, just as you indicated, is something that share between ourselves and Area 4. And that obviously sets everything out such that from the -- actually do take Prosperidade sanction decision, that will be in a brownfield environment. So we anticipate obviously that taking -- having the advantage of those key infrastructure being in place and obviously, we also -- the workforce who have completed the LNG plant before.

So really does have a decades of construction activity and supply going forward. So is that immaterial to us going forward, the timing will be dependent on completion of the first two trains.

Charles Meade -- Johnson Rice -- Analyst

Got it. And then, Al, if I could go back to a comment that you made in your opening remarks about your non-consent acquisitions in the Delaware. And perhaps, that's a more broad question. Going back a year ago, I think I like the way you guys phrase is that at the prices being -- the asked prices at the time, it was hard to make an acquisition work, but can you comment on how that acquisition or the A&D market has changed in the Delaware basin? And what you see now? And perhaps, offer a little bit of more color on if these non-consent acquisitions are still attractive to you? How people are letting them go from their own portfolio?

Al Walker -- Chairman and Chief Executive Officer

Well, let me address the macro question of the A&D market and then I'll come back and discuss kind of what's going on from our perspective on the non-consents. We obviously saw a pretty big deal of transact last year with BP's purchase of BHP in the Delaware. I would say the activity level today is certainly down from a couple of years ago overall. There's still tremendous interest, largely from integrators to continue to be buyers in the Delaware.

I think we have seen lots of media information on that as it relates to several deals are talked about often. So I don't think there's a diminished level of interest that may be more isolated or concentrated. And yes, I think many of the private equity-backed deals have largely been monetized at this point so the number of deals coming into the market probably have slowed down quite a bit, it's not likely to tick back up for that reason. As it relates to non-consents, I think we all are recognizing that when we produce a budget that we have things that we want to deliver against that budget, our objectives might be different than someone else's.

So consequently, when we've sent someone an AFE for a well, it probably means lots of things for us as the operator that we want to achieve. And whether or not that fits into the budget of the people we would send that AFE to is their decision independent of us. So I'm not sure I'd read much more into that than just simply resee things that are attractive to us that others might not see as the same. And keep in mind that as the operator in that part of our portfolio, we have the benefit of our Western Gas midstream and all that goes with that.

So our interest could be different from our non-operated partners in certain cases, and that was part of the operatorship capture strategy in the first place is that we wanted to be able to control the development pace, as well as the economics as best we could. So I'd say our decision what we do are largely independent of those that might be sending AFEs to.

Operator

Our next question comes from Stephen Richardson of Evercore. Please go ahead.

Stephen Richardson -- Evercore ISI -- Analyst

Good morning. I was wondering if you could talk a little bit about the PRB program for '19. Specifically, what do you expect to -- in terms of delineation, what are you expecting to learn from the '19 program? Is it -- and if you could speak a little bit to, is it reputable well cost in some of the unconventional zones? Or is it still on a pure delineation in terms of evaluating the entire scope of the acreage position?

Al Walker -- Chairman and Chief Executive Officer

Well, largely, what we're trying to do this year is understand what we believe is the oil extent of the primary bench there. Our place of program's targeted understanding what that looks like and then inside of that, we will test sort of in a beta concept, what we think could be a development plan. So that if the results at the end of the year are supportive, we'll have a much better idea in the coming years as we look to this particular part of our portfolio for additional cash investment to have a better idea, not only of the upstream but the midstream development plan associated with what we think the well performance would be. So this year sets up what we hope to be both a development idea for upstream as well as midstream.

Stephen Richardson -- Evercore ISI -- Analyst

And is that primary zone -- sorry if I could just follow up. Is that primary zone, the Turner in your plan? Or is it some of the other unconventional zones?

Al Walker -- Chairman and Chief Executive Officer

Well, as we've said in our ops report and talked about on several occasions, yes, it's the Turner, but that is not the only bench that exists there. So we're going to be trying to understand better what some of the commercial aspects of the other benches are as a part of our appraisal of the Turner.

Stephen Richardson -- Evercore ISI -- Analyst

Got it. One follow-up on Mozambique, if I might appreciate, that you've got a lot of disclosure that's coming. The one question is, could you just scale for us in terms of Anadarko today, either headcount or proportion of your cost structure that you're carrying to support this project at this point that will ultimately go on to the project side? Just the sale of -- like the scale of Mitch's organization and the commitment to this, and what it means for your cost structure today?

Al Walker -- Chairman and Chief Executive Officer

You bet. I think both Bob Gwin and Mitch would be great at addressing those. As you imagine, the work that we've done up till now as we are approaching a sanctioning decision moves into a very different framework in terms of how we, as operator, would work with the rest of our working interest partners in the concession. So maybe, Bob, you and Mitch, if you don't mind, take that in part?

Bob Gwin -- President

Sure. We'd be happy to. It's really pretty straightforward. We have 26.5% of the project.

And although as operator, we're hiring the people, and these are employees and contractors on our books, we only bear the burden of the 26.5% interest even though the gross employee count is high, the net employee count adjusted by that working interest is quite a bit lower. Mitch, you have anything to add?

Mitch Ingram -- Executive Vice President, International, Deepwater and Exploration

I'll just add with regards to the scale of the organization, it's quite typical at this stage, where we are preparing for FID that we've put a team so far. We've been focused on getting us to that point, and then we really start looking at increasing the headcount for the construction activities in the field. So we are preparing for that to happen, and obviously takes us into the execution phase. And given the project of the scale, we've got individuals in many parts of the world to be ready to execute this.

Operator

Our next question comes from Welles Fitzpatrick of SunTrust. Please go ahead.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Hey, good morning.

Al Walker -- Chairman and Chief Executive Officer

Good morning.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

You guys talked about the NGL drop quarter over quarter. Obviously, a lot of that is commodity driven versus some specific to you all, but I was wondering if the start-up of the Mentone plant was responsible for some of that lower quarter-over-quarter realizations. And maybe as those recoveries ramp up, if we could see a reversal in 1Q?

Al Walker -- Chairman and Chief Executive Officer

I think some of that was temporal. And if you don't mind, I'll let Ben kind of address your question more specifically.

Ben Fink -- Executive Vice President, Finance AND Chief Financial Officer

Yes. Once again, your suspicion is correct. Right around the time of the NGL price drop, as you noted, we had a plant start-up. Very typical in the start-up phase to have, shall we say, suboptimal liquid recovery percentages, and we were selling a lighter barrel into a weaker market, and you saw that on our GPM line.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

OK. No, great. Good to hear. And then just one more on NGL.

So it seems like Train 1 for late summer, it's midyear now. Any word on that second train? I think you guys had less volumes on that. I think it's mainly third party, but any word on the timing of that second train?

Al Walker -- Chairman and Chief Executive Officer

Well, the timing of that train, I think, is probably best addressed by Mitch. And, Mitch, why don't you, if you don't mind, handle the question?

Mitch Ingram -- Executive Vice President, International, Deepwater and Exploration

Right. Where we are with the train is that obviously, where focus is getting Train 1 completed at this moment in time. Train 2 construction, engineering construction activity really are looking at year end for Train 2. So we'll sequentially move our project team obviously from one phase to next, and it's roughly that timing.

So no surprises.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

OK. Wonderful. Thank you.

Al Walker -- Chairman and Chief Executive Officer

Thank you.

Operator

Our next question comes from Mike Scialla of Stifel. Please go ahead.

Mike Scialla -- Stifel Financial Corp. -- Analyst

Good morning. Wanted to see if you're planning on any other spacing configuration tests in the Delaware or test any deeper zones this year? Or do you move forward with that Silvertip configuration as your development model given the positive results you've seen there?

Al Walker -- Chairman and Chief Executive Officer

We have a lot going on in Delaware this year. Not all of which is focused totally on Silvertip. And, Danny, if you don't mind, I think maybe the description of kind of some of the things you and your folks are trying to do this year probably in order.

Danny Brown -- Executive Vice President, U.S. Onshore Operations

That's great. Thanks for the question, Mike. Yes, we will do some more spacing tests as the year moves on and then into next year, as you would expect, because the rock changes as you move across our position, we've got a fairly expensive position there. So the fluid characteristics change as you move east to west.

The actual rock makeup changes as you move around the basin. So the actual development plan for any individual section is -- can be different. And so we need to learn a little bit more as we move around the field. Thankfully, we do have a fairly expensive -- we drilled off throughout our acreage position, and so we get some good ideas on what's going on particularly in the Wolfcamp A but some of these other targets we have less direct information about.

Clearly, we're getting logs and core data from industry. But we'll likely do some additional spacing tests there. So I think the Silvertip campaign, we know that, that works really well up in that area. We'll continue to do some spacing test in and around the rest of the basin and refine and optimize our development plans from there.

Mike Scialla -- Stifel Financial Corp. -- Analyst

Very good. And there's been some concern about seismic events related to water disposal on the basin. Just want to see if you see any potential changes coming there for either Anadarko or the industry as a whole?

Al Walker -- Chairman and Chief Executive Officer

Well, I think we are watching that. I think it is something that you see additional media attention being placed into on areas, I'll call modest concern. I don't think the active platonics that you saw in Oklahoma are a parallel for West Texas. But nonetheless, as we think about the amount of fluid and water that's moving in the Delaware basin, it is definitely something we're watching and being mindful of.

And I think industry in general is doing the same. My only caution to -- I just don't think the very active tectonics that you saw that led to a lot of concerns in Oklahoma are a parallel for West Texas.

Mike Scialla -- Stifel Financial Corp. -- Analyst

Good to hear. Thank you.

Operator

Our next question comes from Jeffrey Campbell of Tuohy Brothers. Please go ahead.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Good morning. In the ops report, you described the strategic infrastructure and the Delaware basin is largely built on. I just wondered, does this imply that you're going to grow -- continue to grow your volumes until you meet that capacity and then sort of go into steady state mode? Or is there going to be another leg up once you reach that capacity?

Al Walker -- Chairman and Chief Executive Officer

Well, I think in the near term, we've achieved much of what we have been talking about the last couple of years. I think as we look out, I might ask Ben and/or Robin to talk a little bit about the other part of your question. And there will be ongoing requirements for build-out and our infrastructure but as we've addressed in the announcement of our combination of putting the two MLPs together, that will largely move to being a Western Gas decision in the future. So maybe with that, Ben, if you could start and if Robin needs or wants to add something else, feel free to have or do those as well.

Ben Fink -- Executive Vice President, Finance AND Chief Financial Officer

Sure. I'll just make a quick comment and then pass it over to Robin Fielder, who's CEO of Western -- WGP. I think we've gotten much better over time at delivering infrastructure on a just-in-time basis, right? We build a lot of operating leverage and then we add as needed, and I expect, going forward, we will do the same.

Robin Fielder -- President and Chief Executive Officer, WGP

This is Robin. I'll just expand upon that. As you guys recall, and we highlighted it in -- on our -- in our materials in 2018, we added two new regional oil treating facilities throughout the year. We successfully brought on our first plant at the Mentone facility in Q4, and look to bring on the second train there by the end of this quarter.

And we've put in a lot of additional gathering and really have that backbone in place. So that's what really what we mean by we've put in a lot of the initial infrastructure but also with the capability to be able to expand upon that if you continue to facilitate the expected growth we will see out of the basin.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Great. Appreciate the color. That's it for me.

Al Walker -- Chairman and Chief Executive Officer

Thanks, again.

Operator

Our next question comes from Paul Grigel of Macquarie. Please go ahead.

Paul Grigel -- Macquarie Group Limited -- Analyst

Hi, good morning. Following up a little bit on A&D, I was wondering how future opportunity is to grow scale in the Delaware or bolt-on further Gulf of Mexico production and prospects are balanced against the return of cash to shareholders?

Al Walker -- Chairman and Chief Executive Officer

Well, good morning, Paul, and maybe like Doug, we'll eventually have someone there to introduce with your last name being pronounced correctly, sorry about that. As it relates to your question, we'll continue to look at things on the margin that will be attractive from a piece-of-a-puzzle perspective. We haven't seen too many things to date where that puzzle piece makes good economics tends to pursue. So I think you should anticipate that we'll continue to look but be mindful of whether or not we want to add the puzzle piece in a way that does more than just creates operating opportunities versus economic support for those opportunities.

We're very much a total return or full-cycle investors. We think about acquisitions and that's why a few years ago, when we bought the Freeport-McMoRan properties in the deepwater, we were very convinced that what the full-cycle rate of return would do for that investment relative to other investments we might have in our portfolio. And while that was a fairly large transaction in one sense, I think most people look at that as a very good move and one that certainly improved our footprint in the Gulf of Mexico and has helped our company in addition. So we're not afraid to make an A&D move as it relates to the footprint, but it will be more of that full cycle, how does it compete for capital, and does it compete for capital when you include the Corpus investment into that greater return.

Paul Grigel -- Macquarie Group Limited -- Analyst

That's helpful. And I guess, turning to Mozambique, in regards to the funding there, what are the considerations on debt and leverage levels? And any impact on corporate ratings for the project given the debt will grow prior to generating cash? And does that consideration change at all if the debt is consolidated onto the balance sheet even if it is nonrecourse?

Al Walker -- Chairman and Chief Executive Officer

OK. Well, you can imagine, Ben's had more than a couple conversations with the rating agencies to address your question. And I'll also say despite the fact, we'll try to address this as best we can this morning, and you can rest assure that when the time comes and our board has -- may taken a sanctioning decision to go forward, we'll be prepared to give you a lot of detail. Our board has not made that decision yet but we have considered it.

And so maybe with that, let me have Ben address your questions in terms of how would that project financing debt be considered both from a reporting perspective as well as from how the agencies will look at it.

Ben Fink -- Executive Vice President, Finance AND Chief Financial Officer

Sure. And as you can appreciate, we've had numerous conversations with the agencies so that there are no unanticipated surprises if we do take FID. But as operator of an integrated project and it's important to remember this is an integrated upstream, midstream project, our 26.5% share will be on our balance sheet even though after completion, it's nonrecourse to us. And so we're going to need to do some very proactive communication in explaining that and making sure regardless of it being on our balance sheet, it's understood that it's nonrecourse to us very similar to the Western Gas debt that we're forced to consolidate.

Let me stop there and see if I've answered your question.

Paul Grigel -- Macquarie Group Limited -- Analyst

I think that's helpful. Just one quick minor follow-up. The rating agencies understand that consideration as you guys aim to continue to strive to maintain investment-grade ratings?

Ben Fink -- Executive Vice President, Finance AND Chief Financial Officer

Well, I certainly can't speak for them. I can tell you that our communication has been very proactive and constructive, and I feel they are understanding it in the way that it should be interpreted.

Paul Grigel -- Macquarie Group Limited -- Analyst

Thank you very much.

Operator

Our next question comes from Sameer Panjwani of Tudor, Pickering, Holt. Please go ahead.

Sameer Panjwani -- Tudor, Pickering, Holt -- Analyst

Hey, guys, good morning. Can you provide some thoughts about what's changed in the Gulf of Mexico since the Freeport acquisition? If I recall correctly, initial guidance following the deal called for about 160,000 barrels a day. That's taken down to 150,000, and now we're at 140,000. So how should we think about the impacts to guidance from changes in capital allocation versus well performance?

Al Walker -- Chairman and Chief Executive Officer

Well, I think the best person to address, that's probably Bob Gwin, given he has been very intimately involved not only in the acquisition of that but more recently in terms of how we manage it. Some of that has to do with the question Doug Leggate asked earlier about just where are we in the life cycle, I think, with investment in the Gulf of Mexico. It does change from year to year depending upon the prospect inventory or development inventory that we might have. But, Bob, if you don't mind, maybe take the question directly.

Bob Gwin -- President

Sure. I'd be happy to. Al just touched on at the very end there. He touched on one of the things that affects what you're doing in the Gulf of Mexico.

The other one is broader capital allocation across our portfolio. We obviously are seeking to optimize the use of the capital to deliver the best long-term performance that we can. And so if those volumes that you referenced are correct like historically, then the slight difference versus what we might have been expecting two years ago, I think you might see in terms of what we're now showing in terms of flat production at the current level a little longer. Mitch has a little bit to share on that front because this is more a matter of tweaking what we've done and reoptimizing the development programs given the performance of wells and the performance of specific infrastructure.

Both that, which we had on a legacy basis and that which we have acquired and exploited since the acquisition.

Mitch Ingram -- Executive Vice President, International, Deepwater and Exploration

Thanks, Bob. I'll just expand on where we are in terms of the Gulf of Mexico. And I think to identify some of the Freeport facilities, you just look at Horn Mountain and some of the tremendous progress we've seen in terms of production, only as our drilling team done a great job in drilling wells quickly so we've taken as we've reported before in Horn Mountain well really from #5 from spud to production, which was in 81 days. That well was taken on last year and still producing 13,000 barrels per day today.

So some great performance from some of the wells in Horn Mountain and the fill area. It really is lowering our development costs and giving us steady free cash flow going forward long term.

Sameer Panjwani -- Tudor, Pickering, Holt -- Analyst

OK. That's helpful. And then if I can squeeze in a second one here really quickly. In the DJ, it looks like there was a change to the type curve.

Can you just provide some color on what's driving that shift? And if this is meant to represent go-forward development? Or if it's more isolated to the 2019 program?

Al Walker -- Chairman and Chief Executive Officer

You bet. Danny, if you don't mind, would you like to take that one?

Danny Brown -- Executive Vice President, U.S. Onshore Operations

Sure. So when you look at the type curve similar to the information we provided in Delaware, we've got one type curve that now represents DJ and so this is more of a go-forward development -- an average go-forward development plan for us, not necessarily representative of any specific annual-time period. So generally speaking, what we've done is, we've increased the lateral lengths. We've seen that our well length has actually been coming in much higher.

We've been successful in being able to pool different sections together to get longer lateral lengths, and so we needed to account for that. And then we blended more of the acreage together, again, to provide one overall type curve. So more about a go-forward plan and less about any specific-time period.

Operator

Our next question is from Mike McAllister of MUFG. Please go ahead.

Mike McAllister -- MUFG -- Analyst

Thank you for taking my call. Actually, off of that question on DJ Basin, the new type curve, the production mix also changed to now oil is now 32%. Is -- what is the cause of that move?

Al Walker -- Chairman and Chief Executive Officer

Danny, again, I'll turn to you but that's not a materially different mix than we've had historically. And it does represent changes from year to year over what happens to be a drilling campaign. But, Danny, if there's anything in addition you'd like to add, go ahead.

Danny Brown -- Executive Vice President, U.S. Onshore Operations

Well, the only thing I'd add is as we looked at -- as we always do, as we continue to learn from the field, as we learn from different completion techniques, as we drill up certain areas of the field and we move into other areas of the field, we're always looking at our future expected to performance and updating our type curves in accordance with that. So when we look at our -- at the experience we've gotten as we went through '18 and look at the forward plan for the acreage we'll be developing in front of us, we need to update those type curves to provide what we think is the most accurate forecast moving forward and that's what we've done.

Mike McAllister -- MUFG -- Analyst

OK. That's fair enough. And then could you guys talk a little bit about the PRB and kind of how operations there going forward are similar to how you approached the DJ or the Delaware? Just kind of the idea of pace of activity. And if -- is there a point where you could make a decision to say this does not fit in our portfolio?

Al Walker -- Chairman and Chief Executive Officer

Well, that is part of what we're trying to determine this year. That's why this year is best described as appraisal year. As we understand through the appraisal results, what the development opportunities look like both for upstream and midstream, and importantly, the commerciality of that, that will give us a better indication than we have today for exactly where it fits in the portfolio. Early returns look extremely encouraging, and we talked last summer about some of our well results and the oil cuts associated with those.

But I think until we finish this appraisal work, understand the aerial extent of the Turner, appreciate better the commerciality associated with the development and how it would then in turn compete for capital within our portfolio, it would be difficult for me today to answer your question much more than just what I have.

Mike McAllister -- MUFG -- Analyst

But the belief is that those -- there will be more clarity by year end?

Al Walker -- Chairman and Chief Executive Officer

Well, we certainly hope so. I mean, I don't know what these appraisal wells are going to tell us. Well, they very well should tell us everything we're hoping to learn this year. If we find that we need some more appraisal work in 2020, I wouldn't dismiss the notion that we've turned away from that.

On the other hand, our plan currently is that this year's work should give us a very good understanding of how the Turner looks from an aerial perspective, how it might be able to be commercially developed and then how that rate of return or how it would then in turn compete for cash -- for investment within our portfolio can be better gauged. We do have some beta testing to be done this year in terms of how we would see ourselves as a part of the appraisal program, developing a part of it, just to see how that would set up. So there's a lot of work that needs to be done this year. We're not in a hurry.

We think we can do this on a very good pace with the 10 to 15 wells that we've talked about for the appraisal activity. And I think it's a coming attraction but a pretty attractive coming attraction. We've heard industry talk a lot about it. I think we're prepared to talk about it more once we understand better what the results of this year allow us to understand.

Mike McAllister -- MUFG -- Analyst

It doesn't seem like there's anything that push you to move to accelerate activity to on kind of a non-consent basis or anything like that? It seems like you can operate at your own pace.

Al Walker -- Chairman and Chief Executive Officer

Pretty much. I mean, we do have non-operated activities out here with a couple of industry partners. But we have a good working dialogue with each of them, and I think we understand and what their drilling plans are for the year and vice versa. So whether it's operated or non-operated as we are working with our industry partners, we think by year-end, we'll understand more of it.

But I don't think we're going to get forced into a situation where we're going to have unexpected activity.

Mike McAllister -- MUFG -- Analyst

OK. That's great. Thank you very much.

Operator

Our next question comes from Paul Sankey of Mizuho. Please go ahead.

Paul Sankey -- Mizuho -- Analyst

Good morning, all. Al, you asked for strategy questions, I've got one. You also encouragingly spoke about how you wanted to make Anadarko competitive with any stock in the market, which we applaud. One thing regards to the structure of the company in terms of the shape of where you are.

It feels like despite your asset value, you aren't getting full valuation perhaps because you have such a tremendous mix of businesses. And it particularly feels as if the position in Colorado disproportionately affects the stock price relative to its actual valuation to Anadarko. I was wondering if you had some big thoughts about restructuring the company perhaps focusing it into less themes than you're in?

Al Walker -- Chairman and Chief Executive Officer

Well, that's a deep question, Paul. I appreciate it. I'll answer you this way. We have not had any discussion to dare or consideration for doing some things separate and apart with Colorado.

I haven't gotten any indication that the state is looking to get out of the oil and gas business. And in fact, it seems like they're trying to find opportunities to work better and closer with industry around the things that they're considering both in the executive as well as the legislative branches. Consequently, today, I do think that we do see a constructive environment in Colorado relative to our position there. I understand the hesitation by the investment community associated with what's going on, I'm not trying to diminish concerns that people have, but we have a fairly strong investment program targeted there this year, and continue to believe it's an important part of our portfolio.

I have not given any consideration to the question you asked.

Paul Sankey -- Mizuho -- Analyst

Thank you.

Al Walker -- Chairman and Chief Executive Officer

You bet.

Operator

Our next question comes from Biju Perincheril of Susquehanna. Please go ahead.

Biju Perincheril -- Susquehanna Financial Group -- Analyst

Thanks. Good morning. Going back to the Silvertip test. Can you talk about the secondary zones that you tested there, if those are necessary to fully drain the A section? Wondering if you have any thoughts on that this early in that program.

Al Walker -- Chairman and Chief Executive Officer

You bet. Danny is probably best capable of addressing that. But we are trying to understand all of those benches at the same time. So, Danny, if you would?

Danny Brown -- Executive Vice President, U.S. Onshore Operations

Yes. Thanks for the question, Biju. I would say it's too early to tell is the short answer on that. We need to see how the performance of these wells over time and look at the pressure interaction of these wells over time to understand how to best exploit these.

I think we're very encouraged with what we're seeing in drilling these secondary targets. They are resulting in production performance that's equal to or, in many cases, greater than what our overall Wolfcamp A type curve is. So that's very encouraging. But as maybe that as we've seen more production data over time, we can fully develop a section with fewer wells, which should be a good thing for us as we look at how drainage patterns affect over time.

But we won't know that until we produce these wells for little time and it's part of the reason that we did the test. And so I think the good news is, we think we have some excellent secondary targets here and perhaps the better news is over time, we may be able to determine we can drain more of the section with fewer wells.

Biju Perincheril -- Susquehanna Financial Group -- Analyst

That's helpful. Thanks.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to Al Walker for any closing remarks.

Al Walker -- Chairman and Chief Executive Officer

Thank you, Andrea, and I appreciate everyone's participation this morning. Thank you for your questions. And I'd like to just finish with saying I think since September of '17, we've demonstrated a commitment to returning cash to investors. We've reiterated our commitment to that as we go into 2019.

I think the thing we didn't talk a lot about this morning that we hopefully will talk more about is our ability to continue to lower our breakeven oil price. We gave you some information this morning associated with that. I'd encourage you to dig into that a little bit and understand just how important it is to be able to lower your breakeven so you improve your cash flow yield. That is very important to us as we think about how we return cash to investors so that we can continue to be more efficient in driving down that breakeven in order to improve our free cash flow yield to our investors.

The other thing is I think hopefully, you're hearing from us that we don't just -- we believe today and going into the future that we have a portfolio that today as well as for the decades to come is positioned to be able to continue the durable strategy of returning cash to investors above the breakeven and being able to show that with a lot of consistency. So hopefully, as you look more at that and understand better what we're trying to achieve the fact that we did not change our guidance from November, we still believe that the investment program that we rolled out in November will produce the results that we're reaffirming this morning. So if you have additional questions, please don't hesitate to give Mike Pearl and his staff a call, and we look forward to seeing each of you throughout the course of the year. Thank you.

Operator

[Operator signoff]

Duration: 69 minutes

Call Participants:

Mike Pearl -- Senior Vice President of Investor Relations

Al Walker -- Chairman and Chief Executive Officer

Arun Jayaram -- J.P. Morgan & Co. -- Analyst

Danny Brown -- Executive Vice President, U.S. Onshore Operations

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Ben Fink -- Executive Vice President, Finance AND Chief Financial Officer

Brian Singer -- Goldman Sachs -- Analyst

Mitch Ingram -- Executive Vice President, International, Deepwater and Exploration

Bob Brackett -- Bernstein Research -- Analyst

David Deckelbaum -- Cowen -- Analyst

Charles Meade -- Johnson Rice -- Analyst

Stephen Richardson -- Evercore ISI -- Analyst

Bob Gwin -- President

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Mike Scialla -- Stifel Financial Corp. -- Analyst

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Robin Fielder -- President and Chief Executive Officer, WGP

Paul Grigel -- Macquarie Group Limited -- Analyst

Sameer Panjwani -- Tudor, Pickering, Holt -- Analyst

Mike McAllister -- MUFG -- Analyst

Paul Sankey -- Mizuho -- Analyst

Biju Perincheril -- Susquehanna Financial Group -- Analyst

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