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Noble Energy Inc (NYSE:NBL)
Q2 2019 Earnings Call
Aug 2, 2019, 9:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good morning and welcome to Noble Energy's Second Quarter 2019 Earnings Results Webcast and Conference Call. Following today's presentation, there will be an opportunity to ask questions. [Operator Instructions]. I would now like to turn the conference over to Brad Whitmarsh. Please go ahead.

Brad Whitmarsh -- Vice President, Investor Relations

Thank you, Allison, and I appreciate all of you joining us for our second quarter conference call. I hope you've had a chance to review the news release and presentation deck that we published this morning. These materials are available on the Investors page of our website and they highlight continued strong operational performance for the business. Later today, we plan to file our Form 10-Q with the SEC. I want to remind everyone that today's discussion contains projections and forward-looking statements as well as certain non-GAAP financial measures. You should read our full disclosures in our latest news releases and SEC filings for a discussion of those items.

Following our prepared remarks, we'll hold a question-and-answer session. I would ask that analysts limit themselves to one primary and one follow-up . Our planned comments this morning will come from Dave Stover, Chairman and CEO, as well as Brent Smolik, President and COO, Ken Fisher, EVP and CFO, Hodge Walker, SVP of Onshore and Keith Elliott, SVP of Offshore are here to participate in the Q&A session.

With that, I'll turn the call over to Dave.

David L. Stover -- Chairman and Chief Executive Officer

Good morning everyone and thanks for joining us. It has started out as a volatile earning season for the industry, but we're glad to have the time this morning to share Noble's accomplishments and why we are excited about our future . For us, the summer days have been very active. We're close to bringing Leviathan online and realizing the transformational impact, we've been pointing to, for several years. It's thrilling to be just a few months away from start-up. Across our portfolio, we have created more certainty and visibility throughout our business this year. The Alen sanction, DJ inventory of permits and our development mode in the Delaware all contribute to a sustainable future for Noble Energy

Onshore execution and Leviathan start-up established the foundation for performance in 2020 and beyond. Noble is positioned to distinguish itself through three key factors. One, the positive rate of change heading into 2020 from decreasing capital and significantly increasing cash flow and volume; two, the move to an even lower annual corporate volume decline rate in the low 20% range; and three, a global inventory that include substantial discovered resources that can use existing infrastructure to generate significant returns. As the market continues to experience volatility, we remain intensely focused on generating free cash flow, improving corporate returns, protecting the balance sheet and returning significant amounts of capital to investors. Through the first half of the year, our organization has made tremendous progress and I'm proud to share our accomplishments.

For the 4th quarter in a row, our total capital came in below expectations. This was driven by Onshore US well costs and facility savings and offshore activity timing. Brent will highlight how we are exceeding our original capital reduction targets year-to-date and this is a step change that provides the framework for a long-term sustainable decrease in our capital intensity . With our accomplishments to date and our confidence in our outlook through the remainder of the year, we are lowering our full year 2019 capital guidance by $100 million. We delivered a strong operational second quarter, some specific results that really stood out included capital expenditures and operating cash cost per barrel were more than 10% below plan for the quarter and sales volumes were 10,000 barrels equivalent per day, above the midpoint of expectation with oil volumes toward the high end of guidance

These factors contributed to an improvement in cash flow per share versus consensus. It also highlighted the organization's success in managing controllable items. During the quarter, we actively managed our commodity price exposure through market diversification and hedging we added some new oil hedges and are now approximately two-thirds covered for 2019 and above 40% for 2020 with a floor of at least $58. Earlier this year, we also proactively hedged 70% to 75% of our WAHA basis exposure through 2020. Our operational performance and efficiencies accelerated a number of wells to first production through faster drilling and completion timing and our onshore activity in the second quarter will drive a pronounced third quarter volume increase while onshore capital spending trends lower in the back half of the year. Along with the high demand season in Israel and strong performance in West Africa, the entire company is undergoing a material uplift this quarter. Our third quarter volume guidance reflects 8% total company sequential growth at the midpoint of our range with oil up over 10%

We are well on our way to delivering the outlook, this outlook with strong performance in July. Year-to-date results, along with our outlook for the second half provides confidence that our full year volumes will be toward the upper half of our original guidance range . In the DJ Basin our performance continues to deliver to the upside, led by development of the Mustang asset. It's amazing to think of the progress the team has made to efficiently design and set up the asset for long-term development and the results are proving the success. Looking to the future, I'm pleased to announce that we have submitted the application for an additional comprehensive drilling plan or CDP for the North Wells Ranch area where we can build upon the accomplishment seen at our Mustang position

Through our long-term strategic planning, we have years of high return activity in the DJ giving the company line of sight to execute on its multi-year plan and to build upon our industry-leading returns in the basin. In the Delaware, we've delivered significant well cost reductions, operating cost improvements and increased production meaningfully. The team has executed well this year and brought online our first road developments during the second quarter. In support of these basins, Noble Midstream Partners has continued to ensure efficient in-basin gathering as we bring wells online ahead of schedule and plan. Our strategic review of the midstream business is ongoing, we will update the market when appropriate

Providing diversification to our US business, the international assets are comprised of material low cost, low decline discovered resources. These resources have the economic benefit of taking advantage of existing infrastructure to develop them efficiently. The first half of the year has brought Leviathan closer to production and saw the sanction of our Alen gas monetization project in West Africa. These projects provide a unique opportunity to access global natural gas markets with premium pricing.

Noble is rate of change story is really exemplified by our Leviathan project, which creates a huge net cash flow swing from completing the project in 2019 to the first full year of production in 2020. Leviathan represents the largest discovery in our company's history and one of the largest ever infrastructure projects in Israel. With 33 trillion cubic feet of gas in place and 22 trillion cubic feet recoverable, the project will continue to provide energy-independence for Israel and transform the country into a significant energy exporter for the first time in its history. The construction of the Leviathan production decks is finished and the project is now nearly 90% complete. The production decks at sale for Israel in early July and you can see a video of the launch on our website.

We eagerly look forward to their arrival later this quarter before final commissioning and first gas sales by year-end. Additionally, we continue to progress marketing and transport discussions. Technical work on the EMG pipeline was performed during the quarter to test its integrity. Our teams are extremely pleased with the condition of the pipe, we anticipate closing on the acquisition in the third quarter. With Leviathan starting up at the end of this year and Alen in the first half of 2021, I'm really excited about the cash flow impact and sustainability of cash flows that we are adding from our offshore major projects over the next couple of years.

In addition to our robust discovered resource base, we have some material exploration opportunities that we are looking forward to testing in 2020. Our plan includes the handful of onshore unconventional wells in Wyoming, along with an offshore Colombia prospect test next year. Overall, I'm extremely pleased with our progress and how we are executing for the future. To be clear, next year's capital program is expected to be significantly lower than this year. At the same time, cash flow and volumes will grow substantially. As we move into this transformational 2020, we will be managing our capital expenditures to ensure we generate organic free cash flow that can be returned to shareholders while strengthening our balance sheet and improving corporate returns. We've set ambitious goals to recalibrate our business through a laser focus on cost efficiencies and a moderate growth profile. Along with a lower capital intensity, we're focused on improving our overall cost structure through reductions in operating, G&A and non-cash costs. Now, I will turn the call over to Brent Smolik, our President and COO to talk about how we are lowering the long-term capital needs for the company and generating high margin growth in returns through innovation and continuous improvement.

Brent Smolik -- President and Chief Operating Officer

Good morning, everyone. Thanks, Dave. I echo your comments on the dramatic rate of change and significant inflection point that we're experiencing, as evidenced the US Onshore business delivered a very strong second quarter as highlighted on slide 4, production was above plan and capital and operating costs were lower than forecast. For Q3, we expect total US oil production to be up nearly 10% for both oil and equivalents and capital to be down about $75 million sequentially. This is a reflection of the good work our teams have done to improve capital efficiencies and reduce cost, coupled with the acceleration of our turn-in-line schedule, all positive for improving cash flows.

In Q2, USO well costs were down nearly 20% from fourth quarter 2018 levels. On slide 5, you can see that we're exceeding the planned cost reductions of 500,000 to $1 million per well in the DJ Basin and $1 million to $1.5 million per well in the Delaware. Currently all costs are about $0.5 million lower than the budgeted cost through a combination of improved well designs, better execution efficiencies and supply chain savings. Some examples of the Q2 execution included record drilling times in both the DJ and Delaware Basins. Several of our 9500 foot laterals in DJ were drilled in less than five days. A recent well in the Delaware with about a 10,000 foot lateral was drilled in less than 17 days and it wasn't that long ago that we were averaging over 22 days for the long lateral wells in the Permian, so I'm very pleased with the progress made by our drilling teams.

On the completion side, pump hours per day continue to trend higher through the row development and execution improvements. We've also worked with our service providers to incentivize even higher pumping hours per day which benefits both us and them. We continue to refine our completion designs, including in some cases lower profit concentrations and fluid volumes and reducing those frac fluid volumes creates benefits on multiple fronts including lower capital cost, reduction in source water and water disposal and acceleration of first production. We've also continued to attack operating expenses. Unit production costs were down significantly in the quarter as we focused on workover optimization, streamlining chemical programs and fuel cost savings. And we're certainly not done, we've got continuous improvement initiatives under way for further expense reductions.

Before jumping into some of the asset specifics, I also want to highlight a couple of new oil-marketing arrangements that should improve net back pricing. In the Delaware, initial flows from the EPIC pipeline will commence shortly and we'll be moving barrels to the Gulf Coast at very attractive tariff rates. Reported GTP will increase with the transaction. However, increased realizations will more than offset the cost as we migrate our Permian oil sales to Gulf Coast pricing arrangements. During Q2 , we also finalized an agreement with the existing Saddlehorn Pipeline to transport additional quantities of crude from the DJ Basin to Cushing at lower tariff rates. The Noble marketing team in Noble Midstream has done a very nice job of improving the value of our equity barrels and both arrangements will contribute to further margin growth.

Let's take a little closer look at the DJ Basin, we delivered a strong quarter of execution in the asset continued to fund growth while generating free cash flow. In the quarter, we initiated production on 36 wells in the basin with 20 for Mustang Row 2. The Mustang area continues to perform very well. The gross production from Rows 1&2 has grown from 0 to over 55,000 barrels of oil equivalent per day in less than a year. That performance is highlighted on slide 8 along with DP-408, which is one of the development plans Row 2. The Mustang 408DP has 24 wells 12 of which were parked with lower fluid design and 12 with our previous design. Reducing fluid volumes sustainably reduces cycle time and well cost. The DJ efficiency gains result in a few more wells this year than planned. In the second half of the year, we expect to TIL over 50 more wells, primarily in Mustang in Q3 and Wells Ranch in Q4 . Before leaving the DJ, it's important to mention the gas processing expansion that's under way. DCP's O'Connor 2 plant is expected to restart shortly and ramp up through the third quarter. As a reminder, we utilize several gas processing alternatives if needed, which has helped position Noble differentially in the basin.

Turning to the Permian, the Delaware Basin production reached a quarterly record of 64,000 barrels of oil equivalent per day. The production benefited from strong base and new well performance, including the acceleration of 7 TILs into the quarter. As displayed on slide 9, we initiated production on wells across our acreage position in Q2 including our first real row developments. Well costs were significantly lower than we budgeted and well performance was in line with our expectations.

The Calamity Jane development in the Northeast portion of the acreage showcases our initial full section row development. These two [Phonetic] wells peaked at approximately 20,000 barrels of oil equivalent per day with oil percentages in the 50% to 60% range as expected in this part of the field. The benefits of row development include reduction in parent child interactions, improvement in the consistency of well performance and significant operational gains. The calamity well, the Jane wells realized an improvement of 15% in drilling and completion cycle time and through our continued focus on capital efficiencies, we've been able to further improve upon this success. This quarter we expect to TIL an incremental 15 wells and expect our Delaware Basin production to continue to grow in the second half of the year.

We've also meaningfully reduced lease operating expenses in the Permian, unit LOE costs were down approximately 20% sequentially and are expected to trend lower as we move through the year. The Eagle Ford asset continues to perform very well, providing cash flow to the business. We brought online 16 decks in the quarter. Many of those TILs were late in Q2 . So we expect to see a big production step up in the third quarter and then decline in Q4. And we won't be adding any new wells in the second half of the year in Eagle Ford. Therefore, our teams will be heavily focused on base production management including testing a refrac concept in Q3. Our offshore focus is really three-pronged. Our teams continue to be very focused on reservoir management and base production optimization. We're advancing near term development projects, primarily Leviathan and Alen while planning for future monetization of world-class low cost discovered resources in the Eastern Med and West Africa.

So, I'll begin with Israel. Tamar produced 950 million cubic feet equivalent per day in Q2, which was better than expected. And the third quarter, remember it is typically the highest quarter of the year based on seasonal demand, and we expect the asset to average over a Bcf per day in Q3. As Dave mentioned, the Leviathan project is now nearly 90% complete and I commend our project and our operational teams and our many partners around the world that are supporting the project and delivering an exceptionally well managed major project. We also discussed the competitive advantages of Leviathan will deliver to the company, but it bears repeating. Our total company production decline rate pre Leviathan is in the low 30% per year range. As Leviathan comes online that annual decline rate improves to the low 20s. Leviathan itself, remember, has essentially no decline and we expect production at Leviathan to grow with market demand over the first couple of years without any additional capital.

This kind of high-quality asset reduces volatility, it provides more cash flow certainty and creates more capital allocation flexibility across the portfolio since it requires less capital to maintain the base production and that's an important differentiator for us. As Leviathan commences production, we will begin moving significant quantities of gas to Jordan and Egypt representing a new era of energy exports for Israel. Leviathan gas sales have received some positive press in the last few weeks, we're in conversations with our primary Egyptian customer to firm up quantities from Leviathan and Tamar, you may have seen in the news. We'll keep you updated as negotiation progresses and we can track for increasing gas sales into the growing regional market. Our view for Leviathan in 2020 hasn't changed. We're expecting gross production average about 800 million cubic feet per day, below that average in the first half of the year and closer to a Bcf per day at the end of 2020.

As Dave mentioned to highlight for the quarter was the completion of the technical due diligence on the EMG pipeline, we've now confirmed the physical integrity of the pipe with an in-line inspection and pressure test and we've demonstrated the ability to transport natural gas into Egypt. Over the next few weeks, we'll be working with partners to verify the integrity of the downstream pipelines and complete a sustained flow test of gas into the Egyptian grid. The flow test is the final critical path item to closing the EMG pipeline acquisition, which we expect by the end of the third quarter.

We also remain focused on longer-term market in transport options to monetize additional gas, including the expansion of the regional pipeline infrastructure. You may have also seen this week that we're evaluating a floating LNG project, which has the potential to deliver gas in the global markets at a competitive supply cost. That project would require minimal near-term capital as it would be required under the concepts that we're reviewing.

Our West Africa assets continue to be a stable supply of cash flow from existing developments and additional high-return projects. We're currently drilling the horizontal portion of the Aseng 6P well and be moving to the completion phase within the next few weeks. The well is expected to be online early in the fourth quarter, gross production is expected to be approximately 10,000 barrels of oil per day, which will result in about a 60% increase in current field production

The well returns clearly benefit from the use of the Aseng infrastructure. Our Alen team has done an exceptional job of identifying opportunities to increase condensate rates in the field. And as a result, Q2 production was above budget. The gas monetization project at Alen that we announced in Q2 represents another opportunity to add production and cash flow in 2021. Like Leviathan, Alen will have a growing production profile for several years without the need for additional capital.

We've updated guidance on slide 18. The capital expenditures for the third quarter estimated to be in the range of 600 million to 675 million with the majority of the capital spend in the US Onshore and Eastern Med regions. Onshore will be down sequentially and offshore will be up largely due to the Leviathan installation and the Aseng well. We've lowered our full-year capital range by $100 million and we anticipate meaningfully lower capital in the fourth quarter with lower onshore completion activity and lower Leviathan capital as the project starts up by the end of the year.

We've also lowered our full year unit production expenses and DD&A ranges and raised our full-year production outlook. Q3 will be our largest volume quarter for the year as all business units are expected to be up within the USO, we should be up about 10,000 barrels of oil per day in the third quarter with moderate oil growth in the fourth quarter. At this point, everything we can control is moving in the right direction.

As we move to Q&A, I want to leave you with three thoughts. 1, we are delivering on expectations across the company and are ahead of plan. Our strong execution in the first half of 2019 positions us well for the second half of the year for 2020 and for the longer term planning horizon. 2, we're nearing a huge inflection point for the company. The rate of change is being led by the capital efficiency improvements in our US Onshore business and the massive swing in net cash flows from Leviathan which is now just a few months away. And 3, we have a sustainable long-term outlook our portfolio quality and reduced maintenance capital requirements position us extremely well for long-term sustainable free cash flow increasing corporate returns and the ability to return more capital to our investors.

Operator. That completes our prepared remarks, please open the call for questions.

Questions and Answers:

Operator

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question today will come from Arun Jayaram of JPMorgan.Please go ahead.

Arun Jayaram -- JPMorgan -- Analyst

Yeah, good morning Brent maybe this one is for you. I was wondering if you could talk a little bit about the sustainability of the well cost savings that you outlined in slide 5 and how the row development strategy is helping you achieve some of those well cost savings

Brent Smolik -- President and Chief Operating Officer

Yeah, thanks, Arun. Great question. The things that we're doing that are most sustainable are on the completion side of the business, we've been able to fairly significantly improve the pumping hours per day and the number of stages that we're able to get done per day and we've-we've actually added some incentives into the contracts with our service providers to push those numbers up even further and a lot of it is just better day-to-day execution and taking out waste in and downtime in the operations, that part is very sticky and very sustainable.

The other parts of it that are design related are changing how we do our business and so the best example to point to is the lower fluid frac designs in the DJ, those have a lot of benefits, because that we get lower cost for the frac fluid -- the fresh water fluid to start with, we shortened the pump times and get more stages done per day. We increased the -- decreased the cycle time and get well on production quicker and we have less disposal cost on the backside. And those kinds of design changes along with a lot of others are sticky, even if we get back into an inflationary environment. And then we have a number of things that we're working on them to continue to manage the supply chain side of our business, but I think most of what we're doing into a row development point is -- row development only improves the probability of being able to get all those efficiency gains.

So I'm really happy with the progress we've made so far on getting faster.

Arun Jayaram -- JPMorgan -- Analyst

And then those lower fluid designs. What can you speak to in terms of productivity there

Brent Smolik -- President and Chief Operating Officer

So far so good. Remember that we've got some of the highest productive wells up in DJ and we continue to see high productivity per well. Returns are better because of lower capital cost and higher efficiencies. So hopefully we'll get the benefit of both top numerator and denominator .

Arun Jayaram -- JPMorgan -- Analyst

Great. And my follow-up. Dave, perhaps for you. The NBLX strategic alternatives process, we've gotten some questions. Given the departure of NBLX's CFO quite recently our analysis suggests that it's a relatively short cut to well over $2.5 billion in total value kind of net to Noble, but could you provide us an update on the process and maybe some of the pros and cons of a potentially monetizing a portion of your interest here.

David L. Stover -- Chairman and Chief Executive Officer

Not really anything to elaborate on I'd go back to my prepared comments, Arun, that when there is something will tell you, I think you do bring up a good point, though and that's the value of the NBLX business itself. I mean, you look at the, release they sent out this morning, they're hitting on all cylinders also in the second quarter. They've got some transformative things coming up like the EPIC Pipelines coming up, their focus just as Brent has talked about, on decreasing costs and their overall business. So it's just a very valuable business

Arun Jayaram -- JPMorgan -- Analyst

Great, thanks a lot.

Operator

Our next question today will come from Brian Singer of Goldman Sachs. Please go ahead.

Brian Singer -- Goldman Sachs -- Analyst

Thank you. Good morning.

Unidentified Speaker

Hey, Brian,

Brian Singer -- Goldman Sachs -- Analyst

You highlighted on Leviathan expectations for growth volumes in 2020 to average about 800 million a day. Can you talk more about how that ramp up looks over the course of the year or if it is consistent for the year. How much you expect to go to domestic versus international markets? And then whether you see Tamar cycling down or whether the 800 is fully incremental.

David L. Stover -- Chairman and Chief Executive Officer

Yeah, I think what we're seeing is we'll have truly incremental volume here and what Brent I think alluded to in his comments was that you've to expect the first half of the year will be under that average and the second half of the year will be over and set ourselves up nicely to exit the year around that Bcf a day or so. --- So, the whole outlook I think is similar to what we've been saying, but we're continuing to firm up contracts. We're seeing the demand continue to increase, folks wanting to firm up more demand you're seeing and Israel, the discussion around accelerating coal conversion.

So I think it's just as somewhat we expected is Leviathan is coming closer to coming online is becoming more real for folks and it's firming up what our outlook can be and what even the potential upside could be, when you look beyond 2020

Brian Singer -- Goldman Sachs -- Analyst

Great. So the Bcf a day by the end of the year is fully incremental cycling down at or declines at Tamar?

Unidentified Speaker

I think there is going to be enough when you look at internally in Israel and the regional capacity that they'll be wanting everything being delivered from Phase 1 of Leviathan and everything we can deliver from tomorrow, especially as you get toward the end of '20 and beyond.

Brian Singer -- Goldman Sachs -- Analyst

Great. And then my second question is with regards to the Delaware Basin and well productivity. Can you just talk to as you continue to bring on more of the row developments what your expectations are for the -- for how productivity goes from here. And then how you see if at all oil rates evolving relative to the kind of 50% to 60%?

Unidentified Speaker

Yeah, the primary thing we're seeing from the row developments is we have less between well interference and more consistency in the well performance. So we get less of the parent child kind of interference it causes a lot of scatter in the results and I think that's a positive and our average is up of our total returns. In the field, our best performance is still Wolfcamp A and the third Bone, which -- spending most of our program and most of our capital on this year and those results are good and you can see that even in [Indecipherable] rates that we released. So I think that all feels like it's on track to us. We've been admittedly spending a lot of time on our capital efficiency and we talked a lot about it in the first half of the year and the results are compelling. But we've also continued in the background to work on improving well productivity and hopefully over time we'll be talking you more about those improvements.

Brian Singer -- Goldman Sachs -- Analyst

Great. Thank you.

Operator

The next question will come from Doug Leggate of Bank of America. Please go ahead.

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

Thanks, good morning everybody. Guys I wonder if I could circle back to Israel for a second and as you pointed out, there has been some noise in the press around the Egyptian contracts in particular, but I'm just curious about when you talk about little capital required for material growth. Can you just walk us through what the current redundant -- what the redundant capacity would be at both Tamar and Leviathan, let's say once both are online and any kind of reasonable guide that you think or idea that you think is to how quickly you could see that capacity utilized with no material incremental capital? And I've got a follow-up please.

Unidentified Speaker

I think the simplest way to think about it is that we've guided to about 800 million a day average gross production from Leviathan for 2020 and without additional capital into the facility and wells will be capable of about 1.2 Bcf a day and we could ramp that up over that first two to three year period depending on market with no additional capital. So it's kind of inclining base production from 800 to 1.2.

David L. Stover -- Chairman and Chief Executive Officer

And then I think Doug what you're alluding to then beyond filling up the first phase of Leviathan and that's when you start getting into the incremental capital when you get above that 1.2 Bcf a day and we can do that very efficiently as you well know, we've set up the production facility to be able to incrementalize with modules up there in 200 million to 400 million a day increments. And then you're looking at each well can deliver 300 million a day. So the real pace will be how it evolves from where you are going to flow the gas to on your phases of beyond Phase 1.

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

I guess what was behind my question was I seem to recall you had pre-billed a couple of hundred million dollars of expansion capacity in your Leviathan budget plus you've got a 600 million a day redundant in your platform producing a 10th of that in Mari-B. I'm just kind of trying to understand how you optimize a lot of redundancy, it's kind of like if you build it, they will come. I'm wondering if having [Indecipherable] capacity available and more reliable operations if you like, if there is a latent customer base that is going to allow you to run quicker that's kind of really what I was trying to get?

Unidentified Speaker

And that will play itself out, especially as we get into 2020 and everything is up and running and you start to get this ramped up, Leviathan ramped up and you see what that demand is, then folks start to see as we talked earlier that it's more and more real, it's here. It's now you've got both Leviathan and Tamar and they're very low cost sources of supply and go back to how Tamar ramped up and how quickly it ramped up through demand once it came online and I think that's a good precursor, if you will, how we could say 2021 plan up. Your point is exactly right. Taking advantage of existing infrastructure is going to be an incremental benefit as we move forward here in the basin. And the way Keith and his team have laid this out with the pre-planning that we can take this platform from 1.2 Bcf a day to 2.1 Bcf a day and we can do it now in increments as its demand dictates is going to be a benefit. So all of this infrastructure in place just continues to build on that and that's the importance of also having multiple outlets and multiple pipeline takeaways.

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

We think it's almost the entire value of your company right now with your share price is trading but anyway I'll let my follow up is really a quick one, just on the capital guide for next year. Obviously, you're talking about material reductions, I assume the 5% to 10% ex-major projects, is still a good number on a go forward basis associated with that decline in spending, but I'm wondering if you could just give us an idea of what your sustaining capital is in the event the oil prices did come under pressure given all that micro stuff going on. What is the sustaining capital when Leviathan is online to hold your -- your exit rate this year flat, I don't know if you've got something like that to hand but some kind of bold part [Phonetic] would be helpful?

Unidentified Speaker

I think when we -- when we talked about it last year, or earlier this year we laid out a maintenance capital, if you go back to that one slide where we laid off maintenance capital and then we had two transfers above that and that was 1.5, 1.6 type range. I think the nice part of what Brent and his team is working on what the whole organization is working on is improving the capital efficiency, lowering our capital intensity and we'll see where we get to at the end of the year, but I don't see it being higher than that.

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

Great stuff. Thanks for taking my questions, guys and congrats.

Unidentified Speaker

Thank you, Doug.

Operator

The next question will come from Scott Hanold of RBC. Please go ahead.

Scott Hanold -- RBC Capital Markets -- Analyst

Yeah. Thank you. If I could just add on to that last question. And as you look at these well cost reduction, they were fairly significant so far this year, especially in the onshore and you're seeing a lot of efficiencies and how does this help craft your thoughts about US Onshore spending as you go into 2020 and 2021 where you've got large projects really supporting some pretty solid growth?

David L. Stover -- Chairman and Chief Executive Officer

Well, that the focus in 2000 and 2021 will be delivering that free cash flow. Though the spending will fall out of that. But all of this work that the team has been doing and all the progress we've been making on lowering and improving those efficiencies is just going to help in that regard, but I don't know, Brent, anything else to add there.

Brent Smolik -- President and Chief Operating Officer

Yeah, I would just say notionally we're not thinking of higher activity levels. Scott, we're thinking of similar activity levels without finalizing a budget, which would imply, lower than we previously had planned capital because of the efficiencies.

Scott Hanold -- RBC Capital Markets -- Analyst

Okay, great, thanks for that. And then is my follow-up. If I can refer to page 5, a little bit more on the well cost in the DJ and the Delaware and what really stands out as the marked shift in the cost savings on well design in the DJ Basin and correct me if I'm wrong if that's doing the lower fluid fracs. Is that something that you're going to test soon in the Delaware, is that some like could actually be another incremental saving for the Delaware wells?

Unidentified Speaker

Yes, it's possible. We don't have any of them to report on yet, but if we convince ourselves that we can get the same productivities in EURs in the DJ then it would be something that would be transportable elsewhere.

Scott Hanold -- RBC Capital Markets -- Analyst

How long is it -- like how long do you need on DJ data to make that determination. Is that something that could be a 2020 initiative?

Unidentified Speaker

Yes. Yeah, even late this year, we might try to put some in the ground. But I think of it as longer term in the Delaware and I want to point out too. That's not the only thing that's included in that design change bucket, we talk about it, because it's a big and noteworthy accomplishment, but we've changed the design on how we go about executing on the frac jobs, in a lot of ways we're pumping down perforating guns faster, we're bumping down plugs faster. We're changing chemistry's along with the fluid volumes, there's just a lot of things that we're doing in the design changes that add up to a big number.

Scott Hanold -- RBC Capital Markets -- Analyst

Okay. So, is it more advanced right now in the DJ. Is that where you're seeing a bigger step change in the DJ versus the Delaware?

Unidentified Speaker

I think we're seeing a bigger step change because -- because we've made more design changes and they are more advanced in the Permian, we saw a bigger supply chain reductions, because there had been so much inflation that we've clawed some of that back.

Scott Hanold -- RBC Capital Markets -- Analyst

Understood, thanks.

Operator

Our next question today will come from Welles Fitzpatrick of SunTrust. Please go ahead.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Hey, good morning.

Unidentified Speaker

Morning, Welles,

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

you guys talked about Saddlehorn and that details great. But can you point us to where you're looking for relief on the gas and the NGL side in the DJ, whether that's Cheyenne [Phonetic] or some other project coming up

Unidentified Speaker

yeah, I think, I think on the gas side, I think we'll see some relief as soon as DCP works through the current restart of the plant -- the O'Connor Plant 2 or DCP Plant 11 and that will happen we think next week, it will start to ramp back up again. And so the gas is going to debottleneck it itself. I think you know, by the third and fourth quarter we'll see enough NGL capacity where the constraints in the basin will get relieved.I think that will clear itself up in the near term and we factored that into our updated guidance.

Unidentified Speaker

I think you're also seeing some conversion going in place on NGL line with White Cliffs up there too that should be helpful if it gets finished up there.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Okay, OK perfect. And then from a follow-up on the new proposed Colorado AQCC emissions rules, I know you guys stay pretty far ahead of that. Is it fair to say that there won't be significant incremental costs and also could that open up any opportunistic A&D as maybe smaller companies exit

Unidentified Speaker

yeah, not telling on A&D, that's just not something we're focusing on up there. I think that the main focus for us as we talked about earlier is getting this next comprehensive development -- drawn development plan in place, the CDP, and I think that's one of the things that will enable us to stay ahead of the game up there, just as the original one has

Unidentified Speaker

and on the emission side, I mean we already enjoy low emissions and because we've been focused on it for some time. The biggest advantages we have is a lot of the operation. A lot of the surface facilities are nearly tankless [Phonetic] and we're -- we're looking at designs at both reduced emissions further and reduce costs, which is the best of both worlds.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Perfect, thank you so much.

Operator

The next question today will come from Michael Hall of Heikkinen Energy Advisors. Please go ahead .

Michael Hall -- Heikkinen Energy Advisors -- Analyst

Excuse me. Thanks, good morning and solid work this quarter. I was just curious on the near term -- some near term stuff, on the July volumes you posted for the US Onshore already tracking pretty close to the full 3Q US Onshore guide, how should we think about the rest of the quarter from an activity standpoint, is there some sort of little in August. So we should expect or back loading in the quarter or have you really just erased the third quarter already pretty substantially with the July result.

Unidentified Speaker

Yeah, that's, it's a little unusual for us to give you an estimate for the, for the next quarter, but we thought it was important because enough of those TILs came on late in the second quarter across the company really in all areas that, it has a meaningful impact on the third quarter growth and we're seeing it showing up. So that was the key message, if you look, go forward I pointed out in the comments that in the Eagle Ford we're done with drilling and completing wells this year. We do have a refrac pilot that will happen later in the year, but it won't be meaningful in terms of the production profile. So we'll see Eagle Ford decline. It will grow significantly from second to third and then decline significantly from third to fourth. The other parts of the business. DJ and Delaware will see the step up to third quarter and then a little bit of growth into Q4.

Michael Hall -- Heikkinen Energy Advisors -- Analyst

Okay, makes sense. And then I was just curious on the kind of bigger picture on the 2019 capital program, taken on the capex, obviously a positive. You had a TILs a bit ahead of schedule in the first half, efficiencies have been outpacing expectations. How are you guys thinking about the potential for efficiencies to continue improving in the back half and then putting in a position where you're kind of continuing to put on more wells than originally planned. would you bias toward a frac holiday in the back half of the year or how would you manage capital, I guess, is what I'm trying to get at.

Unidentified Speaker

Let me kind of take it in bite-size pieces, if you go back to our original plan, we had always planned to be a little bit front half loaded on completion activity in TILs and a back half loaded on production because of the lag when it shows up. We have accelerated some of the TILs into the second quarter due to efficiency gains. We will add a few at the end of the year. So our profile front half to second half looks a lot like we budgeted and we're kind of on plan with it. To the efficiency gain part of it, you're talking about is the reason I signal that we've set some records recently in drilling and completions is because if we can do that once we can replicate it and we are replicating it in the programs in the second half of the year. So we do expect to continue to drive efficiencies into Q2, that could accelerate production a little more, but in regards to the way we think about the end of the year, we're not, targeting a number of completions. It's more about designing a smooth glide path into the end of the year as we idle equipment that we had already -- we always had planned to have some holidays at the end of the year. And so you just want to make sure you do that as efficiently as possible where we don't stop in the middle of a pad, disrupt any of our supply chain, stop when we don't have facilities [Indecipherable] , there is a lot of things that are important to think about as you ramp down and ramp back up again later.

And so that's how we're trying to design it to be as efficient as possible both in how we take out cost as we're doing it and is how we slow it down

Michael Hall -- Heikkinen Energy Advisors -- Analyst

Great. That makes a lot of sense. And in that glide path . It seems to kind of suggest the 2020 rate on US onshore capital spend is probably hitting lower relative to prior expectations. Is that a fair -- fair comment. And does that by a free cash flow higher in terms of relative to prior expectations on 2020.

Unidentified Speaker

We haven't fully baked 2020 yet but all things being equal, we would expect the efficiencies to carry into 2020 and it would be -- would be positive to free cash flow

Michael Hall -- Heikkinen Energy Advisors -- Analyst

All right, thanks guys. Again congrats.

Operator

Our next question will come from Irene Haas of Imperial Capital. Please go ahead.

Irene Haas -- Imperial Capital -- Analyst

Congratulations. Firstly on Leviathan, this process has been the long haul. And my question is related to East Med and I think at one point you guys talked about of floating LNG. And why is this coming back into the picture. And what would be the incremental production you're thinking of monetizing using this sort of facility. And then also how much lead time you need and how would you finance it.

Unidentified Speaker

Well, I'd just tell you why we're even looking at it Irene and then Keith can talk to some of the other logistics of things, but the reason we're looking at it is -- it for a longer-term -- say a second or third phase of Leviathan potential and it just creates more optionality for us and it's, we would view it and we would only do it as a low-cost option to create more optionality and broaden our marketing reach, if you will. So those would be the reasons you look at it far from doing it at this point as I'd look at it. And as far as timing of how that would play out. Keith, any thoughts.

Unidentified Participant

Yeah, I mean, I think just to build on Dave's point. As you know, we've looked at FLNG before. I think the thing that's different now as we see the ability to connect with a proven vendor, who has got systems up and running in other parts of the world, and they come forth with an idea of taking process gas stream off Leviathan that becomes a very cost competitive solution, at least in the initial looks at it as far as timing. We're early in days. We're in the feed now and so it's something that Dave said that's, it's a second phase project that's a few years down the road.

Unidentified Speaker

and this would need to compete with the other things that would be in our plan that would lay out there. So it's not a capital change is nothing different from that standpoint. It's just creating optionality and potentially broadening our market reach for long-term value,

Irene Haas -- Imperial Capital -- Analyst

if I may have a follow-up. Does it sound like does this vendor would actually -- is it going to be in leasing or do you have to how much money do you need to put in. Then lastly any action in Cyprus

Unidentified Speaker

yeah, I think I'd go back to my original comment. The only way we would do it is if it's a very low cost option for us compared to other things we'd be looking at, that's what it would take to compete. So far from -- far from firming anything up there, but that would be the gist of it. Cyprus, those discussions are ongoing. There has been a lot of progress toward that. That's something that still can have tremendous value longer term, but it's probably a step behind Leviathan obviously in the queue right now.

Irene Haas -- Imperial Capital -- Analyst

Great, thank you.

Operator

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

David Deckelbaum -- Cowen and Company -- Analyst

Morning, guys, thanks for the time. When you guys lowered your capital budget for the year is the $100 million delta. I guess, is that entirely coming out of US Onshore I guess because I know other people asked around Eastern Med spending, but relative to the 550 to 600 budget that you laid out, you're trending a bit below that at this point, what kind of visibility you have for the rest of the year in terms of the Leviathan budget, particularly as the US Onshore comes down for the rest of the year?

Unidentified Speaker

Yeah, I think you should think of it right now as primarily US Onshore the $100 million. But you're right in pointing out that we're 90% complete and we've effectively derisked some of the important phases, we derisk the subsea wells the subsea tie-ins, the umbilicals, pipelines and most of the fabrication and so now we're down to install and commissioning -- final commissioning. So we are getting -- we are, the project is trending well. So we're optimistic that there'll be some room, but think primarily of it as an US Onshore realized savings that we've dialed in.

Unidentified Speaker

For a better line of sight to how the final Leviathan capital turn out as we get the platform said and we get through the third quarter and then we'll be able to give them more expectation around that, but the Brent point. It's been a well managed well run project and extremely pleased with where we are.

David Deckelbaum -- Cowen and Company -- Analyst

I appreciate that. Could you shed a little bit more color around the exploration targets for next year, I guess, namely in Colombia, have you identified targets already. At what point in the calendar is endeavor is going to start taking place, and you sort of have a loose budget in mind for exploratory endeavors next year?

Unidentified Speaker

Yeah, I think when you go back to what we've talked about on total exploration capital, which would be the drilling and the other components we've talked about 100 million to 130 million or so, I think Colombia itself would be one well, probably the second half of the year, most likely us and partners, working with the government, are finalizing the target. it's pretty much set, and again that's targeted to be hopefully an oil play, that's probably some of the real remaining question there, it's got a fairly high for an exploration project piece of G or chance of finding hydrocarbons. But our team is really focused on a liquid oil play potential there, and it will be exciting to get drilled and tested in the second half of next year.

David Deckelbaum -- Cowen and Company -- Analyst

Thank you, guys.

Operator

The next question will come from Charles Meade of Johnson Rice. Please go ahead.

Charles Meade -- Johnson Rice -- Analyst

Good morning, Dave and Brent and the rest of your team there. I wanted to go back. This has been touched on a few times in the Q&A, but I want to go back to your, your comments and your prepared remarks about the 2020 capex outlook and I'm not trying to pin you guys down on anything but I want to get a sense of what are some of the big pieces that are in play. And I think that the one biggest piece looking at '20 over '19 would be -- would be Eastern Med capex and you guys got the 550 to 600 this year and it's not going to go to zero, but there's going to be a big chunk that comes out of there, what are the other pieces that we should be thinking about as we try to think about how '20 might look?

David L. Stover -- Chairman and Chief Executive Officer

Well, to your point, it's still early, will be poor [Phonetic] in a budget later this year and some other things that we know about already though obviously you've got Alen capital, but it will be higher next year obviously than this year. So that would be the one increasing piece. There will still be some capital as you mentioned in the Eastern Med, some of the FEED work, some of the planning that we've talked about for some of the things to stay ahead of market moving forward. And then the other big piece will be the year-on-year movement in onshore and we'll just have to see how that plays out how the efficiencies and the continued momentum play out.

I think the other piece we just touched on is exploration will be a little bit higher next year as we go back to drilling, at least as it's laid out now, but I mean those are just some of the components and obviously we'll have more color as we get into the end of the year.

Charles Meade -- Johnson Rice -- Analyst

Got it, thank you for that. Dave. And then if I could ask a question about the Delaware Basin in less about what happened in the quarter, but more kind of your, the longer trajectory there where -- you guys have a graphic in your presentation shows the I guess the gun barrel view on your spacing there. Can you talk about how much you've iterated and maybe how close you are to being comfortable with that kind of a final decision on what well spacing is at least, at least in the $55 or $60 world. And if you think you've arrived at the right development concept for the current set of conditions or if there's still more learning, you have to do?

Brent Smolik -- President and Chief Operating Officer

Charles. I think the high level answer is, yes, that we've been pretty consistent in the three wells in the Third Bone per section and six in the Wolfcamp A. So I think we're happy with this phasing, I think what you'll hear has been more time talking about is landing zone, getting very specific about landing zones and then optimize completion designs the frac designs and that's something we got to be really mindful of even as we move north, south, east-west in the field. So those, I think the spacing we're pretty comfortable with and we're happy with it in that the one example of the Calamity Jane that we've got in the deck there.

Charles Meade -- Johnson Rice -- Analyst

Thank you for that added detail Brent.

Operator

Our next question will come from Jeanine Wai of Barclays. Please go ahead.

Jeanine Wai -- Barclays -- Analyst

Hi, good morning everyone.

Unidentified Speaker

Good morning Jeanine.

Jeanine Wai -- Barclays -- Analyst

Good morning. My first question is on the Delaware, you continue to just have more activity in the northern part of your acreage and the results look really good. And it looks like the south has been trending around 25% of completions in Q1 and Q2 of this year. So. I just wanted to understand how you think north versus south will be trending in activity in 2020 and if you have any HBP requirements in the south that may be coming up and just overall, how much activity can the southern and central gathering facility handle?

Unidentified Speaker

We haven't guided yet to the specifics on 2020. But I think you should assume that we're in a similar frame of mind that we're going to fill up the CGS, we've got three large ones in the north. We've built the superstructure infrastructure to be able to connect them all this year. So we have a lot more operational for at least the midstream company has done that to give us operational flexibility to move volumes around. We've got capacity in the facility to the south. There, we have seen some fairly high rate wells delivered in the south, and we think that's a function of completion design and landing zone again. So we're going to continue to do some activity down there. And so I think you can think of it as similar in our strategy and approach.

Jeanine Wai -- Barclays -- Analyst

Okay, great. And then my follow-up question I wanted to circle back on Michael's earlier question, efficiencies are clearly going better than expected, which is good. And we notice that the prior 2019 completions guidance implied only eight in the DJ and four completions in the Delaware in the fourth quarter, but I think I heard you say on your prepared comments that you're now planning on doing more than that with overall less capex, so just wanted to clarify that, to make sure we got that. And I'm asking because we just want to understand how you're thinking about kind of the double-edged sword at this point given the space with activity and growth with better than expected efficiencies and we know that yeah the commentary out there that 2020 you kind of expect to have the same activity that you laid out in the prior to your plan, but potentially and lower capex, and just wanted to square your thoughts on how things are heading into the 2020 given the overall focus on free cash flow and the inflection next year?

Unidentified Speaker

It's just a lot in there. I think the way to summarize it, is that that that our thinking is really unchanged. We're delivering on what we said we were going to do this year and we're doing it more cost effectively and that's going to allow us to do a few more completions in primarily the DJ but a couple of more in Delaware, but it's really not a big change and then those efficiencies will be we think are the kind of things that are sticky and so will carry them over into our activity for 2020.

Unidentified Speaker

Yeah. And I guess Jeanine the main point there. As we look to 2020, we're not fixated on an activity level, what we're focused on is delivering the free cash flow.

Jeanine Wai -- Barclays -- Analyst

Okay, perfect. Thank you very much.

Operator

Our next question will come from Leo Mariani of KeyBanc. Please go ahead.

Leo Mariani -- KeyBanc Capital Markets Inc -- Analyst

Hey, guys. question on the DJ. Just wanted to get a sense if you guys are seeing anything incrementally on the regulatory cost side, starting to flow through at all their past the the recent energy build there. What would you guys on the ground there?

Unidentified Speaker

Right. Too early to really seen anything that I mean there is still working through some of the rule making. And I think again I'll go back to our big benefit instead of having to go for one off permits, we're getting a lot of them done at the same time to be more efficient, whether it was that original CDP or the one that's in the system now. So that will be the thing that will make us the most cost efficient operator in the basin.

Leo Mariani -- KeyBanc Capital Markets Inc -- Analyst

Okay. And I guess on the midstream side there in the DJ, obviously it sounds like it's debottlenecking nicely here over the next several months. And you guys have any significant shut in volumes you think might be returning and is there any way to kind of quantify that?

Brent Smolik -- President and Chief Operating Officer

The only place I would point you, this is Brent again, the only place I'd point you to is in that July estimate that we gave you that includes, say 7 to 10 days of some of this interruption that we've seen on the DCP System and we were still able to deliver the numbers that we released in July.

David L. Stover -- Chairman and Chief Executive Officer

And I think Brent's point that highlights the work that's been done over the last year or two to provide multiple outlets and give us more flexibility in the basin and that's always the key.

Leo Mariani -- KeyBanc Capital Markets Inc -- Analyst

Okay, thank you.

Operator

The next question will come from Michael Scialla of Stifel Nicolaus. Please go ahead.

Michael Scialla -- Stifel Nicolaus -- Analyst

Good morning. I think this year's plan originally included 500 million to a billion of divestitures. Just want to see if you could talk about where that process stands?

Unidentified Speaker

Yeah, we're on track with that. We've got multiple ways to deliver that. And as those get firmed up, we'll talk about them, but feel good about being on track with the whole program.

Michael Scialla -- Stifel Nicolaus -- Analyst

Great. Brent you talked about quite a bit in terms of the design changes you're making with the lower fluid and proppant and obviously seen lower cost benefit there and early rate benefit. I, just wondering if there is, are you thinking in terms of maybe it's a trade-off with longer-term rates. And do you have enough data there to show that the economics are superior with the lower intensity [Indecipherable] ?

Brent Smolik -- President and Chief Operating Officer

I think we have confidence that the returns will be higher, which is a biggest driver. We don't have proof yet long term that the EURs will be the same or higher. But when we run sensitivities. We're still better off even if we saw a modest reduction in EUR. Because the cost benefit and the site and accelerated production offset any other loss in the EUR. So we're happy with it, with the returns that we're seeing from it.

Michael Scialla -- Stifel Nicolaus -- Analyst

Good, thank you.

Operator

Our next question will come from Gail Nicholson of Stephens. Please go ahead.

Gail Nicholson -- Stephens Inc. -- Analyst

Good morning, everyone. Brent. in one of the answer to the question you talked about the importance going forward kind of landing in the optimal landing zone in the Delaware ,when you kind of look at the program to date, what do you think the percent of current execution has been landed at the optimal down and kind of how much improvement you think that you guys can achieve kind of over the next 18 months?

Brent Smolik -- President and Chief Operating Officer

I don't know how to answer the percentage of wells, but we have very landing zones even like within the Wolfcamp A. If you go back and look in time, you'll hear us talk about Wolfcamp A Upper, Wolfcamp A lower inside of that there is various spaces that we're moving around. And so, part of what we were doing in addition to the capital efficiency improvements is looking at all data in the basin and all operators and taking additional core data and doing some analysis of the core, that's all designed toward optimizing landing zones and completion designs, so it's all work in progress. So I think that's just long way of saying there is additional room -- additional improvement to be had by narrowing down and locking in on landing zones.

Gail Nicholson -- Stephens Inc. -- Analyst

Okay, great. And then my follow up is back to the non-productive time you've mentioned you've seen good improvement there. Can you quantify where the non-productive time is today, and where it was in 4Q and how it differs in the DJ versus Delaware?

Unidentified Speaker

DJ versus Delaware, they were similar. In our DJ Basin, we had as much as 3 hours between stages in the worst case, and we've been able to get that down to 30 minutes or so. And so we had similar kinds of inefficiencies in the Delaware program. Those are the same kinds of things we've been chasing out in both places.

Gail Nicholson -- Stephens Inc. -- Analyst

Great, thank you.

Operator

Ladies and gentlemen, this will conclude our question and answer session. At this time, I'd like to turn the conference back over to Brad Whitmarsh for any closing remarks.

Brad Whitmarsh -- Vice President, Investor Relations

Thanks, Allison again and appreciate everybody joining us today. Should you have any follow-up questions, please don't hesitate to reach out to Park, Kim or myself. Hope everybody has a great weekend.

Operator

[Operator Closing Remarks]

Duration: 65 minutes

Call participants:

Brad Whitmarsh -- Vice President, Investor Relations

David L. Stover -- Chairman and Chief Executive Officer

Brent Smolik -- President and Chief Operating Officer

Unidentified Speaker

Arun Jayaram -- JPMorgan -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

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

Scott Hanold -- RBC Capital Markets -- Analyst

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Michael Hall -- Heikkinen Energy Advisors -- Analyst

Irene Haas -- Imperial Capital -- Analyst

Unidentified Participant

David Deckelbaum -- Cowen and Company -- Analyst

Charles Meade -- Johnson Rice -- Analyst

Jeanine Wai -- Barclays -- Analyst

Leo Mariani -- KeyBanc Capital Markets Inc -- Analyst

Michael Scialla -- Stifel Nicolaus -- Analyst

Gail Nicholson -- Stephens Inc. -- Analyst

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