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Edited Transcript of NBL earnings conference call or presentation 2-Aug-19 1:00pm GMT

Q2 2019 Noble Energy Inc Earnings Call

HOUSTON Aug 8, 2019 (Thomson StreetEvents) -- Edited Transcript of Noble Energy Inc earnings conference call or presentation Friday, August 2, 2019 at 1:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Brad Whitmarsh

Noble Energy, Inc. - VP of IR

* Brent J. Smolik

Noble Energy, Inc. - President & COO

* David L. Stover

Noble Energy, Inc. - Chairman & CEO

* John Keith Elliott

Noble Energy, Inc. - SVP of Offshore

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Conference Call Participants

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* Arun Jayaram

JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst

* Brian Arthur Singer

Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst

* Charles Arthur Meade

Johnson Rice & Company, L.L.C., Research Division - Analyst

* David Adam Deckelbaum

Cowen and Company, LLC, Research Division - Senior Analyst

* Douglas George Blyth Leggate

BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research

* Gail Amanda Nicholson Dodds

Stephens Inc., Research Division - MD & Analyst

* Irene Oiyin Haas

Imperial Capital, LLC, Research Division - MD & Senior Research Analyst

* Jeanine Wai

Barclays Bank PLC, Research Division - Research Analyst

* Leo Paul Mariani

KeyBanc Capital Markets Inc., Research Division - Analyst

* Michael Anthony Hall

Heikkinen Energy Advisors, LLC - Partner and Senior Exploration & Production Research Analyst

* Michael Stephen Scialla

Stifel, Nicolaus & Company, Incorporated, Research Division - MD

* Scott Michael Hanold

RBC Capital Markets, LLC, Research Division - Analyst

* Welles Westfeldt Fitzpatrick

SunTrust Robinson Humphrey, Inc., Research Division - Analyst

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Presentation

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Operator [1]

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Good morning, and welcome to Noble Energy's Second Quarter 2019 Earnings Results Webcast and Conference Call. (Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to Brad Whitmarsh. Please go ahead.

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Brad Whitmarsh, Noble Energy, Inc. - VP of IR [2]

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Thank you, Allison, and 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. (Operator Instructions) 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.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [3]

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Good morning, everyone, and thanks for joining us. It had started out as a volatile earnings season for the industry, but we are 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 are 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 startup.

Across our portfolio, we've 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 startup establish the foundation for performance in 2020 and beyond. Noble is positioned to distinguish itself through 3 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 includes 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 fourth quarter in a row, our total capital came in below expectations. This was driven by onshore U.S. well cost 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 2/3 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 towards 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 accomplishments 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 multiyear 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 row 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, and we will update the market when appropriate.

Providing diversification to our U.S. 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's 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 deck set sail 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 of 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, and 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 a handful of onshore unconventional wells in Wyoming along with an offshore Colombia prospect test next year.

Overall, I am 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's. 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 have 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 noncash 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 and returns through innovation and continuous improvement.

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Brent J. Smolik, Noble Energy, Inc. - President & COO [4]

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Morning, everyone. Thanks, Dave. I echo your comments on the dramatic rate of change and the significant inflection point that we are experiencing.

As evidence, the U.S. 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 USO 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 are 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 -- of Q2 execution included record drilling times in both the DJ and Delaware Basins. Several of our 9,500-foot laterals in DJ were drilled in less than 5 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 completions 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've continued to refine our completion designs, including, in some cases, lower proppant concentrations and fluid volumes. 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 underway 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 netback 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.

Here in 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 and Noble Midstream have 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 and 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 from Mustang Row 2. The Mustang area continues to perform very well. The gross production from Rows 1 and 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 on Row 2. The Mustang 408 DP has 24 wells, 12 of which were pumped with lower fluid design and 12 with our previous design. Reducing fluid volumes sustainably reduces cycle time and well cost. The DJ efficiency gains will 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 underway. 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 as 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 explained 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 10 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 constancy of well performance and significant operational gains.

The Calamity well -- the Jane well has 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 DUCs 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. We won't be adding any new wells in the second half of the year at 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, 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 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, it 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'll begin moving significant quantities of gas to Jordan and Egypt, representing a new area -- 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 contract for increasing gas sales into the growing regional market.

Our view for Leviathan in 2020 hasn't changed. We are expecting gross production to 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, a highlight for the quarter was the completion of the technical due diligence on the EMG pipeline. We have 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 flows test -- 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 and transport options to monetize additional gas, including expansion of the regional pipeline infrastructure. You may have also seen this week that we are 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 would be required in the concepts that we're reviewing.

Our West Africa assets continue to be a stable supply of cash flow with -- from existing developments and additional high-return projects. We're currently drilling the horizontal portion of the Aseng 6P well and will 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. Our capital expenditures for the third quarter are estimated to be in the range of $600 million to $675 million with the majority of the capital spend in the U.S. onshore and Eastern Med regions. Onshore will be down sequentially and offshore will be up, largely due to 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. With the U.S. -- within the U.S., oil 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 the Q&A, I want to leave you with 3 thoughts. One, we're 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. Two, we're nearing a huge inflection point for the company. The rate of change is being led by the capital efficiency improvements in our U.S. onshore business and the massive swing in net cash flows from Leviathan, which is now just a few months away. And three, 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.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question today will come from Arun Jayaram of JPMorgan.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [2]

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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.

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Brent J. Smolik, Noble Energy, Inc. - President & COO [3]

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Yes. Thanks, Arun. Great question. The things that we're doing that are most sustainable are on the completions 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 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 and downtime in the operations. That part's 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 we get lower cost for the frac fluid -- the freshwater fluid to start with. We shorten the pump times and get more stages done per day. We increase the -- decrease the cycle time and get well on production quicker, and we have less disposal costs 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 then to continue to manage the supply chain side of our business. But I think most of what we're doing -- and to your 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.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [4]

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And then those lower fluid designs, what can you speak to in terms of productivity there?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [5]

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So far, so good. Remember that we've got some of the highest productive wells up in the 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 the numerator and denominator.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [6]

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Great. And my follow-up, Dave, perhaps for you. The NBLX strategic alternatives process. We've gotten some questions, given the departure of NBLX' CFO quite recently. Our analysis suggests that it's a relatively shortcut 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 potentially monetizing a portion of your interest here?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [7]

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Yes. Not really anything to elaborate on. I'd go back to my prepared comments, Arun, that when there is something, we'll 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 their 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 pipeline's coming up. Their focus, just as Brent's talked about, on decreasing costs in their overall business. So it's just a very valuable business.

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Operator [8]

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

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Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [9]

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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 do you expect to go to domestic versus international markets? And then whether you see Tamar cycling down? Or whether the 800 million is fully incremental?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [10]

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Yes. I think what we're saying is, we'll have truly incremental volume here. And what Brent, I think, alluded to in his comments was that you ought to expect the first half of the year will be under that average and the second half of the year, it'll be over it 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 in Israel, the discussion around accelerating coal conversion. So I think it's just as somewhat we expected. As Leviathan is coming close -- closer to coming online, it's 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.

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Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [11]

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Great. So the Bcf a day by the end of the year is fully incremental, no cycling down at -- or declines at Tamar?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [12]

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

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Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [13]

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Great. And then the 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%?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [14]

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Yes. 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 that causes a lot of scatter in the results, and I think that's a positive and it averages up of our total returns. In the field, our best performance is still Wolfcamp A in the Third Bone, which we're spending most of our program and most of the capital on this year. And those results are good, and you can see that even in the 25 test rates that we released. So I think that all feels like it's on track to us. We're -- we've been admittedly spending a lot of time on capital efficiency, and we talk 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 to you more about those improvements.

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Operator [15]

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Your next question will come from Doug Leggate of Bank of America.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [16]

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Guys, I wonder if I could circle back to Israel for a second. And as you pointed out, there's 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 as to how quickly you could see that capacity utilized with no material incremental capital? And I've got a follow-up, please.

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Brent J. Smolik, Noble Energy, Inc. - President & COO [17]

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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, the facility and wells will be capable of about 1.2 Bcf a day, and we can ramp that up over that first 2- to 3-year period depending on market with no additional capital. So it's kind of inclining base production from 800 million to 1.2 billion.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [18]

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And then I think, Doug, what you're alluding to, then beyond filling up the first phase of Leviathan, 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, 400 million a day increments and then you're looking at each well can deliver 300 million a day. So the real piece will be how it evolves from where you're going to flow the gas to on your phases beyond Phase 1.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [19]

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The -- I guess what was behind my question was, I seem to recall you had pre-built a couple hundred million dollars of expansion capacity in your Leviathan budget, plus you've got a 600 million a day platform producing 1/10 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, it will come. I'm wondering if having all that capacity available and more reliable operations, if you like, if there's a latent customer base that is going to allow you to ramp quicker. That's kind of really what I was trying to get at.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [20]

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Yes. And that'll 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 and 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 it -- quickly it ramped up through demand once it came online, and I think that's a good precursor, if you will, for how we could see '20 and '21 playing out. 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 their preplanning 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, it's 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.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [21]

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We think it's almost the entire value of your company right now, where your share price is trading. But anyway, 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 oil prices did come under pressure, given all the macro stuff going on, what is the sustaining capital when Leviathan is online to hold your exit rate this year flat? I don't know if you've got something like that at hand, but some kind of ballpark would be helpful.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [22]

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Yes. I think when we talked about it last year, we kind of -- or earlier this year, we laid out a maintenance capital. If you go back to that one slide where we laid out the maintenance capital and then we had 2 tranches above that. And that was in probably...

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [23]

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[1-6,] right?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [24]

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Yes. [1-5, 1-6] type range. I think the nice part of what Brent and his team's 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 it's -- I don't see it being higher than that.

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Operator [25]

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The next question will come from Scott Hanold of RBC.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - Analyst [26]

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

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [27]

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Well, the focus in 2020, 2021 will be delivering that free cash flow. So the spending will fall out of that. But all of this work that the team's been doing and all of 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?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [28]

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Yes. 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.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - Analyst [29]

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Okay. Great. And then as 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 is 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 something that could actually be another incremental saving for the Delaware wells?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [30]

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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 and EURs in the DJ, then it'd be something that'll be transportable elsewhere.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - Analyst [31]

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

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Brent J. Smolik, Noble Energy, Inc. - President & COO [32]

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Yes. Even late this year, we might try to put some in the ground, but think of it as longer term in the Delaware. And then 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 have 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 pumping down plugs faster, we're getting -- we're changing chemistries 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.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - Analyst [33]

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

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Brent J. Smolik, Noble Energy, Inc. - President & COO [34]

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

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Operator [35]

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

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [36]

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

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Brent J. Smolik, Noble Energy, Inc. - President & COO [37]

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Yes. 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 DC Plant 11, and that'll happen we think, in the next week, it'll start to ramp back up again. And so the gas is going to debottleneck itself. I think by the third and fourth quarter, we'll see enough NGL capacity where the constraints in the basin will get relieved. I think that'll clear itself up in the near term, and we've factored that into our updated guidance.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [38]

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

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [39]

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Okay. Perfect. And then for my follow-up. On the new proposed Colorado AQCC emissions rules, I know you guys stayed 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?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [40]

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Yes. No 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 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.

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Brent J. Smolik, Noble Energy, Inc. - President & COO [41]

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And on the emissions side, I mean, we already enjoy low emissions 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. And we've -- we're looking at designs that both reduce emissions further and reduce costs, which is the best of both worlds.

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Operator [42]

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

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration & Production Research Analyst [43]

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Solid work this quarter. I was just curious on the -- some near-term stuff, on the July volumes you posted for the U.S. onshore are already tracking pretty darn close to the full 3Q U.S. onshore guide. How should we think about the rest of the quarter from an activity standpoint? Is there some sort of lull in August that we should expect or backloading in the quarter? Or have you really just derisked the third quarter already pretty substantially with the July result?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [44]

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Yes. That's -- it's a little unusual for us to give you an estimate 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 meaningful impact on the third quarter growth, and we're seeing it. It's showing up. And 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'll 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'll grow significantly from second to third and then decline significantly from third to fourth. The other parts of the business, DJ and Delaware, we'll see the step up to third quarter and then a little bit of growth into Q4.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration & Production Research Analyst [45]

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Okay. Makes sense. And then I was just curious on the kind of bigger picture on the 2019 capital program, taking down the CapEx, obviously, a positive. You had 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 you in a position where you're kind of continuing to put on more wells than originally planned? Would you do -- would you bias towards 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?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [46]

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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 our completion activity in TILs and 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'll 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 year as we idle equipment that we had already -- we'd 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 the pad, disrupt any of our supply chain, stop when we don't have facilities full right in the immediate area. There's 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 as how we slow it down.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration & Production Research Analyst [47]

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Great. That makes a lot of sense. And then in that glide path, it seems to kind of suggest the 2020 rate on U.S. onshore capital spend is probably hitting lower relative to prior expectations. Is that a fair comment? And does that bias free cash flow higher in terms of relative to prior expectations on 2020?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [48]

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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 positive to free cash flow.

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Operator [49]

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

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [50]

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Congratulations firstly on Leviathan's process, it's been a long haul. And my question is related to East Med. And I think at one point, you guys talked about a 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 do you need and how would you finance it?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [51]

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Well, I can 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 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, but how we'd look at it. And as far as timing of how that would play out, Keith, any thoughts?

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John Keith Elliott, Noble Energy, Inc. - SVP of Offshore [52]

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

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [53]

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

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [54]

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If I may have a follow-up? Does it sound like -- does this vendor actually -- is it going to be a leasing? Or do you have to -- how much money do you think you need to put in? Then lastly, any action in Cyprus?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [55]

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Yes. I think I'd go back to my original comment. The only way we would do it 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 firming anything up there, but that would be the gist of it.

Cyprus, those discussions are ongoing, there's been a lot of progress towards 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.

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Operator [56]

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Our next question will come from David Deckelbaum of Cowen.

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David Adam Deckelbaum, Cowen and Company, LLC, Research Division - Senior Analyst [57]

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I just -- when you guys lowered your capital budget for the year, the $100 million delta, I guess, is that entirely coming out of U.S. onshore, I guess, because I know other people have asked around Eastern Med spending. But relative to the $550 million to $600 million budget that you laid out, you're trending a bit below that at this point. What kind of visibility do you have for the rest of the year, in terms of the Leviathan budget, particularly, as U.S. onshore comes down for the rest of the year?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [58]

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Yes. I think you should think of it right now as primarily U.S. 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've derisked 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 are optimistic that there'll be some room, but think primarily of it as the U.S. onshore realized savings that we have dialed in.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [59]

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Probably a better line of sight to how the final Leviathan capital will turn out as we get the platform set and we get through the third quarter and then we'll be able to get more expectation around that. But to Brent's point, it's been a well-managed, well-run project, and I'm extremely pleased with where we are.

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David Adam Deckelbaum, Cowen and Company, LLC, Research Division - Senior Analyst [60]

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Appreciate that. Could you just add 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 do you sort of have a loose budget in mind for exploratory endeavors next year?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [61]

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Yes. 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 1 well probably the second half of the year most likely. We've -- us and a partner is working with the government or finalizing the targets, it's pretty much set. Again, it'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 Pg, or chance of finding hydrocarbons. But our team's really focused on a liquid oil play potential there. And so it'll be exciting to get drilled and tested in the second half of next year.

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Operator [62]

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

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Charles Arthur Meade, Johnson Rice & Company, L.L.C., Research Division - Analyst [63]

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Dave, 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 comments in your prepared remarks about the 2020 CapEx outlook. And I'm not trying to pin you guys down on anything, but I more want to get a sense of what are some of the big pieces that are in play? And I think the one biggest piece looking at '20 over '19 would be Eastern Med CapEx. And you guys guided to $550 million to $600 million this year, and it's not going to go to 0, but there's going to be a big chunk that comes out there. What are the other pieces that we should be thinking about as we try to think about how '20 might look?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [64]

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Well, to your point, it's still early. We'll be pouring the budget later this year. And some of the things that we know about already, though, obviously, you've got Alen capital that will be higher next year obviously than this year. So that'd be the one increasing piece. There'll still be some capital, as you mentioned, in the Eastern Med and 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 pieces 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. 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.

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Charles Arthur Meade, Johnson Rice & Company, L.L.C., Research Division - Analyst [65]

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Got it. And then if I could ask a question about the Delaware Basin and less about what happened before but more kind of your -- the longer trajectory there. Where -- you guys have a graphic in your presentation, it 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 the kind of final decision on what well spacing is, at least in a $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?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [66]

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Charles, I think the high-level answer is yes. We've been pretty consistent in 3 wells in the Third Bone first section and 6 in the Wolfcamp A. So I think we're happy with the spacing. I think what you'll hear us spend 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've 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.

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Operator [67]

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Our next question will come from Jeanine Wai of Barclays.

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Jeanine Wai, Barclays Bank PLC, Research Division - Research Analyst [68]

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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 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 central gathering facility handle?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [69]

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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 3 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 -- or 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.

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Jeanine Wai, Barclays Bank PLC, Research Division - Research Analyst [70]

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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 noticed that the prior 2019 completions guidance implied only 8 in the DJ and 4 completions in the Delaware in the fourth quarter. But I think I heard you say in 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 a double-edge sword at this point, given the space, with activity and growth, with better-than-expected efficiencies. And we know that you had the commentary out there that in 2020, you kind of expect to have the same activity, that you laid out in the prior 2-year plan but potentially on lower CapEx. And just wanted to square your thoughts on how things are heading into 2020 given the overall focus on free cash flow and the inflection next year.

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Brent J. Smolik, Noble Energy, Inc. - President & COO [71]

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I mean there's a lot in there. I think the way to summarize it is 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 more in Delaware, but it's really not a big change. And then those efficiencies will be -- we think are the kind of the things that are sticky and so we'll carry them over into our activity for 2020.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [72]

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

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Operator [73]

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Our next question will come from Leo Mariani of KeyBanc.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [74]

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A 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 there, past the recent energy bill there? What have you guys seen on the ground there?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [75]

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It's probably too early to have really seen anything at that, I mean, they're still working through some of that rule-making. And I think, again, I'll go back to our big benefit, instead of having to go for one-off permits, we are getting a lot of them done at the same time [to be with] that original CDP or the one that's in the system now. So that will be a thing that will make us the most cost-efficient operator in the basin.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [76]

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

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Brent J. Smolik, Noble Energy, Inc. - President & COO [77]

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The only place I would point you -- this is Brent again. The only place I would 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.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [78]

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And I think to Brent's point, that highlights the work that's been done over the last year or 2 to provide multiple outlets and give us more flexibility in the basin and that's always the key.

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Operator [79]

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Your next question will come from Michael Scialla of Stifel, Nicolaus.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [80]

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I think this year's plan originally included $500 million to $1 billion of divestitures. Just want to see if you could talk about where that process stands?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [81]

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Yes. 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.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [82]

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Great. And Brent, you talked about it quite a bit in terms of the design changes you are making with the lower fluid and proppant and obviously, seen lower cost benefit there and early rate benefit. Just wondering if it is -- are you thinking in terms of it maybe as 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 frac?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [83]

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I think we have confidence that the returns will be higher, which is the 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 accelerated production offset any other loss in the EUR. So we're happy with the returns that we're seeing from it.

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Operator [84]

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Our next question will come from Gail Nicholson of Stephens.

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Gail Amanda Nicholson Dodds, Stephens Inc., Research Division - MD & Analyst [85]

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Brent, in one of the answers to a question, you talked about the importance going forward of kind of landing in the optimal landing zone in the Delaware. When you kind of look at the programs to date, what do you think the percent of current execution has been landed in the optimal zone? And kind of how much improvement do you think that you guys can achieve kind of over the next 18 months?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [86]

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I don't know how to answer the percentage of wells, but we have varied 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's various spaces that we're moving around in. And so part of what we are 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. It's all designed toward optimizing landing zones and completion designs. So it's all work under -- in progress. So I think that's a long way of saying there's additional room -- additional improvement to be had by narrowing down and locking in on landing zones.

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Gail Amanda Nicholson Dodds, Stephens Inc., Research Division - MD & Analyst [87]

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

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Brent J. Smolik, Noble Energy, Inc. - President & COO [88]

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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 were the same kinds of things we've been chasing out in both places.

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Operator [89]

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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.

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Brad Whitmarsh, Noble Energy, Inc. - VP of IR [90]

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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.

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Operator [91]

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The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.