Thanks, Brad, and good morning, everyone. Before commenting about the business, how we performed and how we are responding in the current environment, I'd like to extend well wishes to all of you who are joining us. I hope that you and your families are remaining healthy as our country and the whole world deal with the COVID-19 pandemic.

Over the past several weeks, the courage and professionalism of our frontline community workers has been extremely evident. This includes our health care workers, food supply providers, government agencies and other critical services. On behalf of everyone at Noble Energy, I extend a sincere thank you to those on the front lines for their tireless and sacrificial efforts.

I'd like to also extend my gratitude to the employees of Noble Energy, our customers and suppliers, partners and all for their extraordinary efforts to maintain safety and health. Our employee base has been working from home for nearly 8 weeks now, during one of the toughest industry environments we have ever faced. They've maintained a great focus on safety, efficiency and execution.

Our first quarter results highlight our team's extraordinary commitment and capability, as we delivered one of the best quarters of execution in Noble Energy's history. The whole organization did an exceptional job, building off last year's successes in terms of capital efficiency and cost improvement. Production was above plan, while capital expenditures, operating costs and G&A were all lower than expectation.

As you all know well, this is an extremely dynamic situation. The impacts from the COVID-19 pandemic and the resulting demand destruction has created the most unpredictable marketplace that I've experienced in my 40 years in this industry. We've seen supply response by OPEC+, and producers here in the U.S. are quickly rationing capital and adjusting production. However, the supply-demand imbalance is likely to remain in the near term. While we don't know the duration of this pandemic, or the ultimate slope of demand recovery, we will continue to be agile and respond appropriately.

Before handing over to Ken, I want to highlight the recent actions we have taken with a focus on optimizing our cash flow and liquidity while preserving inventory, setting us on a path for success coming through this environment and moving forward.

First, in response to the current commodity environment, we've lowered our 2020 capital plan by more than 50% versus original guidance, a decrease of $900 million. The majority of these reductions have come from our U.S. onshore business, where current commodity prices do not justify new near-term investment in shale in any basin. At Noble Energy, we will not invest capital at less than acceptable returns, and we will preserve our resource for a better future. While this will result in production declines in the second half of the year, we're focused on value, not volume. This is further highlighted by our election to voluntarily curtail production in May and June.

Offshore, we're moving forward the pipeline expansion work in Israel, and the Alen gas monetization project in Equatorial Guinea. Both projects are expected to generate good returns, enhancing our cash flows beginning later this year and establishing the pathway for long-term value uplift in those businesses.

In addition to announced capital savings, we've identified $225 million in cash reductions, mainly from operating costs and G&A initiatives. Total, the reductions that we have announced to date between capital cost and other initiatives, are saving approximately $1.3 billion as compared to our original 2020 plan. And we will continue to work to identify even more cost reduction opportunities as we move through the year.

Noble Energy is well positioned to manage through the current environment. Our strategy is right, with Leviathan online at the end of last year, our diversified portfolio stands out, with low cost of supply assets globally and a low annual production decline base. Our financial standing is strong, with high levels of liquidity and a reset cost structure as we move forward. Our execution capabilities are industry-leading, with best-in-class major project delivery and record U.S. onshore drilling and completion cycle times, providing a strong base of support when activity levels resume. I'm confident that we are well situated to come through this environment in a position of strength, ready to capitalize on opportunities and to rebuild shareholder value.

Let me now turn it over to Ken.

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Kenneth M. Fisher, Noble Energy, Inc. - Executive VP & CFO [4]

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Thanks, Dave. I also want to wish my best to all of you and your families during these challenging times. Throughout our history, maintaining strong financial liquidity and resilience has been a hallmark of Noble Energy. We have effectively navigated through volatile commodity cycles of the past, and today is no different. We have robust financial liquidity, ending at $4.4 billion in first quarter, and we have no near-term debt maturities. In fact, we have one of the longest dated maturity profiles in the E&P space at a very competitive average coupon.

As you know, we consolidate Noble Midstream Partners, NBLX, in our financials. NBLX is in solid financial condition, with ample liquidity and exceptional coverage. With the majority of their backbone infrastructure built and in place, and their JV pipeline investments nearly complete, they will move to organic cash flow positive position in the second quarter with a focus on reducing debt. One additional point, NBLX debt is non-recourse to Noble Energy.

As I mentioned, Noble Energy ended first quarter with $4.4 billion in financial liquidity, including $1.4 billion in cash and $3 billion of available borrowing capacity on our revolving credit facility. Our unsecured investment-grade revolver is one of the strongest in the energy space, backed by more than 25 banks. It contains only one financial covenant, a debt to capitalization ratio of less than 65%. On the covenant calculation, we ended first quarter at approximately 35% debt to capitalization.

Similar to commodity cycles of the past, we have protected our cash flows with our commodity hedging program. During the quarter, we took the opportunity to bring forward cash proceeds through monetization of certain crude oil hedges that had reached maximum value. This contributed to the total $208 million of net hedge proceeds in the first quarter.

Additionally, we added significant oil hedge coverage for the remainder of the year to protect cash flows. The majority of second quarter is locked in at fixed price swaps of nearly $36 per barrel WTI. Second half is also well protected with a combination of both fixed price swaps and three-way collars between $30 and $40 per barrel WTI. The value of our forward hedge position as of the end of the first quarter was approximately $235 million.

In summary, we are confident in our financial position, with robust liquidity, a well-managed maturity profile, solid hedge protection and the cash flow contribution of our long-term international gas assets.

Now let me hand it to Brent.

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

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Thanks, Ken. Good morning, everyone. I also want to express my gratitude to the Noble and Noble Midstream employees for their performance during the pandemic. Our office-based teams have kept the business running effectively, while working remotely since mid-March and our field-based team [field with] on-site teams have quickly adopted new health and wellness practices to safely execute our day-to-day operations and to successfully manage logistics and global chain -- supply chain disruptions.

As Dave mentioned, we built upon 2019's execution successes, and we delivered an exceptional first quarter. In the U.S. onshore, we drilled and completed our fastest wells to date, and average well costs in Q1 were down 10% to 15% versus budget. In 2019, our average well costs were $6.2 million and $8 million, respectively, for the DJ and the Delaware. And during the first quarter this year, we delivered them for $5.4 million and $6.8 million.

Production expenses have also improved with total U.S. onshore unit production cost more than $0.50 per BOE below plan. We exceeded expectations on sales volumes with strong base performance and new well productivity, and our operational efficiency gains resulted in higher TIL counts than expected with meaningfully lower capital.

The first quarter was a high point for U.S. onshore execution and although the onshore activity is not warranted in the current environment, these milestones are still important. When we choose to restart, we'll be building on a stronger operational foundation.

In the Eastern Med, we advanced the Leviathan commissioning process, delivered over 92% facility run time in the second quarter and satisfied all of our domestic and export gas sales contracts. I'm happy to report that the platform commissioning is nearly complete, reliability is high and we've delivered close to 100% run time over the last month.

Following a strong start to sales in January and February, the economic slowdown from COVID became visible in the Eastern Med region, which impacted power demand and natural gas consumption in March.

Turning to EG. Strong oil liftings in the quarter benefited from our Aseng 6P well and active production decline management at both the Alba fields and Alen fields.

Looking forward to the remainder of 2020, in the U.S. onshore, we've revised -- we have a revised capital plan of $575 million for the year, with over 55% of that spend in the first quarter. All completion activity has been suspended, and drilling activity has been reduced to 1 rig in the DJ Basin. The plan includes $75 million to $100 million for the option to complete DJ wells in the fourth quarter. We'll hold that capital decision until late this year based on a variety of factors, including the extent of oil price improvement. If we elect to carry the DUCs into next year, then the U.S. onshore capital will be under $500 million this year.

Due to low crude oil realized pricing, we've also voluntarily curtailed May net production by 5,000 to 10,000 barrels of oil per day. For June, we expect to curtail 30,000 to 40,000 barrels of oil per day. We made these decisions on shut-ins in 2 tranches. The first bucket is lower productivity wells, which are not covering variable operating costs. We're also deferring production from certain higher rate wells for better value in future higher price environments. The exact amount and the duration of these curtailments is uncertain and will depend on the recovery of oil prices and economics.

As Brad mentioned, although we've not provided specific production guidance, I'll provide you some directional trends for the remainder of the year. Absent the curtailments, we estimate that Q2 onshore production would have been roughly equivalent to Q1. Without any new TILs planned, base declines in the U.S. will be about 10% to 12% per quarter in the second half of the year.

When you consider our efficiency gains, our cost reduction improvements and DUC inventory, we estimate that U.S. onshore maintenance capital required to hold fourth quarter oil and BOEs flat for 2021 is now between $600 million and $700 million. The combination of lower onshore maintenance capital and our conventional international assets, which we expect to grow over the next few years, we believe that remains a competitive advantage for Noble.

In EG, the Alen project continues to make good progress, with start-up anticipated early next year. We finalized the marketing agreements for the Alen gas during the first quarter, with pricing indexed to European LNG. Considering the attractive liquification cost, the project is anticipated to pay out in approximately 2 years. We estimate a $230 million cash flow swing from 2020 to 2021, as spending is completed this year, and new cash flow begins early next year.

In the Eastern Med, the pace of the economic recovery makes it a little more difficult to forecast sales volumes. The good news here, though, is that Israel and Jordan appear to be several weeks ahead of the U.S. in terms of reopening their economies, which is encouraging for demand recovery this summer. We also anticipate a step-up in sales volumes in the second half of the year due to seasonal demand and increased quantities in the Egypt contract. We're currently preparing to install compression equipment to expand the EMG pipeline capacity for higher Egypt sales. With Leviathan fully installed, we now have a total of 2.3 Bcf of gross deliverability. That's a great opportunity for us over the next couple of years to grow production and cash flows as demand returns without incurring any additional capital. This is a one-of-a-kind asset base, with extremely low operating and development cost, no annual production decline and over 32 Tcf of gas to produce in the future from Leviathan and Tamar.

So I'll wrap up this morning where Dave started. We're making the right adjustments in the current macro environment, and we'll be a stronger, more efficient company as conditions improve.

I'll now open the call for questions. Operator?

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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 Brian Singer with Goldman Sachs.

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Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [2]

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I wanted to see if you guys could touch a little bit more on just the production trajectory, and I get -- we certainly get there's moving pieces here as it relates to the second quarter and maybe even the third quarter. But how you're thinking about, in the various basins, when you think about the capital budget that you're planning here for this year, what the implications are for exit rate production and natural decline rates.

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

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Yes, Brian. This is Brent. As I outlined in some of the prepared comments, the way we're thinking about it is that Q1 is in the bag. We've given some pretty clear direction, I think, on shut-ins as best we can guesstimate them for now, for May, June. If you back those out of Q1, then I think we would have otherwise been a bit about flat in Q2. And then our U.S. onshore overall declines about 10% to 12% a quarter. So I think that gives you a pretty good direction on how we think it's going to play out for the year.

With the capital, the way we've designed it, we're going to have that one rig running in the DJ for most of the second half of the year, if not all. If we do the completions that we've got in the $75 million to $100 million in the capital, that will be fourth quarter. So it will have a fairly small or no impact on exit volumes right at the end of the year, but it will be wells that could potentially come on in early Q1. So that's kind of generally how we're thinking about the U.S. onshore part of the business.

International is largely going to be wrapping up the 2 projects, the Alen project in EG and the compression projects pipeline work that we're doing in Egypt and Israel.

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Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [4]

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Great. And then my follow-up is a little bit more bigger picture. When you think about the various areas in which Noble is operating and the environment that we're in, how do you think about really 2 things: one, free cash flow and then how that would be returned to shareholders? At what point would you think about bringing the dividend back more meaningfully? And then also more on the consolidation front. Do you see Noble as a participant in that, either during the downcycle or when things normalize?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [5]

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Yes. Brian, this is Dave. I'll start on the first one. On the free cash flow, that's still our focus. We went into this year as -- that's being our focus to generate free cash flow, and it's still our focus. I think all the quick actions that you've seen us take have been in support and service of that direction there. I think as -- obviously, through this downturn, balance sheet is going to be a focus for us here. I think coming out of this downturn, it will still be a focus as we get support from commodity prices and get back into a higher cash flow picture. Dividend, we would expect to increase with cash flow over time. But dividend has been a key component of our structure. It's always been a key component of our belief in shareholder return, and so it will still play a key role going forward. But I think balance sheet is the focus right now on the downturn [in] liquidity.

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Operator [6]

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Our next question today will come from Scott Gouber (sic) [Gruber] of Citigroup.

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Scott Andrew Gruber, Citigroup Inc, Research Division - Director and Senior Analyst [7]

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Does the $600 million to $700 million of U.S. maintenance CapEx include a DUC draw? And how should we think about the cadence of [pulling those] greater than 100 DUCS that you could be exiting the year with?

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Kenneth M. Fisher, Noble Energy, Inc. - Executive VP & CFO [8]

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Yes. We would factor that in. We normally have a DUC inventory because of just a normal lag in the schedules, but we'll have a little bit bigger one. We'll probably add 4 or 5 DUCs a month is kind of how we look at it, with the rig that we have running now. So it's not a big difference. But those will support lower maintenance capital because that production will either start up very late this year or early next. So it makes next year's capital a little more efficient. Probably the bigger difference is the actual cost reductions we've taken out of the program over the last couple of years, and I gave some first quarter results just to help you see how much we've been able to reduce the per-well cost, so that meaningfully helps lower it and then, lastly, starting from a lower base exiting the year.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [9]

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Yes. I'd like just to add to that, when you think of the company picture overall for '21, we've got a couple of things that are really working in our advantage. One has been the cost reset that the teams jumped on very quickly this year, that will carry over and probably expand into next year. And then it's what we had mentioned earlier, with Alen coming on, you've got a big cash flow switch from spending some money this year to generating money next year. That's a big difference. And then with Leviathan in the Eastern Med, you've got capacity that will start to fill up at no additional capital. So there's a number of things, as we move into '21, that are really working in our favor, besides just the increased efficiency in the onshore, which has been significant.

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Scott Andrew Gruber, Citigroup Inc, Research Division - Director and Senior Analyst [10]

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Got it. And then can you just provide some additional color and outlook for Eastern Med volumes in 2Q in the second half of -- the second half largely coming in as expected per your previous guidance?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [11]

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We've always -- as you recall, we've always expected Q2 to be the lowest quarter for the year just because of normal lower seasonal demand. I think you have to layer on a little extra demand destruction because of the COVID virus, though. And so I think those are the 2 elements that we've factored into Q2. And it will still be -- we still anticipate it being lower. So Q1 you have, Q2 lower, and then we have the step-up in the second half, assuming recovery in regional demand and the step-up in the Egypt contract.

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Scott Andrew Gruber, Citigroup Inc, Research Division - Director and Senior Analyst [12]

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Got you. But no lingering COVID into 3Q expected at this point.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [13]

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Well, I think that's the uncertainty when you think about it around the world. The encouraging part is we're starting to see Israel return to work. You're starting to see Jordan [start] to have signs of returning to work. The unknowns are just how quickly will things continue to return to work and how will we not have any relapse, if you will, over the rest of the year. So that's part of the uncertainty. But I think as Brent mentioned, the impact that we've seen, even kind of, if you will, in the trough of the COVID impact here over last month or 2 has been maybe 10% to 15%, at most. So I think that bodes well as we see these countries return to work for the second half of the year. And you're still going to see seasonal demands. Third quarter is going to be the high quarter for the year. Fourth quarter will have a seasonal piece that will come down a little bit. So if you go back and look how Tamar started up when you had additional capacity, that's the same type shape, kind of with first and third quarter being the highest and second and fourth quarter being the lowest.

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Operator [14]

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Our next 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 [15]

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I had a couple of questions for you this morning. One is I wanted to ask you a little bit about mechanically or how gas is marketing in Israel between the Tamar and Leviathan consortium. And just overall, how do you manage that process and the conflicts just inherent in those structures?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [16]

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Yes, Arun. This is Brent. A lot of what we have in place is already contracted, 10- to 15-year long-term contracts. And so that's already managed, if you will. And then what we have to contend with over the future is then how do we think about incremental gas. And so you may have seen some of that in the public commentary. It's talking about incremental contracts for future gas as we -- as you think about, as we penetrate into the coal-fired power and as we get GDP demand growth, and those kind of things. So I just want to make it clear for everybody that, that's -- most of it is already contracted long-term. And then to be able to manage it, we've got good working relationships with all partners. And so it's just an ongoing dialogue.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [17]

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Yes. Not to forget also, Arun. Another key part of Leviathan's part is the focus on the export portion also.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [18]

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Yes, that's a good point. That's a good point. Question for you, Ken, is just going through the commentary on NBLX was super helpful. I know the debt is nonrecourse to Noble, but one of the recurring questions we get from the buy side is what would happen in a more draconian scenario where access to capital is more difficult? And how would you consider thinking about using Noble's balance sheet to assist NBLX in again, a draconian scenario?

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Kenneth M. Fisher, Noble Energy, Inc. - Executive VP & CFO [19]

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Yes. I mean Noble X is a very strongly positioned business. As I said, the infrastructure is built out, and the JVs are pretty much complete. So their need for future capital is pretty low, so they'll move into a cash-generating position. I would expect them to be paying down debt. That's clearly their focus. And so I don't see any issue where Noble would have to step in. I think they're well able to fund themselves.

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Operator [20]

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Our next question today 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 [21]

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Dave, or maybe it's for Ken or Brent, actually, but the operating cost reductions that you guys have delivered are, obviously, pretty meaningful. How sustainable do you think those are, both for 2020 and coming out the other side of this?

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Kenneth M. Fisher, Noble Energy, Inc. - Executive VP & CFO [22]

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Yes. If you're actually talking about the OpEx or the expense side, we think some of them are very sustainable because they're fundamentally changing how we're staffing and managing the assets. So we think they're sticky. If you notice -- if you go back to the trends that we had for both OpEx and CapEx from all of last year, they trended down through '19. If you look at Q1 results, they trended down again. That gives me some hope that -- or belief that there's -- they're bigger structural changes we're making. They're not transient.

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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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Okay. I appreciate that.

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

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And add to that, I think on thing on the G&A part of that, because you asked on OpEx, but on the G&A part of that, I think there are some things that are going to be very sticky as we move into next year that we saw maybe half or less than half of the benefit this year that will...

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [25]

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Okay. I appreciate that. We -- I don't think all of us are assuming much of this is sustainable. That's why I asked the question. But my follow-up question, if I may, is you guys are obviously, differentiated with growth opportunities outside of the U.S. I just wonder that given the Alen start-up next year, is there any color you can give us on how you see the trajectory after you get the initial backfill to the Bioko plant? And in light of that and Leviathan, what is the right growth rate for the U.S. coming out the other side of this? And I'll leave it there.

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Brent J. Smolik, Noble Energy, Inc. - President & COO [26]

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Yes. So Doug, we've talked a few times about the -- that we'll just be basically backfilling -- as the Alba gas declines, we'll be backfilling that decline kind of molecule for molecule. Over the next 2 to 3 years we'll see growth from the Alen project. And what we said, even way before the virus early last year, is that we think that the model is a lower growth rate model. And we had already started moving there for the U.S. onshore part of our business. So I think we'll stay in that mindset. Because we're advantaged on growing Israel volumes and growing EG volumes, it's less pressure on us to have to grow U.S.

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Operator [27]

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Our next question today will come from Charles Meade of Johnson Rice.

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Charles Arthur Meade, Johnson Rice & Company, L.L.C., Research Division - Analyst [28]

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I wondered if you could -- again, going back to -- you said something in your prepared comments that struck me. You said that you don't have acceptable returns in any basin in the U.S. onshore now. But could you give us an indication -- I guess, this kind of gets back to not just the shut-in question, but also Brent's comments about, perhaps, going back to work on the completion side in 4Q. What is the WTI level we should be thinking about for where those returns would become acceptable?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [29]

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Yes. This is Brent, again. Yes. I think Dave's comment was at the current kind of low commodity price, there's no basin in the U.S. that's economic. But if you look at our stack, the DJ is the highest returns we have in the U.S. onshore, and it will be the first to come back in to being acceptable rate of return. And that's why we have the rig running there, and we're -- and we've created the option to spend the completion dollars. Again, we'll hold that option until late in the year and then decide if we're going to spend them or we'll roll the DUCs into 2021 for those. But that program is pretty good economics around $40 flat, the way we look at it today. So that's why we're taking the actions we're taking.

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Charles Arthur Meade, Johnson Rice & Company, L.L.C., Research Division - Analyst [30]

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Got it. That's helpful, Brent. And then as a follow-up, any color you care to offer on where geographically the shut-ins that you're seeing for May and June are coming from?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [31]

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Yes. The bulk are going to come from DJ and Delaware, obviously. And we started in that first tranche of the lower rate wells and the older wells. And so that naturally moves some of that more to DJ because we've got the older vertical wells in the program. Delaware is newer for us, so it has less of those low rate, late life, higher cost, lower margin kinds of wells in the portfolio. So probably something like 2/3, 1/3, DJ, Delaware.

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Operator [32]

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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 [33]

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You guys have talked a lot about the demand impacts in the Eastern Med. Just from a modeling perspective, should we expect those to materialize via volume or via price? And you talked about the March impact, was April flattish, maybe a little bit worse as would be the trend on, say, oil demand in general, or more stable?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [34]

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Yes. What was the second question?

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [35]

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Oil demand in Eastern Med.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [36]

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I think that's the first question.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [37]

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Is the impact of the demand destruction in Levar and Tamiathen (sic) [Tamar and Leviathan], is that going to flow through to you all via lower volumes or via a lower price? And you talked to it being -- impacting March. How did April look if you can give a guess?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [38]

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Yes, for demand. Yes. So just again, a reminder that our prices are set by contract or by floors in the contracts, and so those are long-term, 10- to 15-year agreements that we have in place. Everybody is performing on those agreements. And so really, we think of the uncertainty more as the volume uncertainty in the near term because of the impacts on demand in the near term. So that's the way we're tending to manage through it. We started the year really high. January and February, we hit days that were 1.6 to 1.8 Bcf a day gross between Tamar and Leviathan, so that tells you what sort of -- when the market is full on, cold days, high demand, we were able to deliver those kinds of numbers. We saw the impacts show up in March, so March was lower. That goes into the average for the quarter, and we're seeing about the same levels in April as March. So what I hope, what we hope is the government has announced that they want to open up fairly aggressively. A lot of the offices are now up to 50% staffed. Schools are opening. Summer is coming on. So as it trends back to sort of normalcy, we hope to get back on normal trends this summer.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [39]

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But again, as Brent highlighted earlier, second quarter was always going to be the lowest quarter just from a seasonal standpoint. So that's been what's kind of encouraging is, even with all the COVID piece, it's not that big of a change. Like I said, maybe 10% to 15% we've seen in April, and that should get better as we go through the year.

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Brent J. Smolik, Noble Energy, Inc. - President & COO [40]

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And again, just to remind everybody that this is almost pure natural gas. It almost all goes for power demand. So we don't have the same challenges when you're making motor fuels. This is electric demand in the grid for both the Israel and the region, Jordan and Egypt.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [41]

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Okay. Perfect. And like you guys said in the prepared remarks, you guys have one of the best bank lines in the industry, really, really covenant-light, et cetera. Why pull down on it at all given the kind of strength of your position there?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [42]

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Well, we were concerned of the -- what would happen in the banking system around the world so -- was the abundance of caution, no concern about the availability of the facility. There's no redetermination or anything like that. So as everything returns to normal, we'll probably repay some of that cash.

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Operator [43]

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Our next question today will come from Scott Hanoid (sic) [Hanold] of RBC Capital Markets.

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Scott Michael Hanold, RBC Capital Markets, Research Division - MD of Energy Research & Analyst [44]

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Could you talk a little more on the volumes that you're curtailing and deferring? And just give a sense of -- are they true shut-ins? Or are you choking the wells? And obviously, the decision to bring those wells back is different than the conversation that you had a couple of questions ago on when it takes to drill a new well. Can you talk about when those wells you think are going to start look more economic?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [45]

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Yes. I would characterize ours as primarily shut-ins, especially the lower-rate older wells, because part of what you're trying to do there is take out all the variable costs, and if you can, variabilize some of the fixed cost and take that out as well. So you don't want to just crack or pinch those wells back. The other -- the second tranche is the higher deliverability, higher-rate wells, primarily this year, maybe late last year wells. And those will be probably full shut-ins as well for geographies within the field, parts of the field, so we can idle all of the infrastructure to go along with it. Those are obviously the easiest to come back on, Scott, and it wouldn't be much above where we are today, price-wise, for those to be well above their variable cost. It's really a question [of looking at] longer-term PV, value creation of delayed -- deferring that production.

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Scott Michael Hanold, RBC Capital Markets, Research Division - MD of Energy Research & Analyst [46]

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Yes. On the vertical wells, is there a chance that those may not come online for quite some time, considering they probably have the highest fixed costs?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [47]

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Yes. The -- we should be able to restart them. There's always going to be some probably that are difficult, that are hard to get them kick back off again. But we should be able to restart most of the wells over time. The higher rate productive wells, we've got good experience with, either because we're fracking and we're offsetting and shutting in wells or because if we have upsets or plant -- anything that we -- cause them to shut in. And we know those come back pretty well. The highest rate -- highest deliverability wells, you can almost think of them as storage where we're just storing it in the ground, and then they'll respond pretty quickly when we turn them back on.

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Scott Michael Hanold, RBC Capital Markets, Research Division - MD of Energy Research & Analyst [48]

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Okay. That's great. And then I'm curious about the decision to defer Colombia activity. And maybe I was mistaken, but I thought the capital outlay for this year was fairly small for that. And obviously, the opportunity could be somewhat impactful over time.

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Kenneth M. Fisher, Noble Energy, Inc. - Executive VP & CFO [49]

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Yes. I think the capital was around $50 million this year, and both from the standpoint of preserving that opportunity for next year or beyond, but also just all the uncertainty that was tied in with when are countries going to be able to resume, companies, activity and so forth. It just didn't make sense to push that this year, but put it back in a more stable environment.

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Brent J. Smolik, Noble Energy, Inc. - President & COO [50]

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Yes. The only thing I may layer on top of that is there was a bit of a COVID overlay of that, because being able to go in and start up a new operation in country and be certain that we could supply the rig and -- with equipment and everything, it just -- I think it makes -- it's just more prudent to defer this until we get some better certainty in the world.

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Operator [51]

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Our next question 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 [52]

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I was wondering if we could -- on the maintenance capital figure that you put out there, maybe talk a little bit more about kind of what underlies the assumptions within that as it relates to maybe rig count or which regions you'd be active in and any further cost reductions that are embedded within that. Or is that kind of running with the latest costs? Or what are you thinking on well costs within those -- within that number?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [53]

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We didn't assume any new lower cost savings. We anchored it in what we -- current cost in Q1 actuals that we delivered. And I think that the only thing that makes it a little unique, like I said earlier, was that we do have -- we will have a few more DUCs that we'll either complete late this year or early next, and that would appear as higher efficiency -- better efficiency in the 2021 program. And then we are anchoring it, just to be clear, on the fourth quarter average volumes. And so it's a lower volume number than we would have had in a full year number previously year-over-year.

I think as far as how we would distribute it between the programs, you could assume a lot like what we had planned on this year. I mean that really hasn't changed, the economics between the Permian and DJ or the rank order is still about the same. So I think about the same kind of activity levels as this year's plan.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration & Production Research Analyst [54]

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Like the original plan this year, Brent, or the current?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [55]

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Yes. We had more -- we had about twice as many wells in DJ as we did in Permian, so about 100 and about 50 round numbers. So that kind of ratio is fine to assume for '21. The other thing that's maybe more important than all this, though, it 's -- remember, international, we've got some capital included in there, but there's very little true maintenance capital to maintain production or cash flow required at all. We've included some in that range, but we could potentially see significant growth in both EG because of the Alen project coming on next year, with all the spend this year, with no additional capital next year. And then because we've got so much excess capacity already built that could be readily turned into the market as [with] demand grows with no additional capital in Israel, that's -- you've got to put both of those 2 together to fully understand the advantage that it creates for us.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration & Production Research Analyst [56]

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Yes, you just pre-answered, I guess, what my follow-up was going to be, which was how to think about kind of capital requirements on the international business in '21, and if the thought process is basically keep U.S. at maintenance given the current strip, keep U.S. at maintenance and let those potential growth wedges come forward. I mean, is that capital requirement in the $50 million to $75 million level? Is that -- am I thinking about that right for '21 for the international?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [57]

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It's a reasonable assumption if you average it over the next 2 or 3 years for international maintenance.

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [58]

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But think about it this way. If you look at -- I mean, the Eastern Med is truly a unique asset. I'm so thankful we got the Leviathan project behind us last year. It came on beginning of this year, actually, last day of last year, because think about what that sets up for you. You've got capacity to grow into the 2.3 Bcf a day that's established right now, and that's what creates the unique asset. You can grow into that with essentially no capital over the next couple of years. And then you combine that with Alen, that will be on by early next year, and as Brent mentioned, will continue to grow as its capacity increases from the need for additional gas in the onshore LNG facility. Those are 2 unique positions to have as you go into next year.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration & Production Research Analyst [59]

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And if I could, just tag one more on in the context of EG. How much incremental gas comes from the LNG plant, net to you guys in '21? I just want to make sure I'm thinking about that right.

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Brad Whitmarsh, Noble Energy, Inc. - VP of IR [60]

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It's about -- Mike, this is Brad. We expect the start-up 95 million, 100 million equivalent a day. That includes a couple of thousand, I think, barrels of condensates. And so we expect to start up, net to us, 100-ish million, 300-ish million on a gross basis. And as the guys said earlier, that should be able to grow for a couple of years from there.

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Operator [61]

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Our next question will come from Devin McDermott of Morgan Stanley.

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Devin J. McDermott, Morgan Stanley, Research Division - VP, Commodity Strategist for Power Markets, and Equity Analyst of Power and Utilities Research Team [62]

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So I wanted to just build on some of what's already come up, but really the free cash flow potential of the business. And if we think about some of the moving pieces going into 2021, you have the step-up in Eastern Mediterranean volumes, the Egypt contract you mentioned, you have the step-up in EG and also the step-down in CapEx there. And you also have some of the ongoing efficiencies and cost savings that you've talked about that will flow through on a long-term basis. So what I wanted to ask is, with the onshore maintenance CapEx you disclosed, the $600 million to $700 million, what's kind of the breakeven oil price you need to be free cash flow neutral, and similarly, the point at which you inflect to be free cash flow positive, and how that's trending over time?

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Kenneth M. Fisher, Noble Energy, Inc. - Executive VP & CFO [63]

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Well, I think the trend over time has been very positive. When you just think about all the things you described, it's probably $5 to $10 lower than maybe what it would have been previously. So you're looking on just a specific free cash flow number, you're probably in the 40 or less potential type range. Again, you're still going to make your capital decisions based on the rate returns for those projects, and Brent talked about that. What you're looking for on a program in the U.S. is a program that -- what the outlook of prices that support generating at least 30% type return at the wellhead to cover the cost. So all things trending in the right direction with the reset of costs, both on the capital efficiency side and the underlying daily run rate of costs that we're seeing being reset here.

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Devin J. McDermott, Morgan Stanley, Research Division - VP, Commodity Strategist for Power Markets, and Equity Analyst of Power and Utilities Research Team [64]

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Makes a lot of sense. And my follow-up question is just a bit more detail on the Alen offtake contracts. I think it mentions in the slide that's linked to global benchmarks but is that oil [only] pricing, gas benchmarks? How should we think about what's baked into the cash flow uplift you disclosed and what kind of are the sensitivities could be over time to that?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [65]

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Yes. Those contracts aren't public, but what we've been signaling is that they're gas indexed to European gas prices. So if you start there, back out transport, really competitive liquefaction, you still get to good netbacks in the field that pays out in a couple of years -- pays out the project in a couple of years. So hopefully that's enough clarity to kind of give you a sense of how strong the project is.

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Devin J. McDermott, Morgan Stanley, Research Division - VP, Commodity Strategist for Power Markets, and Equity Analyst of Power and Utilities Research Team [66]

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And does the cash flow uplift bake in something close to the strip for European gas prices for 2021?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [67]

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Yes. I mean, you pick your price, but that's how we'd think about it, is start with European [, land at] LNG.

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Operator [68]

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Our next question today will come from Jeanine Wai of Barclays.

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Jeanine Wai, Barclays Bank PLC, Research Division - Research Analyst [69]

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My first question, I'm just going to be following up on a few of the other questions on -- regarding Michael and Devin's questions about maintenance CapEx. We've been pretty impressed by industry commentary on how much base declines are expected to improve in '21 given the big CapEx cuts this year. So do you have an estimate of how much improvement your base decline in the U.S. would have year-over-year? And what's embedded into your updated $650 million maintenance number? And I know you mentioned this 10% to 12% decline per quarter in 2Q -- or in the second half of the year, but just wondering what that might improve to next year.

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Brent J. Smolik, Noble Energy, Inc. - President & COO [70]

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Yes. I think the thing you can look back is how prior years, as we layer in a new year's worth of capital and uplift on top of the existing base. We don't change the base that fast, right? So it's going to be a few percentage better as we go from '19 -- or '20 to '21 if we have less new wells coming on this year than we otherwise would have had.

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Jeanine Wai, Barclays Bank PLC, Research Division - Research Analyst [71]

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Okay. Great. That's helpful. And then maybe following up on Welles's question on the Eastern Med. And I'm not sure how much detail you can discuss, but can you maybe talk a little bit more about the contract volumes and how those fluctuate with oil prices? I guess, in particular, we're wondering if you can provide some color on the Dolphinus contract that if we understand Delek's comments correctly, and we might not, I think that contract allows the buyer to reduce volumes when Brent falls below $50 average for a single year, but I know there's a lot of moving pieces in that.

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Brent J. Smolik, Noble Energy, Inc. - President & COO [72]

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Yes. Let me start that and then maybe hand it to Keith. So just a reminder that, that's the project that we're installing the compression on now. So we're on the ground working collaboratively to be able to get that compression up because that's what allows us to step up the contract volumes from 250 million to 450 million at midyear. And so we're working with the buyers on the other side on -- with Dolphinus, so they're asking us to be ready to deliver that gas in the contract. So the actions on the ground are that we're still moving forward with the step-up in the second half of the year.

So I don't know, Keith, any other color on this conversation but...

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John Keith Elliott, Noble Energy, Inc. - SVP of Offshore [73]

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Yes. I mean, Jeanine, to your question, there's certainly -- there are clauses in that contract that, at a sustained Brent price below $50, they have some rights to temporarily reduce the take-or-pay. But I think the key point is what Brent is describing is, we're engaged with the customers down in Egypt. They're asking us for assurances that the compression is going to be online on July 1. They're not asking us about reduction in takes.

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Operator [74]

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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 [75]

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Just wanted to follow up a little bit there on Israel. I certainly appreciate the color you guys have given. I guess there's been some various agencies out there in the press that have kind of been reporting on issues that you might be having there with the Israeli Competition Authority, I guess, with some of your minority partners there in Tamar. What can you sort of tell us about that? Do you see this as a major issue that could kind of impact volumes or price for Noble in Israel going forward?

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David L. Stover, Noble Energy, Inc. - Chairman & CEO [76]

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No. I think that the good piece there, Leo, that you're talking about is what's been under discussion is incremental volumes, new volume portion, And what the authority has said is for the partners to work it out, and sent it back to the partners to work out any differences. And I think that's what's ongoing right now. So I find that all encouraging for process forward. And -- so I don't see it having an impact this year. So I think it's just part of the process of new production coming online and a growing market, too, over time.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [77]

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Okay. That's helpful for sure. And just wanted to follow up on one of you-all's earlier comments. I just wanted to make sure I sort of heard this right. I think you guys talked about sort of a $40 WTI price given you -- a really nice rate of return in the DJ. So just wanted to kind of get a sense of the $75 million to $100 million of potential extra capital in the fourth quarter from fracking those DJ wells. Do you need to see $40? Or is it below that, just given that you've already spent the drilling capital on those wells?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [78]

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No, I think we need to look at it full cycle for the well and we need to have our belief that we're going to be in a forward world that's in the $40 range. So I think that's the way you need to think about it, is we don't necessarily have to have it in the strip and be able to hedge it, but we've got to have a belief that we're coming out of the recovery here. That's the way I would think about it.

And I think since you've asked, Leo, I think it's important just to remind everybody that, that option will exist up until the beginning of the fourth quarter if we spend that capital or not. So I think it's -- we wanted to point it out to you because that's how we're thinking about the business and create that. But if we don't spend it, the U.S. onshore will be sub $500 million this year.

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Operator [79]

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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 [80]

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You guys have achieved really great efficiencies over the last several quarters in the U.S. With the deceleration of activity, what steps are you or can you take to make sure you preserve those efficiencies on a go-forward basis when activity resumes?

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Brent J. Smolik, Noble Energy, Inc. - President & COO [81]

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That's a great question, Gail. Thank you. So part of what we've done as we've slowed the activity down, the teams that are working on that are doing everything we can to archive all of the best practices and processes that we've improved over the last 2 years or so to make sure that we've got every step of every part of the operation clearly documented on how we've been able to deliver it, from -- and that includes all the relationships with our service providers, and means everything we do internally and how we plan and execute. So we've done it before. If you remember, we had a little slowdown in the fourth quarter at the end of '19, and we ramped that activity back up in the first quarter this year. And look at the results of the first quarter this year, how good they are. So we've got a restart plan that we're working on right now.

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Gail Amanda Nicholson Dodds, Stephens Inc., Research Division - MD & Analyst [82]

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Great. And then a part of the $225 million of savings you guys have talked about this year is asset retirement savings. Can you just talk -- has that been completely removed from the system? Or have you just pushed those AROs to the right?

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

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No, we've had efficiency gains in those, just like we have in other parts of our operations. So we're able to -- it's primarily up in the DJ, but we're able to abandon the wells at a lower cost per well. But we're also doing less of them this year because we've reduced the drilling activity. So we have less plugging in and around the drilling program that we do in advance of drilling them. So it's a combination.

Allison?

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Operator [84]

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Ladies and gentlemen, this will conclude the question-and-answer session. And I'll now turn back to Brad Whitmarsh for closing remarks.

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Brad Whitmarsh, Noble Energy, Inc. - VP of IR [85]

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Sure. Thanks again, everybody, for joining us. Ken and I are available to connect for any follow-ups. Don't hesitate to reach out. We look forward to talking with many of our shareholders and analysts virtually in the upcoming weeks. And I want to wish all the mothers out there a Happy Mother's Day. So I hope everyone has a nice weekend.

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Operator [86]

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The conference has now concluded, and we thank you for attending today's presentation. You may now disconnect.