Noble Energy, Inc. (NASDAQ:NBL) Q4 2019 Results Earnings Conference Call February 12, 2020 9:00 AM ET
Brad Whitmarsh – Investor Relations
Dave Stover – Chairman and CEO
Brent Smolik – President and COO
Ken Fisher – Executive Vice President and CFO
Hodge Walker – Senior Vice President, Onshore
Keith Elliott – Senior Vice President, Offshore
Robin Fielder – Senior Vice President, Midstream
Conference Call Participants
Arun Jayaram – JPMorgan
Brian Singer – Goldman Sachs
Charles Meade – Johnson Rice
Doug Leggate – Bank of America Merrill Lynch
Michael Hall – Heikkinen Energy Advisors
Scott Gruber – Citi
David Deckelbaum – Cowen
Scott Hanold – RBC Capital Markets
Paul Cheng – Scotiabank
Leo Mariani – KeyBanc
Irene Haas – Imperial Capital
Gail Nicholson – Stephens
Nitin Kumar – Wells Fargo
Jeoffrey Lambujon – Tudor, Pickering & Holt
Good morning. And welcome to Noble Energy’s Fourth Quarter 2019 Earnings Results Webcast and Conference Call. Following today’s presentation, there will be an opportunity to ask questions. [Operator Instructions]
Please note this event is being recorded. I would now like to turn the conference over to Brad Whitmarsh. Please go ahead.
Thank you, Chad, and thanks to all of you for joining today’s conference call. I hope you have had a chance to review the news releases and presentation deck that we published this morning. These materials are available on the Investors page of our website and they highlight our strong 2019 and an updated capital allocation framework with specifics on our 2020 plans. Later today we will file our 10-K 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 will hold a question-and-answer session. I would ask that analysts limit themselves to one primary and one follow-up. Our planned comments this morning will come from Dave Stover, Chairman and CEO; as well as Brent Smolik, President and COO. Also joining us for Q&A is Ken Fisher, EVP and CFO; Hodge Walker, SVP of Onshore; and Keith Elliott, our SVP of Offshore. I also want to extend a welcome to Robin Fielder, SVP of Midstream who is joining us for her first call as well. Our planned comments will go about 25 minutes and we will wrap up today’s call in an hour.
With that, I will turn the call to Dave.
Thanks, Brad, and good morning, everyone, and thanks for joining our call. At this time last year, I started my comments by saying we were on the cusp of something very unique and very special. Today, I am excited to highlight how we have now delivered and poured the foundation for Noble Energy to provide a differential future for investors.
I want to start this morning by taking a proud look back at 2019, which was a remarkable year for the company as we executed on our strategy of a low cost diversified E&P, delivering moderate growth and sustainable free cash flow to our shareholders.
As highlighted in our fourth quarter press release and slides, we finished the year with another impressive quarter of operational execution and cost discipline. Production was toward the high end of expectation, and capital and unit production expenses were again below plan.
For the full year 2019, we delivered extremely well on all areas in our control. It was quite possibly the best year of execution and delivery of our strategic objectives of many years that I have experienced in this business. I want to congratulate the Noble Energy and Noble Midstream teams, our partners and shareholders for all that we accomplished last year. Many of our accomplishments can be seen on slide three.
Beginning the year, we lowered our capital expectations 17% from 2018 levels, while anticipating 5% pro forma volume growth. We actually drove nearly 7% total production growth on 25% less capital. Combined our capital savings of $240 million and operating cost reduction of $120 million improved our total cash flow by $360 million from where we expected when we started 2019.
In our U.S. Onshore business, we delivered 10% total equivalent and 10% oil growth over 2018, while achieving record safety performance for the year. We promised to have Leviathan on production by year end and did so, at more than $200 million under budget.
Also in our Eastern Med business, we substantially expanded the total quantities of our gas sales contracts into Egypt, while securing a pathway through the acquisition of interest in the EMG pipeline. In West Africa, we sanctioned the Alen Gas Monetization Project and first production remains on schedule for early 2021, driving incremental cash flow and volumes next year. We also commenced production from the Aseng 6P oil well, which is producing in excess of expectation.
2019 was an exceptional year for reserves as we replaced 233% of our production at just over $7 per equivalent barrel development cost. U.S. Onshore approved developed reserves were added an attractive cost of under $8 per equivalent barrel.
On the portfolio side, we continued to build long-term value potential for Noble Energy with an exploration farm in offshore, Colombia and we added to our low-cost unconventional acreage position, now totaling over 200,000 acres, primarily in the Powder and Green River Basins in Wyoming.
We targeted $500 million to $1 billion in portfolio proceeds for 2019 and we were able to achieve that outcome with full year proceeds of over $800 million, including $670 million from the Noble Midstream transaction. This helped us close the — close out the year with $4.5 billion in financial liquidity.
I was also pleased that our Board approved a 9% increase in our dividend last year, reflecting confidence from the significant cash flow increase that is occurring in 2020.
On the ESG front, I mentioned earlier, our record Onshore safety performance in 2019, we noted other advancements in our eighth Annual Sustainability Report and our first Climate Resilience Report, which utilize the TCFD framework. We also welcomed Martha Wyrsch to our board in December, our third new member in the last two and half years.
The greatest single achievement in 2019 was successfully bringing Leviathan Offshore Israel on production. The safe and successful execution of this unique development has been world-class, continuing our exceptional track record of major project delivery.
We are already delivering volumes into Israel, Jordan and Egypt, making it the first time in Israel’s history to have significant exports to regional customers. Brent will provide more details on the fields ramp up and sales outlook, but I am extremely pleased with the early production history and reservoir performance. The notion that world-class fields get bigger and better certainly applies to Leviathan.
An essential part of Noble’s competitive advantage comes from the blend of short cycle Onshore unconventional assets with world-class Offshore conventional assets. Few companies have this combination in their portfolio. This asset mix provides us investment optionality, a top tier corporate decline rate and the ability to build the company in a capital efficient manner focused on generating returns.
If you have seen slide nine before and we have updated it to highlight a real differentiator for Noble Energy. With Leviathan now on production, we expect our total company annual production decline rate to be in the low 20% range.
You can see how well that positions us compared to the decline profiles of key U.S. Onshore basins. This year we expect over 30% of our production and nearly 40% of our operating cash flows to come from our conventional low decline assets. This provides more certainty of cash flows, lower maintenance capital and ultimately positions us to make the right capital allocation decisions for our shareholders in all macro environment.
We have also updated slide 10, which represents our multiyear capital allocation framework. As compared to last year, 2020’s model reflects a substantial improvement in our maintenance capital needs from $1.6 billion projected annually to $1.4 billion going forward. The improvement primarily reflects the significant reduction in oil costs from our Onshore business.
This framework remains highly focused on generating strong returns through commodity cycles and driving sustainable free cash flow. As mentioned many times before, our planning targets the following; one, plan the business for a long-term WTI oil price of $50 per barrel to $60 per barrel; two, generate a competitive free cash flow yield annually with significant return to investors, focus on delivering at least $500 million in upstream free cash flow this year with the potential to continue to grow going forward; three, maintain a strong balance sheet and financial flexibility; and four, drive a long-term production growth CAGR of 5% to 10%.
For 2020, we have set our capital budget at $1.6 billion to $1.8 billion at the upstream level, as we prioritize our free cash flow generation and balance sheet support over additional growth.
Capital spend for 2020 is estimated down 25% from last year while production volumes should grow 10% and operating cash flow grows even higher. This occurs as our margins improve with Leviathan startup but also from the allocation of capital within the U.S. Onshore business unit. Brent will touch on this more later. But even with level year-on-year onshore equivalent volumes, we expect moderate U.S. Onshore oil growth.
Use of free cash flow will continue to be prioritized for return to investors through dividend growth and balance sheet improvement. With everything we have delivered in 2019 and recognizing commodity price volatility, I am even more confident now in our ability to generate sustainable free cash flow, while continuing to build our business.
This year we have also modified our short-term and long-term compensation programs to further highlight our focus on organic free cash flow and ESG improvement. These changes reflect an increased weighting in the short-term bonus pool towards defined metrics, with organic free cash flow being the highest weighted metric for 2020.
In addition, we have modified our long-term incentive plans, moving away from solely peer relative total shareholder return performance and incorporating cash return on capital employed and ESG measures. I believe these changes further align our interest with those of our shareholders.
As I hand over to Brent, I want to highlight three key factors where Noble Energy is distinguishing itself. First, outstanding execution, which set the stage for 2020s decreasing capital and increasing cash flow and volume.
Second, the move to a lower annual corporate production decline rate and maintenance capital.
And third, a global inventory that includes substantial low cost discovered resources that can utilize existing infrastructure to generate competitive returns.
Our accomplishments in 2019 serve as evidence of our ability to provide differential performance for our investors.
Thanks for your time this morning and I will now hand this over to Brent.
Thanks, Dave. Good morning, everyone. 2019 was truly a tremendous year for the company. We closed out the year with a strong fourth quarter and with an extensive list of accomplishments during the year. As we move into 2020, we are building on our 2019 successes, and as Dave discussed, we expect to increase cash flow and production and decrease capital and expenses.
In the U.S. Onshore, we achieved sustainable reductions in capital last year through several initiatives including faster drilling rates, accelerated completion times, lower cost facilities and well connects.
On the expense side, optimized compression, improved uptime and reduced workover frequency are examples of long-term changes in the efficiency of our base production operations.
I expect the 2019 capital and expense gains to continue into 2020 and beyond. We also achieved those improvements in our execution and cost culture, while — cost structure, while maintaining a strong company-wide safety culture.
In 2019, we achieved a record low total recordable incident rate for the U.S. Onshore and we delivered the Leviathan platform in Israel and the Aseng 6P well in Africa without a recordable injury. Each of these programs are well executed for less capital than planned, which strengthens our conviction that efficient operations are safe operations.
Our 2019 execution success has also shaped our thinking about capital allocation for 2020. As Dave mentioned, we set the total capital budget for the company of $1.6 billion to $1.8 billion, which includes Offshore major projects, exploration capital and essentially maintenance capital level for the U.S. Onshore.
Through the year-over-year improvements in capital efficiency, we are planning a similar number of activities in the DJ and the Delaware for the 2019 drilling campaigns for approximately $200 million less capital. The program is expected to generate DJ growth to offset Eagle Ford decline and maintain or modestly grow Delaware production.
We think that the focus on DJ makes sense based on the scale and the remaining inventory in the DJ Basin, our track record of successful execution returns there and the ability to grow while generating significant cash flow.
We expect this capital plan to deliver moderate onshore oil growth as production increases in the more oily DJ assets and offsets decline in the NGLs and natural gas and the Eagle Ford. All three U.S. basins are designed to generate free cash flow in 2020.
Jumping into some asset specifics, in 2019, the DJ Basin delivered more than 20% growth over 2018 and during the year Mustang and Wells Ranch both delivered quarterly record production. The strong performance in the Mustang development area resulted in positive reserve revisions of almost 27 million barrels equivalent for the year, validating the quality of our acreage and the importance of consistent row development.
DJ operating costs were down more than 15% year-over-year with record lows in the fourth quarter. Furthermore, the DJ DD&A rates improved by more than $3 a barrel for 2020 reflecting the improvement in EUR and cost per well. The exceptional performance for the year is trending into 2020 and we expect even more efficient development in Mustang.
Our first sales for the year will complete Row 2 in Mustang on the far eastern side of the development and then we will move to Row 3 which is immediately adjacent to Row 2, and we plan to utilize the existing upstream and midstream infrastructure, therefore, reducing the well costs and improving the efficiency of the well connects. In the first quarter, we plan to run three rigs and two frac crews, and are targeting about 20 TILs.
Our North Wells Ranch comprehensive drilling plan is progressing through the approval process and the CDP will add about 250 long live drilling permits to our existing permit inventory and It will give us the clarity to about two more years of drilling activity.
In 2019, the Delaware Basin delivered 25% growth over 2018 and during the year, we realized several important improvements in the asset. Row development has improved the consistency of our well results, drilling and completion efficiencies have helped reduce well costs by over 20% and LOE has decreased by more than 30% on a per unit basis.
In my experience, it is rare to see such dramatic year-over-year improvements in an asset and it would be difficult for us to replicate the magnitude of the 2019 improvements. However, we still expect to see cost structure and well performance gains in the Delaware again in 2020.
So, for example, in the fourth quarter of 2019, we completed four wells in the southern portion of our Delaware acreage and the 30-day IPs on those wells averaged 200 barrels of oil per 1,000 foot or 260 barrels per foot on an equivalent basis. Those great results demonstrate how we can further improve well performance with optimized landing zones and customized completion designs.
As we apply those ideas and techniques across the acreage position, we expect to see improved well performance, increased capital efficiency and even better returns in 2020. In the first quarter, we will have two rigs and two frac crews running in the Delaware and deliver about 15 TILs. The Eagle Ford asset will continue to be a considerable cash flow generator as we maintain focus on base production optimization in 2020.
Closing out the U.S. Onshore, I want to highlight the strong underlying performance of Noble Midstream. The team at Noble X has done a great job of building out the gathering infrastructure to support Noble Energy’s activity in the DJ and the Delaware.
Like Noble, Noble Midstream is nearing the end of a heavy investment cycle and transitioning the longer term sustainable cash flow and the impact of long haul pipes out of both basins along with significantly reduced organic capital outlook positions Noble Midstream very well for 2020 and beyond.
Turning to the Offshore. We delivered several strategic milestones in 2019 clearly punctuated by the start up of Leviathan at year end. As we signal, we expect EMed and Leviathan to be the growth engine for the company in 2020. Since startup, the field has been ramping up and on peak days, we have exceeded 1.8 Bcf per day from both Tamar and Leviathan combined.
As Dave mentioned, we also successfully opened up new markets in the region with exports flowing into both Jordan and Egypt. As we ramped up production in the field, the Leviathan wells have proven to be even more prolific than we anticipated, with well deliverabilities exceeding 400 million cubic feet a day due to the very high reservoir permeabilities and thickness.
Our focus in 2020 is going to be to deliver safe operations, demonstrate supply reliability and increased value through greater contracted sales. We have a combined 2.3 Bcf of capacity and we are primarily focused on increasing the utilization of that capacity this year.
Capital allocation for 2020 in EMed will be approximately $100 million, which includes the Tamar South West Pipeline project, compression at Ashkelon on the EMG pipeline and the debottlenecking project on the Israel INGL pipeline grid.
In addition to the value creation of the project and the regional economic benefits, Leviathan is a very long-term source of clean reliable energy because the use of more natural gas and less coal for electrical generation will result in significantly better air quality in the region.
In West Africa, the Aseng 6P well and the Alen sanction were the highlights for the year. The 6P well has continued to outperform expectations and will help reduce base declines in 2020. Also for 2020, we will allocate approximately $165 million to the Alen gas project facilitating an early 2021 startup.
The project already had a positive impact on the 2019 results with 34 million barrel equivalents of reserve additions from Alen and 18 million barrels of positive revisions from extending the economic life of the Alba Field.
Bigger picture, our longer term capital planning also includes exploration as a means to adding future resources and maintaining longer term portfolio value. In 2020, we allocated $65 million to drill the Kumbia prospect in Colombia, which is in the second half of the year. This will test targets approaching 0.5 billion barrels of resource at the midpoint of estimates and a successful well here will derisk additional prospects in the basin.
So I will wrap up this morning with guidance, first for the full year. During the year, we expect U.S. Onshore capital spending to be about 60% weighted to the first half of 2020, similar to the profile in 2019 and we also expect the 2020 production profile to be similar to 2019 with second half growth in the U.S. Onshore driven by peak second quarter TIL counts. Importantly, U.S. oil production is expected to be up 3% to 5% year-over-year and 5% to 7% 4Q to 4Q.
In the Eastern Med, we anticipate the second quarter to be the lowest sales for the year with a peak in the third quarter due to growing contract quantities and second quarter lower seasonal demand. Based on the successful startup of the field, we are maintaining our prior guidance of 1.4 Bcf per day to 1.6 Bcf per day gross from our Israel fields in the first half and 1.8 Bcf per day to 2 Bcf per day in the second half of the year.
Due to shift in Africa due to greater capital and maintenance activities this year and then in 2019, we expect more quarterly variability in our sales, expenses and cash flows. Q1 sales will benefit from additional lifting and then we also expect some fourth quarter downtime as we prepare for the Alen gas project to come online and do a planned maintenance at the Aseng and the Alba Fields.
Specifically in the first quarter, we expect Q1 volumes to be up meaningfully from the fourth quarter primarily due to our incremental Leviathan production and all three U.S. Onshore business units should be down in Q1 because of low fourth quarter and first quarter activity levels. In Israel, we expect 410 million cubic feet a day to 440 million cubic feet a day net from our Tamar and Leviathan assets.
In West Africa, all sales are anticipated to be higher than production with total equivalents down slightly quarter-over-quarter, primarily due to natural gas declines in the Alba Field. Total company sales for the first quarter anticipated to be 378,000 barrel equivalents per day to 398,000 barrel equivalents per day. Now I would expect the second quarter to be relatively consistent with the total first quarter volumes before we see another substantial jump up in the third quarter.
For 2020, we remain committed to capital discipline and shareholder return and we believe it’s prudent to prioritize total company free cash flow generation over U.S. Onshore production growth, particularly when considering the total company year-over-year production and cash flow growth from the Eastern Med and the uncertain commodity price environment.
Beyond 2020, the combination of the depth and quality of our unconventional and conventional inventory, our ability to execute on our plan and manage costs, our low decline rate and our capital discipline all enable us to deliver long-term sustainable growth and free cash flow.
This completes our prepared comments. I will now turn the call over to the operator for Q&A.
Thank you. [Operator Instructions] And the first question will come from Arun Jayaram with JPMorgan. Please go ahead.
Yeah. Good morning. Dave, you did reduce your maintenance CapEx by $200 million. I wanted to know how you will deal with uncertainties in 2020 regarding the plan, you obviously have the Coronavirus, the warm start to the winter weather season and weak gas prices in the U.S. and Europe. So wondering how you would flex 2020 if prices are below the reference prices that you highlighted in slide 25?
Appreciate it, Arun, and I will tell you what, it’s great to be sitting here in 2020 despite all those other outside influences coming off the momentum that we created in 2019. And I think that will go partly to answering your question as I talk about it.
Because I think to your point, we had a reference deck out there we were looking at when we budgeted, but we have also obviously kept track of strip pricing and so forth. And I’d say even in the strip case that’s out there now, that’s been influenced by some of those things that you have talked about, we are still staying committed to that free cash flow generation, partly because of the hedges we have in place already and partly because of the momentum that we are continuing to carry in on the capital efficiency improvements. So, I think, we are staying committed and focused on that and we will play it out from there.
Yeah. Fair enough. I had one question regarding 2021. I was wondering if you could help us think about the volume impact from the Alen gas monetization project. It looks like it’s going to be start up in early 2021? And in your mind is the path to get to full volumes at Leviathan in 2021, 2022?
Yeah. I think when you think about a Alen, we should be able to and what Keith and his team is working on, is getting that ready for early ‘21. I think a full year impact of that what we laid out in there was around 260 million a day gross. So somewhere in on an equivalent basis 15,000 barrels a day to 20,000 barrels a day equivalent for us if I am not mistaken. So that’s a nice catalyst as you look into ‘21.
And then the other piece that you referenced is and you look at the profile this year, is the ramp up in the Eastern Med in the second half of the year and carryover into next year. So our focus in ‘21 will be on carrying over that ramp up from the second half of this year.
And then seeing if we can supplement that by filling out some of that capacity that we still have available there. So I think you have got opportunity for both of those things to be a very nice catalyst as you go into ‘21.
Great. Thanks a lot.
Our next question comes from Brian Singer with Goldman Sachs. Please go ahead.
Thank you. Good morning.
Good morning. Brian.
First question is on Israel gas, little bit of a slight follow up there. You talked about increasing utilization of Leviathan over the course of the year and I wondered if you could just add even more color on some of the moving pieces, production capacity versus seasonal demand versus maintenance or pipeline constraints versus contracting as we go through the year, and specifically, what you see as the market for additional contracts and how that could impact your production and pricing.
Yeah. Brian, this is Brent. We took all those things into consideration when we originally guided the third quarter last year — on our third quarter call last year for this year’s full year. We still think we are going to see a step-up in the first half to the second half all factors considered.
But the startup has gone very well. And as I mentioned in the prepared comments, we have been above 1.8 Bcf a day on peak days from the combined total of Tamar and Leviathan on a gross basis. So I think other than some seasonal lower demand in the second quarter, we think we have got the profile model about right.
And then, remember, as we move into the second quarter, the contracts and the exports to Egypt step up, so we go to 450 million a day. So that’s what’s influencing our second — first half to second half year growth and what’s already contracted.
My second question is on proved reserves. Can you speak to the drivers and the production mix in the U.S. of the increase in PDP and then what drove the downward revisions? And how does the reserve report as well as the point that you made on expectations for well performance and costs in 2020 impact your interest in pursuing inorganic growth projects in the U.S. going forward?
Yeah. I think just to hit on the proved reserves, the biggest positive revisions and improvements on proved reserves in the U.S. were in the DJ. The downward revisions were more a reflection of change in activity timing and making sure that we are staying in that four-year to five-year level on activity and then also, there was obviously some impact from price, there was significant price changes from ‘18 to ‘19.
And then from an inorganic perspective, when you take that and how you see the costs and expectations for performance in the U.S. business? Does that make you more or less interested or uninterested in pursuing inorganic growth acquisition types in the U.S.?
Well, I think, we have said and we have consistently said, we are not focusing on acquisitions, if that’s what your question is, but we are focusing on continuing to get more and more efficient and develop out the large global resource base that we have both U.S. and international. We have that significant benefit of a large global discovered resource base.
And our next question will come from Charles Meade with Johnson Rice. Please go ahead.
Good morning, Dave to you and your whole team there.
I wanted to ask a question about the U.S. Onshore and if you guys could deliver or offer for more details on how some of the drivers over the back half of ‘19 into ‘20. If you look at the — you guys came in under CapEx guidance in both 3Q and 4Q and I think part of that was the U.S. Onshore and when we look at your 1Q guide, the U.S. Onshore oil is going to decline, depending on where you fall in your guidance, 8,000 to 10,000 barrels a day, but you guys are putting the — you guys are putting the pedal down, it seems, on your spending in 1Q. So can you talk about what those drivers were and how much of that decline we are seeing in 1Q was really a function of you guys coming in perhaps below what you are spending — what you thought you are spending was going to be in the back half of the year.
So just to give you a little background, we got more activities done through the full year 2019 than we budgeted for less capital, but it’s timing related, because we were accelerating the completion pace and the drilling.
We pulled some of those third quarter completions in the second quarter and some of the fourth quarter into of the third, so our fourth quarter last year and our first quarter of this year TILs, the new projects it turned into line, were lower than we would have thought about at the beginning of last year. So that’s what contributed to the production outperformance through the year. It also — it is also what’s causing the shape of it as we go fourth quarter to first quarter.
All that was in line with our expectations with the exception maybe of the outperformance that we saw in the DJ and so in that case, we beat volumes in the DJ over what we would have guided in the fourth quarter and we grew more oil in the full year 2019 because of that outperformance. So far we are not seeing anything negative in the way we were modeling well performance, capital, or capital efficiency.
I’d say, Charles, just to add to that and Brent highlighted it as prepared comments, you look at that even fourth quarter to fourth quarter oil volume increased from ‘19 to ‘20, that’s pretty significant for the onshore portion.
Got it. That’s some of the color I was hoping for. And then I have a question on kind of your — a refresh or an update on how you guys are thinking about your target leverage or target debt, you guys — you are going to have some free cash flow this year. You guys mentioned the dividend is a priority, but can you tell us or give us an update on your thinking on what metrics you guys use, whether it’s an absolute debt level or whether it’s a consolidated leverage or upstream only leverage that you are looking to get to?
Yeah. Charles, I think, we have been fairly consistent of staying focused on talking about the net upstream, that the EBITDA target of 1.5 or lower over the next few years and that’s the trajectory we are going to continue to watch and stay focused on. So I’d say the priorities as you mentioned are dividend and balance sheet trajectory.
Got it. Thank you, Dave.
The next question comes from Doug Leggate with Bank of America Merrill Lynch. Please go ahead.
Thanks. Good morning, everybody.
Dave, I wonder if I could hit Israel first of all, I mean, thanks First of all for the cadence in the second half. But I wonder if you can give us some idea as to what your exit rate looks like in Israel, what your expectations are, maybe in the answer if you could address some of these headlines that have been circulating around Jordan as it relates to the exports and I have got a follow-up question?
Dave Stover A – Dave Stover
Yeah. We have been very pleased with our export and what we have been seeing out of both Jordan and Egypt and the support and cooperation in both places. I think it’s been remarkable. When you look at our second half of the year, what we have said that 1.8 Bcf a day to 2 Bcf a day for the total Eastern Med volume, and I think that’s still a reasonable place to be thinking about.
I think when you look even beyond that and it was touched on earlier, it is a good place here to dive into this, I think, but it’s been absolutely remarkable, the impact that Leviathan has had on the region. When you think about how it’s brought together the countries. I mean, obviously, the cooperation between Israel, Jordan, and Egypt.
But then you think about it on a bigger scale, you now have an Eastern Med gas forum that started up, you have got countries like Cypress, Israel, Egypt, Jordan, Palestinian authority that are all getting together to think about how do you use this huge resource in the area that’s now, and I think, partly from Leviathan getting a lot more international attention.
And then, you have got other groups that are looking at things like how do we get gas to Europe. You have got groups pulling together discussions on a pipeline in the Europe. We are looking at FLNG as a competitive option. You have got the opportunity to use the gas plants in the LNG plant in Egypt.
So you have got some very strong competing options and a very strong pull to get gas into Europe at some place and just expand the whole horizon of development and broader reach of this large resource and that’s getting attention. It’s getting attention from the country’s themselves and it’s getting attention from a lot of international players. So I have got to give Leviathan a lot of credit now for having now been online just creating kind of a revitalization of that part of the world from an energy perspective.
I appreciate the lengthy answer, Dave. My follow-up, I am not sure if you will be able to offer any color here, but I am looking at slide 20 in the book and I think for — at least for those on the sell side, that’s a really helpful chart in terms of how the cadence of a land kicks in for the production profile. But my question is what can you tell us about your cash flow coming out of EG, because obviously you are providing the resource but there has not been much disclosure around the terms, obviously, so I am just curious when we think about the contributions of volumes coming from your legacy asset. How does your cash flow trajectory evolve as we look at that chart evolve as we look at that chart on page 20?
Yeah. Doug, we haven’t guided yet — this is Brent again. We haven’t guided yet to that level. We have stated the volume level. But we will remind everyone that this is very low cost to liquefy, a very low cost project to operate, because it’s all existing infrastructure with the addition of a new pipeline to the LNG plant.
And then the only other variable would be global gas prices that you can think about, right now they are softer than they have been in the past, but long-term it would be a global gas price, because we own the equity gas to end markets.
All right, guys. I thought I’d give it a go. But I appreciate the help and appreciate the capital discipline. Thanks.
The next question is from Michael Hall with Heikkinen Energy Advisors. Please go ahead.
Thanks. Good morning.
Good morning, Mike.
I appreciate the time. I just want to — I guess focus a little bit on the U.S. Onshore business, that exact growth rate you provided for U.S. oil. It looks pretty good relative to where we were. I am just curious how are you thinking about the sustainability of that level and then how would you frame your inventory depth in the U.S. Onshore, let’s say, for 2021 and beyond, at this point, how are you thinking about that?
Yeah. Mike, this is Brent, again. Yeah. I think the second question first is, we still feel like we have got a long runway both in the DJ and the Delaware, high return, high quality inventory, partly because of the size and scale of the DJ position and then, partly because of a lower activity levels that effectively extends our inventory life in both places.
So we think we have got lots of sustainability in terms of depth and quality of inventory and Colorado specifically, we have got a deep inventory of approved drilling permits and we are working to extend those more with the new CDP we are working on.
In terms of the oil part of it, it’s — even though we are keeping the U.S. essentially flat year-over-year 2019 to 2020 with the current capital plan because we are focusing it in the DJ and the Delaware that are oilier than the Eagle Ford by comparison. Then — that’s why we are able to grow well and that trend would continue going forward as long as we continue to focus capital on those two basins.
Okay. That last bit was what I was hoping to hear. That’s helpful. And I guess, maybe if you could also translate to total corporate oil. I mean, I know there’s some downtime in the fourth quarter in West Africa, is that just affecting gas volumes, should we — how should we think about the fourth quarter, exit currently for the corporate place?
Dave Stover A – Dave Stover
Yeah. Primarily, yeah, there is some oil condensate type of mix. But then when you get into ‘21, we will have that behind us and then Alen will also have some condensate that comes with that.
Okay. Great. I appreciate it guys. Thanks.
The next question is from Scott Gruber with Citi. Please go ahead.
Yes. Good morning.
Good morning, Scott.
I just wanted to follow-on the last final question really focusing on the DJ, because that’s where you are growing in 2020. You mentioned maintaining that momentum into ‘21, given the inventory depth. But just as you think about the asset long-term, is there a plan to shift the asset to the maintenance mode at some point, and if so when? And just how could international growth opportunities affect that timing?
Yeah. I don’t think — this is Brent. I don’t think we think about it like shifted to maintenance mode or not. It’s — our capital allocation, long-term is returns driven and the DJ returns stack up very well right now in the portfolio. And so I think as long as it’s in that position, then it would continue to garner its funding and then the growth would be an outcome, not a goal. Remember that asset is already like all U.S. assets, but even at the current capital and current growth rate, DJ is free cash flow positive at the asset level and so we can continue to stay in this mode for long-term.
Got it. And a follow-up on the seasonality in the U.S. both from a CapEx and production standpoint, it sounds like it’s going to repeat again in 2020 and potentially CapEx flexing down a little bit more in the second half if commodity prices stay weak. But, in general, are you comfortable with that seasonality on an ongoing basis, would it be better to try to smooth out the CapEx over the course of the year? I guess the real question is do you feel like you are losing any efficiency in our operations with that seasonality?
Yeah. That’s — it’s always — always best case if you could be perfectly level loaded in all aspects of the business. But if you look at the performance from ‘18 to ‘19 and look at the improvements and cycle time reductions, capital and capital efficiency for the U.S. Onshore, even though we were kind of 60% front half loaded in 40% back half loaded on capital. I think we found ways to manage that little bit of unlevelness. It’s not that much. But it’s manageable and we are still able to hang on to or drive even significant improvements in the capital efficiency. It takes a lot of planning and scheduling. But that’s what we do.
Got it. Appreciate the color.
The next question is from David Deckelbaum with Cowen. Please go ahead.
Good morning, everyone, and thanks for taking my questions and thanks for the outlook. Curious as you guys look at Leviathan and we have read reports that from some of your peers out there and some of your partners that there are decisions this year on expansion. I think, Dave, you talked about floating LNG as a viable option. Can you give us a timeline on when you would expect to make those decisions around expansion and given some of the productivity, where you sort of see that capacity tapping out for the feel at this point?
Yeah. This is Brent. Maybe I will jump in and take that. We have said pretty consistently for 2020. Our priority is making sure we can demonstrate safe, reliable supply coming from the Leviathan project and so far so good in that regard.
And then utilizing the existing capacity, so in total, we now have 2.3 Bcf a day in the Med and so those are definitely going to be our primary focus for 2020 and even 2021 when we roll into it. But because of the size and quality of this resource, we are — I think we are a long-term — for a long-term going to be talking about expansion possibilities.
So the one that we have talked about publicly is that we have got a floating LNG, FLNG FEED study underway, as Dave mentioned, and that’s a possibility to expand to additional markets, the others would be in all three countries. We could expand in Israel, Jordan, and Egypt and we can ultimately maybe get it exported out of Egypt through the LNG facility. So all of those are all actively being worked and we are looking to be able to expand with demand.
Got it. I appreciate the color there and recognize it. There is not a whole lot you can say there. And just wanted to ask a question on U.S. Onshore, you talked about the mix right now, the focus on DJ obviously in Delaware and that mix of 60-40 split, is pretty consistent I guess with 2019. Is there a point and your long-term development profile where that switches — does it happens beyond the proposed Wells Ranch CDP? And I guess as a follow on to that is, as we think about capital of those assets, I know it’s returns base at this point? But given the corporate level focus on free cash generation, now if we are looking at strip now in the low 50s, is there a sub maintenance profile that makes more sense from a free cash generation perspective?
It feels like we have gone a long way here from ‘18 to ‘19 to ‘20 in terms of driving down U.S. Onshore capital and driving up capital efficiency. At the level that we are at now to the earlier question, we are pretty low in terms of activities, rigs and stems and we have got it matched up pretty well in the pace of development.
And so it feels like a good level. If prices go lower though, we have been very, very consistently committed to our free cash flow objectives. And so we would have to think about something in the back half of the year for an adjustment.
Thanks, Brent. Appreciate the color, guys.
Thank you, David.
The next question will come from Scott Hanold with RBC Capital Markets. Please go ahead.
Yeah. Thanks. I am just kind of building on a couple of the line of questions a little bit. Obviously, in 2020, you got the nice growth in Leviathan and then EG in 2021. As you look a little bit bigger picture longer dated. I mean, do you feel, I mean, do you see the need to continue to ramp up the U.S. Onshore a little bit more as you get into some of those out years to provide that 5% to 10% growth? And maybe as a part of that discussion, when you think about things like FLNG, how long of a timeframe do you really have there, is that two years — one year, two years, three years. Can you give me — give us a sense of how long that would take to come to fruition.
I think, let me start with the last question on FLNG we will be doing a hard look FEED study this year. So by the end of this year, we will have a better perspective and I think to actually bring it about to a reality price takes say plus or minus three years, let’s call it, something like that.
I think on your other question, which goes to the longer term outlook for the company. I think that’s where our ability to have maintained our exploration capabilities also comes into play. I mean, hopefully, not missed in the discussion was the fact we are back to drilling significant material exploration prospect this year Offshore Colombia.
And we have consistently focused on three to five key material potential plays going forward that any of those could supplement our outlook as we go forward just as our Offshore developments so far were driven by exploration in the past.
And then in the Onshore business, let’s not forget the significant position we have built in — particularly in Wyoming up there in the inventory. And my expectation is over time — over the next five years, that will start to compete with DJ and Delaware to give us another leg to build off.
So I think the beauty of our portfolio — of a diverse portfolio is the fact that we have maintained our Onshore capabilities, our Offshore capability and our exploration in major project execution and that gives us a lot to look forward to going forward.
That was a great color. And my follow-up is, is on the Eagle Ford, obviously, getting really no capital this year and not much last year? Given it’s free cash flow, but it is a declining asset and just from a visual perspective, it obviously weighs on that U.S. growth rates on, especially in a BOE perspective, what is the big picture or long-term plan of the Eagle Ford?
Yeah. Scott, some of the things we have talked about in the past is there is still a lot of resource there, that’s in the secondary upper parts of the Eagle Ford and we tested last year a pilot program to do some refracs to see what we could do with the older wells in the older vintage completions.
So those — that upside still exists and there is still potential that’s out there. But right now the heads up drilling capital doesn’t compete with the Delaware and the DJ, so it will stay in its free cash flow generation posture.
Would it be a monetization candidate?
Yeah. I mean, we have said off and on that we are willing to think about investing non-core assets and we have done a fair amount of that over the last couple of years. So if somebody came out with a big enough check, we think about it.
Appreciate it. Thanks.
The next question is from Paul Cheng with Scotiabank. Please go ahead.
Good morning. Thank you, guys. Two quick questions. One, do you have an estimate — what is the remaining prospect inventory at DJ and Delaware, Based on a $50 WTI and $2.50 Henry Hub on all-in, including CapEx, G&A and all that to generate 10% return?
I don’t have numbers right here in front of me, but what we have continued to say is that the activity levels, we have got 10 years type inventory or beyond on this stuff that fits our return…
Right. And Brent that when you guys say 10 years, what kind of returns that you are based on and then whether that’s including on the all-inclusive on the field level. What I was trying to understand what’s the baseline that we are using?
Yeah. So just a reminder, our investment for the next well AFE is our hurdle rates of 30% hurdle rate and that’s what we would start on these long-term inventory kinds of conversations. And then remember that we have been driving capital efficiency significantly. So when we take out a couple of million dollars of well cost and/or improve the productivity of the wells, like, we have been doing in both DJ and Delaware, then not only that increases the value of the inventory. So that’s the way we think about it long-term.
Okay. Then second one that, I think, with issue with that, now your total capacity 2.3, I think, you have two opportunities, maybe up 400 million cubic feet per day at a time. Just curious that, I mean, do you have a rough estimate, what is the CapEx requirement if we do want to expand the next 400 million cubic feet and then the next one?
Yeah. I think the best way to think about it is to take you back to our long-term capital framework. We have laid out, total company 1.82 Bcf a day to 2 Bcf a day over the next five years, that includes both exploration and major projects. And those expansions you are talking about and the Leviathan fit within that framework. So the major project capital for a year includes our thinking about how those expansions would come in over time.
So at least one of them is included in that, say, call it, the next five years?
Paul, say that again please.
Does it mean that at least one of the 400 million cubic feet per day expansion is included in the next five years?
Yes. You can assume that because remember, the first expansion is really low cost. We are only talking about some incremental wells and facility mods, and so the first expansion easily fits within our capital framework.
Okay. Very good. Thank you.
The next question is from Leo Mariani with KeyBanc. Please go ahead.
I guess, I wanted to dig in a little bit more into the trajectory of the Permian production here. In 2020, I think, you guys were kind of talking flattish year-over-year, you did have some pretty good Permian growth in the second half of ‘19. So kind of gets to flattish, should be thinking that Permian is kind of down a little bit in the first half of ‘20 before ramping in the second half of ‘20, just wanted to see if I am reading that right?
Yeah. That’s right. And before I expand on it, remember that it’s flattish on equivalents. It grows on an oil basis year-over-year. And then it should grow exit to exit, the fourth quarter to fourth quarter, which means then because of the completion activity in the fourth quarter — lower completion activities in the fourth quarter and first quarter, then we are down a little bit in Q1 and then we grow through the year, got it right.
All right. That’s helpful for sure. And your comment with the oil growing and the equivalent sort of flattish. Is that just reflecting where you will be shifting some activity in the Permian, some oilier areas in ‘20?
No. It’s — that was really a mixed comment. That was flattish on equivalent basis for all of U.S. Onshore, for the Permian it will grow oil and equivalents.
Got it. Okay. That’s helpful. And I guess, just jumping back over to Israel, obviously, you have got a significant ramp in production here in 2020. I just wanted to get a sense. I think that all of that ramp is volumes that are already under contract, which will clearly benefit you guys into 2021 as well. Just wanted to get a sense, now that Leviathan is online and the wells look great, are you starting to see accelerated discussions around new contracts there and you think there is a decent chance you guys might be able to get something in place here in ‘20? And lastly, with respect to Israel, is there any possibility you could sell volumes above what’s contracted in 2020 and 2021 or do you sort of need kind of hard contracts to get those new volumes going?
I think to your question, Leo, we were starting to see accelerated interest before Leviathan even came on line from potential customers. So I think those discussions will continue kind of get back to that more when you build it and they will come type of thing and you are seeing that and you are seeing that interest over there.
The other thing to keep an eye on is how quickly Israel starts to displace coal. We have always talked about that being about a 600 million a day plus or minus type opportunity there and now with Leviathan on, we will see if they kind of accelerate some of that conversion on that opportunity.
So I think they have already talked about moving that up from late this decade to middle of this decade and now that Leviathan is on, I think, that’s an opportunity. So, yeah, we will see. We are obviously not limiting ourselves, we are not limited on capacity right now, we have some room to grow beyond what we have laid out this year and we will see how it progresses, we are just a month — a little over a month into this and everything looks great so far, so a good start.
Okay. Thanks for the color.
Next question is from Irene Haas with Imperial Capital. Please go ahead.
Yeah. Very quickly to follow up on Brent’s comment earlier that Noble X right now is going past a heavy investment stage, so any plan for debt reduction like term loan, due ‘21, ‘22? And also related to this, your interest in Noble X Midstream, are you okay with it, any need to reduce ownership and deconsolidate in the near-term? That’s all I have.
And so, Irene, you are asking of financing our capital structure, question for Noble X.
Yeah. Yeah. Yeah.
So, we will have that call a little later this morning too. But, yeah, you would expect as that business grows over time. It would term out some of its debt. That makes sense. In terms of the ownership after the simplification and drop, we now own 62% of the units. And as you know, we consolidate that business accordingly. And so we have a lock-up for the first six months through mid-year this year.
So nothing would happen in the first half and then longer term, we would have to look at the merits of owning 62% of it. We don’t have to own that much of it to be able to manage — maintain the control of the pace of development to keep up with our DJ and our Delaware activity. So it’s an option to think about.
Great. Thank you.
The next question is from Gail Nicholson with Stephens.
Good morning. First question on the LOE side, there is a lot of moving pieces in 2020, but if we just specifically look at the Delaware and the DJ, can you talk about LOE trajectory in 2020? Is that should we think that’s in line with 4Q ‘19 levels or should we think there’s incremental improvement throughout the year?
I think you think about it more in line with — this is Brent. Think about it more in line with the second half of last year. The fourth quarter was an exceptional U.S. Onshore LOE performance, so it was our lowest per barrel unit cost that we have had in the U.S. Onshore.
It was a combination of things, we had really mild winter, not much to deal with there in the late part of the quarter. We had very low workover kind of maintenance activities. We had really good run time and wells and facilities. So we managed cost well and compression well and those kind of things. Some of those are sustainable and they will flow right in to this year. But we will probably not be as low as fourth quarter as we go through the full year and we have got it more like second half.
Great. Thank you. And then I just kind of wanted to tack onto Irene’s question regards to that — the deceleration times with last year being that heavy NBLX CapEx. How do you guys think about the benefit of that ownership in regards to free cash flow generation really in 2021 forward, like, market doesn’t fully give you guys credit for kind of that annuity like situation, I was just kind of curious on your thoughts of ownership benefit to the cash flow stream in ‘24 forward for NBLX?
Well, yeah. As Brent alluded to it, Gail, on his comments that for NBLX, it’s entering its phase like we have entered now with Leviathan with the new pipes coming on in the big inflection — infusion I guess is a better word, of cash flow that will start to come in here this year and that will carry over on a full year basis next year.
So that’s the big benefit that we see of that, that it’s not that dissimilar to what we have seen from Noble, that NBLX is undergoing their big inflection and transition right now too. And so you get beyond this year and you have got both companies now that are seeing the benefit of these past investments that are generating a tremendous amount of cash flow going forward.
And if I just add one thing, I think I understand your question better. The two big things that we saw last year when we announced the end of the strategic review were the benefits of having the two business together because of the collaboration and the synergies.
And we can — real examples of lower OpEx and lower CapEx that is directly related to the synergies of having the business together. And then the quality of the cash flows in the midstream business, especially as it expands downstream into the oil pipes, we like the quality of those cash flows and the ability to upstream some of that to Noble.
Great. Thank you.
The next question is from Nitin Kumar with Wells Fargo.
Good morning, gentlemen, and thank you for taking my question. I had a quick question on slide nine, as you have brought down the costs in the U.S. Onshore business. What is the breakeven price oil or something for that business today, because it seems like you are doing free cash flow out of the U.S. Onshore with the new plan, is that fair?
So two questions in there. So the breakevens definitely come down, partly depends on how you define it. So if you are talking about just break even at a cost to capital return, it’s going to be sub $50. We invested a higher threshold than that, but that we have driven it down sub $50 for straight cost to capital like returns. What was the other part of the question?
Is the U.S. Onshore business standalone today, free cash flow neutral, let’s say, at strip, or $50?
It is today in our plans for the total of U.S. Onshore and each asset area, each business unit, so DJ, Delaware and Eagle Ford at this year’s capital plans are all free cash flow positive.
Great. The other question, David, you said in your prepared remarks, obviously you have raised dividends about 9% last year in anticipation of the Leviathan free cash flows. As you think about 2020 in the cadence of your spending and production, clearly, it is going to be the second half where it is free cash flow profile. Are you — do you think the Board or the management team is looking to wait till you have more line of sight and actual free cash flows before raising the dividend or you could do it in anticipation of the growth?
Well, we look at that each quarter. If you look back over the last two years, it wasn’t just ‘19 but ‘18 also we raised the dividend in April. So I imagine we will take another pretty hard look at that this coming April also and we will see where we get to.
Great. Thank you so much.
Our next question comes from Jeoffrey Lambujon with Tudor, Pickering & Holt. Please go ahead.
Good morning. Thanks for taking my questions. My first one is just a follow-up to one of the earlier responses regarding staying committed to the free cash flow generation. It sounds like the $500 million target is what will remain intact even if something closer to strip plays out. So if that’s a fair interpretation, just wanted to get a little more color on what the facts could be on the budgeting side in that scenario?
Yeah. I think, you are right from the standpoint, we are staying committed to that even at a strip price scenario. The hedges helped protect that, we don’t see that big of an impact when you move from the 55 to the strip because of that, the hedging that we have in place.
And then the capital efficiencies that we have seen and we are continuing to stay focused on not just capital but operating efficiencies also, give us a lot of confidence and if we stay in that kind of a ballpark, we can still stay focused on delivering that cash flow target.
Got it. And then my second one is just a nuance one on the Eagle Ford, just wanted to see if you can give us a sense for what to expect there in terms of exit over exit production or just how you see PDP declines in general, just thinking about the DJ and the Delaware receiving the bulk of the U.S. Onshore budget?
Yeah. I don’t have the Eagle Ford decline rate in front of us. But if you look on page nine, we showed a typical Eagle Ford declines in the 30% to 40%. That’s probably pretty similar to where we are, obviously, as you get further away from making investments, the decline will level off a little more than that or slow down a little bit, but as we go into 2020 that’s probably a reasonable range.
Ladies and gentlemen, this concludes our question-and-answer session. I would like to turn the conference back over to Brad Whitmarsh for any closing remarks.
Sure. Thank you, Chad, and thanks to all for joining us today. Kim and I are around for questions and answers all afternoon if you have anything and we look forward to talking with you.
The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.