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Noble Energy Inc (NBL)
Q4Â 2018 Earnings Conference Call
Feb. 19, 2019, 9:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
See all our earnings call transcripts.
Prepared Remarks:
Operator
Good morning and welcome to Noble Energy's Fourth Quarter 2018 Earnings Results and 2019 Guidance 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, sir.
Brad Whitmarsh -- Vice President, Investor Relations
Thanks, Denise, and thank you all for joining us today for our year-end 2018 and forward guidance conference call. I hope you've had a chance to review the news releases and presentation deck that we published this morning. These materials highlight our strong finish to 2018, provide detailed guidance for the current year and an outlook for the future. All materials are available on the Investors page of our website. And later today, we plan to file our Form 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 the question-and-answer session. I would ask that analysts limit themselves to one primary question and one follow-up. Our planned comments this morning will come from Dave Stover, Chairman and CEO, as well as Brent Smolik, President and COO; Ken Fisher, EVP and CFO; Hodge Walker, SVP of Onshore and Keith Elliott, SVP of Offshore are here to participate in the Q&A session.
With that, I will turn the call over to Dave.
David L. Stover -- Chairman, President and Chief Executive Officer
Good morning everyone and thanks for joining us. Over the last few years, the company has taken many steps to position Noble Energy to succeed in any environment. We are on the cusp of something very unique and very special. I'm really excited with what is ahead of us. You will hear what is behind that excitement this morning.
In the earnings release and on the slides, Brad has provided detailed information on the fourth quarter. So, I can only add how pleased I am with our execution as we ended the year. For the second quarter in a row, our capital within the lower end of guidance, yet our volumes were at or above the higher end. As Brent will discuss further, this focus on capital efficiency driving even better returns is front and center as we move into this year.
Combined with strict operating cost management, the focus on capital discipline and returns drives our delivery on three key elements important to attracting investments across all sectors. These elements are cash flow growth per debt adjusted share, balance sheet strength and sustainable free cash flow generation that can be returned to shareholders. These themes will come across throughout our discussion supported by our unique high-quality asset base.
This morning, I will start with our 2018 accomplishment and then discuss our strategy moving forward. You can see many of these accomplishments on Slide 5. We generated in all in cash flow surplus for the year, enabling us to return over $1 billion to equity and debt investors including nearly $300 million in share repurchases, over $200 million in dividends with a 10% increase to the dividend and over $600 million in noble debt reduction.
Operationally, Noble Energy delivered 11% pro forma volume growth year-over-year while continuing to maintain an excellent safety record. Led by the DJ and Delaware Basins, our onshore business delivered record oil and liquids production for the year. Our onshore oil growth alone was over 25%. In the DJ Basin, we ramped up our Mustang development and received approval for the 100-square mile comprehensive drilling plan. This CDP is one of a kind in Colorado, providing a clear line of sight to our long-term execution in the DJ Basin. Following the industry's extensive engagement with stakeholders across Colorado, voters rejected a ballot initiative that would have set the state back for many years.
Moving forward, we will continue to support reasonable regulatory solutions that provide more certainty for safe and sustainable operations in the state. In the Delaware Basin in spite of a tough first half, we more than doubled production volumes last year while slowing completion activity in the second half of the year to protect returns and prepare for row development. This sets the company up to take advantage of the development mode benefits that we saw in the DJ and Eagle Ford, driving capital efficiency through productivity improvements and lower costs.
We also added necessary infrastructure and secured long-haul pipeline agreements to the Gulf Coast providing transportation reliability and access to a higher priced market. Internationally, it was a great year for both our Equatorial Guinea and our Israel operations. Each area outperformed volume and cash flow expectations while progressing the high impact natural gas developments that will meaningfully increase our company's cash flow in the very near future.
In Israel, Tamar continued to produce reliably with almost 100% run time as Israel and regional gas demand continues to grow. Our world-class Leviathan project ended the year near 75% complete with the target start-up by the end of this year. I can't tell you how great it feels to be able to say that Leviathan will be online this year. If you get the chance, take a look at the video we included on our Investor Relations website to see the Leviathan jacket recently being launched in the water. It is an impressive reminder of the scale of this project and the execution capabilities that are required for a project this size.
I am extremely proud of the team, Noble and contractors, for this accomplishment. The execution of strategic gas sales and pipeline agreements to Egypt were milestone events in the Eastern Mediterranean in 2018. This provides the pathway for delivery of substantial quantities of natural gas volumes into Egypt. It also reinforces the significance of Noble's gas development and the impact it is having in the region by providing reliable, clean and affordable energy.
Adding to our future potential, last year we captured over 100,000 acres of low cost material exploration inventory in the onshore US and a 40% interest in operatorship of 2 million acres offshore in a new venture country. We expect to drill both onshore and offshore opportunities in 2020 as we begin to test nearly 1 billion barrels of net risked exploration inventory. Overall, we were reminded in 2018 of the volatility of oil prices and how the impact of global markets, sanctions and other events can affect our business.
With that context, Noble Energy remains focused on aligning the business to drive sustainability through commodity cycles. Accordingly, we have designed our business and strategy around the following key components: Number one, plan for a long-term $50 to $55 per barrel WTI oil price; two, generate a competitive free cash flow yield with significant return to investors; three, maintain a strong balance sheet and financial flexibility; and number four, deliver 5% to 10% long-term growth on an annual basis supplemented by additional growth as major projects come online.
In addition, our disciplined capital allocation focused on only the highest return, highest margin opportunities will ensure our investments drive increasing corporate returns. Should commodity prices moved higher than our long-term outlook, we plan to maintain our growth objectives and return the additional free cash flow to investors.
2019 is of strategic importance for Noble Energy as we transition our business to a long-term sustainable free cash flow profile. We're planning for a 2019 organic capital budget of $2.4 billion to $2.6 billion, which is 17% lower than 2018. These investments will grow volumes on a pro forma basis by 5% total company and 10% in the US onshore. Continuing on the track record of optimizing the portfolio, we anticipate strategic portfolio proceeds of between $500 million and $1 billion this year.
These funds will be allocated to support the balance sheet and to opportunistically continue our buyback program. An essential part of Noble's competitive advantage and ability to generate sustainable free cash flow comes from the blend of short cycle onshore shale assets with world-class offshore assets. Our inventory of high return drilling locations onshore provides significant capital flexibility in any commodity environment and our offshore assets are unique, delivering long life sustainable production with very low maintenance requirements. Few companies have this combination their portfolio. It results in a best-in-class corporate decline profile and the ability to replace production in a very capital-efficient manner.
Slide 9 highlights a real differentiator for Noble Energy. With the addition of Leviathan by the end of this year, Noble Energy will have over 30% of our asset base with minimal to no decline for up to a decade. Our overall corporate decline improves into the low 20% range in 2020. You can see how well that positions us compared to the decline profiles of key US onshore basins. This ensures that the capital dollars we deploy drive more incremental value as compared to just maintaining the base. We anticipate that we can hold our entire production base flat going forward at a capital level of around $1.6 billion per year. This is the amount of capital required to essentially replace our US onshore production on an annual basis, with our international assets meeting minimal capital to stay flat.
With the production free cash flow impact from Leviathan coming at the end of this year, I want to provide some initial thoughts on our 2020 expectations. Although too early to outline definitive plans, we anticipate that close to a $2.1 billion capital program would generate a 15% to 20% total company volume growth.
Production for 2020 modeled the full year's impact from Leviathan, consistent with our previous communication of around 800 million cubic feet per day gross. The capital range includes our $1.6 billion of maintenance capital and $400 million to $600 million for growth, split evenly between near-term onshore projects and longer cycle exploration and development projects. At current oil prices, free cash flow would be in excess of $500 million, which we target for return to shareholders through our dividend and buyback program.
We anticipate the amount of free cash flow available beyond 2020 to grow and we remain committed to significant shareholder returns. In summary, we have adjusted our activities to protect returns and manage cash flow. Our plan reduces combined 2019 and 2020 capital by nearly $1 billion from our previous outlook. This plan delivers a more moderate growth profile of 5% to 10% annually, supplemented by specific major project additions such as Leviathan's first phase.
The organization is focused on improving returns through relentless capital efficiency, accomplishing more for the same cost. To further emphasize capital discipline and ensure company wide focus, we've modified our 2019 compensation program to include an annual capital efficiency metric. Looking forward, we are positioned for reliable sustainable free cash flow that can be returned to shareholders, while continuing to build the company through a global inventory of high return opportunities.
As I've highlighted, the start-up of Leviathan this year is transformational for Noble Energy. Now, I invite you to hear what Brent Smolik, our new President and COO has to say regarding our operations. As most of you know, he has been with us just since November and his leadership is already making an impact.
Brent J. Smolik -- President and Chief Operating Officer
Good morning, everyone. Thanks, Dave, it's great to be here. I'm excited to be part of the Noble team. I'm also excited about our future direction and the quality set of opportunities we have ahead of us. So, I'll begin this morning with a few general comments about the 2019 budget and then dive into some details about our assets.
As Dave mentioned, we made the decision to manage our capital expenditures closer to cash flow in 2019 and set the company up for sustainable production growth and free cash flow generation, which led us to a $2.4 billion to $2.6 billion capital budget. In the US onshore, the 2019 upstream capital range is $1.6 billion to $1.7 billion and it is expected to generate pro forma growth of 10% equivalent production and 13% oil production at the midpoint of guidance. The DJ and the Delaware will be important contributors to 2019 and those assets will consume about 90% of the onshore capital spend this year, and grow our combined 15% to 20% versus full year 2018.
We've designed the US onshore business to live within cash flow by the end of this year, which requires that we remain very diligent about improving capital efficiencies. Following the decrease in industry activity in the fourth quarter and the drop in oil prices, our teams have been very active in reducing cost across the onshore US. Since December, the combination of more efficient well designs, faster execution and service cost reductions is resulting in lower capital cost per well.
With all three US onshore basins now largely transitioned to row development and more the backbone infrastructure built, we have the key elements in place to efficiently develop our assets and drive further savings and productivity improvements. Slide 12 begins the asset discussion, beginning with the DJ Basin. We have a high quality core asset in the DJ that continues to differentiate us in the basin. We have blocky, contiguous land positions and the liquids-rich portion of the trend, primarily located in rural areas. The quality of the asset is unique in the basin and as a result, Noble Energy continues to set the benchmark for high oil productivity per well.
Additionally, we have multiple gas processing and takeaway alternatives in the basin, and that benefit was visible in the second half of 2018 production growth, which was partially due to lower system pressures and minimal gas constraints. In 2018, the DJ grew production by 10% fourth quarter to fourth quarter and 15% throughout 2018 from 1Q to 4Q, with the two rig drilling program. The other significant contributor to Q4 performance was the productivity of our initial row at Mustang. Row 1 produced a plateau for most of the quarter, with gross production over 26,000 barrel oil equivalents per day, with over 60% oil. We expect that momentum to continue into 2019.
As Dave mentioned, last fall, we announced the approval of the Mustang comprehensive drilling plan. With the development of this scale, there's numerous operational infrastructure synergies. For example, due to tremendous execution by our DJ team, we now have over 400 approved drilling permits in the Mustang area, the majority of which are valid for six years. For more immediate value creation, we've also identified savings of $500,000 to $1 million per well versus the second half of 2018.
The company will continue to operate one to two rigs and two to three frac crews and bring 95 to 100 wells online in the DJ this year. We will continue to emphasize Mustang development and more than half of the 2019 wells turned in line will be in Mustang.
As we moved to Row 2, we expect to see slightly higher GOR in that part of the basin. As a result, we've estimated the total DJ oil percentage to average 48% to 50% in 2019 and 2020. And, I am highlighting that expected change for guidance purposes, but nothing has changed from our prior assumptions. We expect the Mustang wells to generate great returns, and high oil per lateral foot relative to the rest of our DJ program. I will focus most of my comments on Mustang this morning, but also note that we plan to complete about 40 additional wells in the East Pony and the Wells Ranch IDP's this year.
In the Delaware Basin, the industry battled several challenges in 2018 including rapid activity and production growth, the strange transportation and service infrastructure that led to oil differential weakness, margin pressures and higher drilling completion and facility costs. In the first half of the year, Noble Energy experienced additional challenges, stemming from the appraisal of lower tier acreage in the Southwest areas, some well interference when completing near existing wells and the growing pains of early phase development and rapid facility build out.
By the second half of the year, the company had mitigated many of those challenges. We migrated away from the Southwest and in fact, a portion of that acreage was divested earlier this year. As shown on slide 15, in Q3 and Q4, our average well productivity improved and quarterly production returned to growth. The improvement was primarily driven by two factors; one, high run times at our new facilities and optimized production operations; and two, the new wells that we brought online in 4Q were highly productive.
Furthermore, based on a review of public data over the last two years, Noble Energy delivered upper tier productivity in the Southern Delaware Basin, on a three-month oil production basis for the Wolfcamp A wells. We expect this performance to continue as we refine our drilling and completion designs and further improve our results.
In Q4, our Wolfcamp A wells generated robust 30-day average production rate of 182 barrels oil equivalent per day per 1000 foot lateral with over 70% oil. The company also brought on line a couple of impressive Third Bone Spring wells averaging an IP-30 of over 200 barrels oil equivalent per day per 1,000 foot. Overall, Noble Energy accomplished a great deal in the Delaware last year. We more than doubled our production compared to full year 2017. We completed appraisal of the Clayton Williams acquisition, confirming the quality of the Tier 1 core acreage in Reeves County.
We secured an agreement to transport 100,000 barrels of oil per day on the Epic pipeline to Corpus Christi starting in early 2020 and we also have the option of early crude service from the Epic NGL pipeline, beginning in Q3 of this year. We monetized nearly $250 million of non-core acreage including the Southwest area that I mentioned earlier and note that the cost per acreage that we received met or exceeded our acquisition case valuation. Going forward, we plan to further block up our acreage position in the Delaware, just as we've done in the DJ.
In 2019, we expect to average four drilling rigs and two completion crews in the Permian. We plan to focus over 95% of our 2019 program on row development drilling and we anticipate bringing a total of 50 to 55 wells online with an average lateral length of over 8,700 feet. Through drilling completion and facility design changes and lower service cost, we've already identified $1 million to $1.5 million of well cost reductions versus the second half of 2018.
We plan to remain focused on our core Wolfcamp A zones as well as the Third Bone Spring with most of our completions located near our five central gathering facilities. I am pleased with the progress in the Delaware program and how we ended 2018, but we're not done yet. With the bulk of the 2019 activities in full scale row development, we expect further improvements in completion and drilling efficiencies. We're still early in 2019, but we've already seen significant improvement in stages pumped per day and footage drilled per day in this program. We also expect better production per well.
As a reminder, the first row development wells drilled last year will come online in late Q1. So, although we don't have any production from those wells yet, we're encouraged by the performance of a few row-style wells that we turned in line late last year.
The final onshore asset is the Eagle Ford. We generated significant asset level free cash flow last year and we plan to continue cash flowing to Eagle Ford this year. The 2019 program is focused on completing approximately 20 DUCs and turning those to sales. We expect production to decline in Q1 and then grow in Q2 and Q3 as we bring online the DUC completions.
An important key to our onshore upstream success and a significant value contributor to Noble is Noble Midstream Partners. In 2018, the Midstream team significantly expanded the in-basin gathering infrastructure in the Delaware and built out the backbone in the southern Mustang area in the DJ setting the stage for longer-term capital efficient development in these key assets.
Our Midstream businesses continued to perform very well with a long runway of 20% per unit distribution growth. I'm excited that the team has continued to capture new high return expansion opportunities, including a 30% ownership in the Epic crude line and a 15% ownership in the NGL line. These are attractive opportunities for NBLX and enable Noble Energy to access higher price Gulf Coast markets for our equity barrels at relatively low transportation costs.
Shifting to offshore and West Africa, we continue to see strong performance from our producing assets where we achieved nearly 100% runtime in our operated fields.
I want to congratulate our West Africa team on their diligent work to improve base declines and extend the life of these higher margin assets. Those efforts to push West African volumes above the high end of our 2018 guidance range. In 2019, we plan to drill an additional well in the Aseng field which will further mitigate decline. This well is expected to begin drilling in May and should be online in the third quarter.
We're also progressing the Alen gas monetization project and our marketing activity is targeting a project sanctioned by mid-year. This is a significant step toward monetization of over 3 Tcf of discovered gas in the area. The project will benefit from linkage to higher priced global LNG markets and from the capital efficient use of existing infrastructure.
2018, The Eastern Med, continue to exhibit why it's a world-class natural gas asset. Tamar and Mari-B consistently produced over 1 Bcf per day of gross production throughout 2018 with essentially no decline.
Israel gas demand has been exceeding domestic gas deliverability requiring higher cost LNG to supply growing power generation. That demand growth underscores the importance of bringing Leviathan online, which will provide a second major source of natural gas for Israel. We are also seeing growing regional demand and we continue to pursue additional contracts for Leviathan in Phase 1. As Dave mentioned, the Leviathan project is now 75% complete, a successful step to further de-risk the project timeline and cost and highlights our major project management capabilities.
A few recent milestones; the four subsea wells have been successfully completed and tested and based on those test results, we estimate that each well is capable of producing over 300 million cubic feet per day. The platform jacket fabrication was completed, it arrived in Israel last month and it's been installed offshore. The production deck will arrive later this year and first gas sales are expected by year-end. The budgeted 2019 capital for the Eastern Med is expected to be $550 million to $600 million, which includes some capital for future expansion opportunities.
We'll be thoughtful how we allocate future capital consistent with both the expansion of regional gas demand and our commitment to return capital to shareholders. In the third quarter, we announced the acquisition of an interest in the EMG pipeline to deliver gas into Egypt. We continue due diligence the acquisition and plan to flow test the pipeline by mid-year as part of that process. The pipeline further improves our ability to meet growing regional gas demand and potentially provide gas to global markets through the underutilized Egyptian LNG facilities.
We expect to flow test at least 350 million cubic feet per day through the EMG pipeline beginning with the start-up of Leviathan. We also have a complimentary backlog of offshore projects in inventory that compete for capital with US onshore development. We plan to be prudent in the use of future capital and leverage our existing infrastructure to bring these additional high return, high margin projects online over the next decade.
Going forward, exploration remains a component of our strategy. We plan to invest $50 million to $100 million annually in this program with new prospect drilling plan post of Leviathan.
Let me wrap up my commentary with some guidance on the first quarter. Offshore, our West Africa volumes are anticipated to be lower in the first quarter compared to 4Q by approximately 15,000 barrel oil equivalents per day, about 40% of which is driven by the timing of oil liftings. The remainder, which is primarily natural gas, is impacted by the planned turnaround maintenance at the EG LNG plant. As we've discussed, our Israel volumes have essentially no decline and we anticipate relatively stable volumes throughout the year. And the US onshore, the first quarter should be the low point for well completions in 2019, as we increase completions through the year, we should see a ramp up of volumes with the second half about 15% higher than the first half.
Bringing it all together, total company sales volumes in the first quarter are expected to be between 321,000 barrel to 336,000 barrel oil equivalents per day which will grow throughout the year with US onshore growth. Then, in the end of the year, we and our shareholders will see the huge benefits of Leviathan. I'm excited about our future at Noble, particularly our asset quality, our organizational capability, balance sheet strength and financial flexibility and our company strategy to sustainably increase production and generate free cash flow.
Now, we'll open the line for questions. Operator?
Questions and Answers:
Operator
Thank you, Mr. Smolik. We will now begin the question-and-answer session. (Operator Instructions) Your first question will be from Bob Morris of Citi. Please go ahead.
Robert Morris -- Citigroup -- Analyst
Thank you. Good morning, Dave. Nice quarter.
David L. Stover -- Chairman, President and Chief Executive Officer
Thanks, Bob.
Robert Morris -- Citigroup -- Analyst
You posted some nice wells in the Delaware Basin in the fourth quarter and the guidance that you gave with four rigs on average for the year appears to entail laying down or dropping some rigs in the Delaware here this year. Can you give us some sort of sense as to the completion activity or how activity runs through the year because I know you've been building some DUCs in anticipation of the expanded pipeline capacity, but how long do you continue to build DUCs and then what is the outlook for them beginning to work those down as you go through the year, I know, you said Q1 will be the low point for the year on completions. But if you could just give us a little bit of a sense dropping, looks like a couple of rigs there and then just the pace of building DUCs and then working that down?
David L. Stover -- Chairman, President and Chief Executive Officer
Sure, Bob. Let me start and then I'll have Brent weigh in on it. I think as you mentioned and as we've talked about, we adjusted our activity last year to move to the row development. You can see on Slide 16, how that's laid out and how that efficient we think that can become. When you look at how we're focused in specific areas for this year, I'd say we designed our program and set up our program, looking ahead, so that we'd be bringing on the majority of our ramp up production here as we start to head into mid-year and into the second half of the year especially with the pipeline infrastructure and our ability to move more volumes down this Epic line, it should be turned on by mid-year or into the third quarter. So, I think we tried to sequence this and set this up to take advantage and I think really what it does is provide us the highest return out of this program. But let me turn it over to Brent to give you a little more on the sequence.
Brent J. Smolik -- President and Chief Operating Officer
Yes, good morning, Bob. Yes --
Robert Morris -- Citigroup -- Analyst
Good morning.
Brent J. Smolik -- President and Chief Operating Officer
At the end of the last year, we were about 40 DUCs and because of the row style development, row development program that we have that we're not building DUCs, but we will have about that many in any given quarter as we work through the program. Completions and turn in lines will be a little back loaded. So we'll have about, we'll just have a handful in the first quarter and then we'll be in the teens for turn in lines through the rest of the year. So that's why, we'll get a production ramp through the end of the year, even though, we're kind of front-end loaded on drilling rigs and back-end loaded on completions in TILs (ph).
So, and then, directly answer your question on rigs. That's -- it's a good new story because if we continue to improve the pace, the cycle times for drilling, then it will naturally, we will need less rigs to get the program done.
Robert Morris -- Citigroup -- Analyst
Great, and now, that makes sense. My second question is just you -- the expected 10% to 15% drop in well cost is impressive and you touched a little bit on that. But could you provide a little bit more detail on the drivers of this both from the oilfield service cost side, whether you're using cheaper more local sand, whether you've locked in some lower-rig rates or completion contracts, and then from the operational side, whether that's just the efficiency of drilling longer laterals or just what's driving that big drop in the well cost through the year?
David L. Stover -- Chairman, President and Chief Executive Officer
Yes, I think from the efficiency standpoint, I would say less about longer laterals, more about row development and there is a pretty good slide in the deck that I didn't comment on, to point you to on slide 16, it's got an aerial photograph of, part of the field, where we'll spend a lot of time developing this year and I think you just get a sense of what, and I know you've all seen lots of pictures like this, but, when we have that much activity in a very small footprint, we're going to get very efficient. We're going to drill faster, because we're drilling near, well controlled and the completion times are going to get faster. So, that's definitely a benefit and we expect to see more of that as we go through 2019.
But we have also been very aggressive and negotiating discounts on our services with the drop in activity, which I would say is more completion weighted in the Permian in the fourth quarter last year and the drop in oil prices. And so, it's a combination of both, more efficient activity and better discounts.
Robert Morris -- Citigroup -- Analyst
Great. Thank you.
David L. Stover -- Chairman, President and Chief Executive Officer
You bet.
Operator
The next question will be from Welles Fitzpatrick of SunTrust. Please go ahead.
Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst
Good morning and congrats on the strong 2019 and 2020 guides.
David L. Stover -- Chairman, President and Chief Executive Officer
Thank you, Welles.
Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst
Obviously, you have a very, very high working interest in Mustang, but does this exclusive operatorship within the CDP, does that put you guys in the (inaudible) for consolidating further within that CDP. I mean, are you guys looking at expanding via bolt-ons there given the advantage that presumably gives you?
David L. Stover -- Chairman, President and Chief Executive Officer
I think it's a for the great question Welles and really if you look back at what we did toward the end of last year and what we've done over the last couple of years in consolidating our acreage position, some of the trades we've done up there. It's enabled us to put together this core, very contiguous high working interest position that enabled us to have the first of its kind in the state CDP for Mustang. So, I'd say most all of that's pretty much done, as you highlight, you look at the map and there's very few blanks on that map.
So, I think we're in great shape and it's enabled us to get a running start, a head start on permits. Brent highlighted, we've got over 400 permits already in place, then you think about the number of years that gives us certainty of activity up there, and it's just hugely impactful.
Brent J. Smolik -- President and Chief Operating Officer
Yes, Welles, this is Brent. I might add is that, we may not be able to add a whole lot more inside of that CDP, but we have other areas that we can look at doing similar things on a smaller scale, similar CDP on a smaller scale. I think the message is, it's just more important in today's world that we get further and further out in our planning horizons if we are going to be able to execute these programs and to your question kind of about, I don't want to signal anything about acquisitions, but if we believe that we have got the highest producing rate per lateral foot in the basin and we believe in our cost structure, compares favorably to others, then that is a formula that we want to have everywhere in our operations because then we would logically be able to consolidate.
Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst
Okay. And that makes perfect sense. And then just from a follow-up, obviously, six-year permits are pretty fantastic but how flexible are those permits, to me, if you want to go back in and maybe tweak the spacing at a lateral length, a little bit here or there, because you're learning more as you develop. Do you have to go get an entirely new permit and I understand that the easier in the CDP or can you would adjust some -- I don't want say on the fly but through a simpler process?
David L. Stover -- Chairman, President and Chief Executive Officer
We've got a small amount of latitude in that, like you suggest lateral lengths and those things, but if we move locations or significantly change it, we're going to be amending that permit, but remember with 600 of them, that's six-plus years. And so, we've got enough flexibility in there, because of the scale to be able to adjust activity.
Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst
That's great, thank you so much.
Operator
The next question will be from Phillip Jungwirth of BMO. Please go ahead.
Phillip Jungwirth -- BMO Capital Markets -- Analyst
Thanks, good morning.
David L. Stover -- Chairman, President and Chief Executive Officer
Good morning.
Phillip Jungwirth -- BMO Capital Markets -- Analyst
I was hoping to better understand the capital spending trajectory throughout the year. It looks like guidance suggests roughly 30% of the budget would be spent in the first quarter and was really hoping to drill down on this for US onshore and better understand where we'd exit the year out and maybe just some color around what drives the deceleration in spend, in terms of, rigs, completions (inaudible), or operational efficiencies?
David L. Stover -- Chairman, President and Chief Executive Officer
Let me start a minute, Phillip, on. I think what Brent highlighted was about 60% of our overall spend first half of the year, you got two components, you got Leviathan that will start to trickle off as we move through the year. So it's probably a little more first-half weighted and then you got our onshore program, which by design is set up to have a little heavier spend in the first half of the year to get a set up as Brent mentioned, not only in the Permian but in the DJ for new infrastructure coming on toward mid-year. You've got new plants coming on in the DJ by mid-year and you've got the pipeline infrastructure in the Permian. So what we want to do is be positioned, that we can bring our larger volumes on into the second half of the year and take advantage of that.
Brent J. Smolik -- President and Chief Operating Officer
Yes, a little more color, Philip, the DJ, I would say is the most ratable across the period -- across the four periods. Eagle Ford because we're only doing the DUCs will be largely finished in the first half of the year, so that causes a little bit of the front-end loading, and then, Permian, we'll start out at the current activity levels and the lowest CapEx period will be the fourth quarter, give you a little sense of how we're looking at it today, but remember we got lots of flexibility to move capital around.
Phillip Jungwirth -- BMO Capital Markets -- Analyst
Great. And then also on Slide 15, where you highlight the improved initial rates in the Wolfcamp in the second half, was just hoping to better understand that the key drivers here whether it be just where the wells are drilled, completion design, I know, you had tested some pretty high proppant concentrations in the past, inter-lateral spacing, and that whether these second half rates are more representative of what you would expect on a go forward basis as you move to row development?
David L. Stover -- Chairman, President and Chief Executive Officer
Yes. The couple of things that we highlighted there that we've caused better benefits in the second half, as we move more to the northern part of our core acreage block, Wolfcamp A is better there, Bone Spring better there, and we've had good results. We haven't yet seen row development results because those wells will just start to come on at the end of the first quarter and then primarily second quarter of this year. But we're still optimistic because we've seen a couple of places where we've drilled sections, not drilled rows, but at least sections up pretty densely and we've had good results there, which says that that's a better way to go about completing them, then coming back in later and having between well interference. So I think the geography matters and then how we're developing and completing it matters. I don't think it's the size of the proppant, the total amount of proppant per stage, I think if anything that may go down as we work out between well interference, we may pump less proppant, less fluid and if that's -- in that case we would be more efficient, because it would be lower well cost.
Brent J. Smolik -- President and Chief Operating Officer
I'd say the other thing just to add to that is the team did a great job of focusing on the base production to minimizing decline and really starting to see some of the advantages of some of the cost we had spent on putting in some additional power generation, some of the things to provide more reliability and uptime, if you will, in the overall operations and that really provided a whole new level of consistency in the second half of the year.
Kenneth M. Fisher -- Executive Vice President and Chief Financial Officer
You can clearly see that in Q4. Dave's point is if you look at the fewer TILs that we had in there yet, we were still growing production. That was the combination of good new wells and good base optimization.
Phillip Jungwirth -- BMO Capital Markets -- Analyst
Great, thanks.
Operator
The next question will be from Charles Meade of Johnson Rice. Please go ahead.
Charles Meade -- Johnson Rice -- Analyst
Good morning to you and Brent and the rest of your team there.
David L. Stover -- Chairman, President and Chief Executive Officer
Hi, Charles.
Charles Meade -- Johnson Rice -- Analyst
In your prepared comments, you talked about implementing a capital efficiency metric in your incentive compensation structure. How do you measure that?
David L. Stover -- Chairman, President and Chief Executive Officer
That's actually pretty simple. We look at what we laid out in the budget for, if you will the denominator, new production coming on this year and then timed out monthly on that. And in the numerator, it's the -- our capital that we're spending. So it's actually pretty simple that we can track monthly on a regular basis and see how we're doing and what it does, it puts the emphasis on how we're allocating capital, how are timing things coming on, new production coming on, are they staying on target or staying on track, can we accelerate anything and then making sure we're keeping the focus on the total cost of what we're spending.
Charles Meade -- Johnson Rice -- Analyst
Got it. So, is that kind of a, just, it's an amalgamation function both the CapEx, production growth and timing? Is that the right way to think about it?
David L. Stover -- Chairman, President and Chief Executive Officer
Yes, I mean, we lay it out as an expectation going into the year of what we expect to bring on and how much we expect to spend every month and then we're just tracking that, are we on target, are we are doing better, we're doing worse, that gives us early insight into do we need to adjust anything and let's everybody through the whole organization have clear visibility to how we're doing at any point in time.
Charles Meade -- Johnson Rice -- Analyst
That's great detail Dave. And then, Brian, if I could ask you or perhaps you Dave is, I saw that video on your website about the jacket going in the water and you guys have a little Gantt (ph) chart in your presentation, but I wonder if you can elaborate a little bit more on what are the milestones that you guys are -- can be focused on over the course of 2019 as we get close to Leviathan commission? I am guessing, one big piece is with the production that goes in place, but are there other pieces that we can look for?
David L. Stover -- Chairman, President and Chief Executive Officer
I mean that's going to be the biggest piece is getting the rest of the platform if you will, over there, or set it in place and everything hooked up and function tested -- final function test. One of the things that's really benefited us, and we had this learnings early in our big major projects, whether it was West Africa or Gulf of Mexico or Tamar, was to be function testing each module as it was put together and then as we put things up together, we would continue to function test as we go. So we're not waiting till the end. We're function testing as we go, less surprises, more bugs worked out early and that created the reliability that we've seen from those projects.
Charles Meade -- Johnson Rice -- Analyst
That's great detail. Thanks a lot Dave.
David L. Stover -- Chairman, President and Chief Executive Officer
Thank you, Charles.
Operator
The next question will be from Jeanine Wai of Barclays. Please go ahead.
Jeanine Wai -- Barclays -- Analyst
Hi, good morning everyone.
David L. Stover -- Chairman, President and Chief Executive Officer
Good morning Jeanine.
Jeanine Wai -- Barclays -- Analyst
Good morning. My question is on the updated 2020 outlook, I guess the early look generates about $500 million of free cash flow at strip (ph) pricing, which I think is around $58 for 2020 these days. And so, just so that we can do an apples-to-apples comparison of the prior estimate that you have, which I think was $750 million of free cash flow (inaudible), do you have what your ballpark cash flow sensitivity for every dollar of WTI is so that we can try to do the math?
David L. Stover -- Chairman, President and Chief Executive Officer
Even though I have it right here with me Jeanine, but I'll tell you what we actually looked at was, that $500 million was actually set up closer to a $55 price though it's not at a strip price of $58 now. I would say probably at least $300 million or more for every $5 of price increase, we will see how it plays out, but just a ballpark. And I think when you compare it back before, the other thing we've talked about here is that, we've already taken into account, the additional major project development and exploration this time, which is a little different than the way we talked about it previously.
Jeanine Wai -- Barclays -- Analyst
Okay. So it sounds like kind --.
David L. Stover -- Chairman, President and Chief Executive Officer
This is over and above that.
Jeanine Wai -- Barclays -- Analyst
Okay. So in terms of the primary factors that are driving the delta between the prior cash flow -- free cash flow estimate and the one now, so some of it is exploration, but is it primarily due to maybe cost or operational efficiency, activity pace or otherwise or just kind of square the two numbers?
David L. Stover -- Chairman, President and Chief Executive Officer
I think it's just resetting everything for the world we're in now, taking into account all the environmental factors we've seen over the last year and then setting up the program. So that one in 2020, we have our focus on onshore cash flow generation. That's been a key focus. And secondly, so that we're returning the cash flow from Leviathan to investors and that matches up pretty well with that $500 million or greater as you said in the current strip price world.
Jeanine Wai -- Barclays -- Analyst
Okay, great, thank you very much.
Operator
The next question will be from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer -- Goldman Sachs -- Analyst
Thank you, good morning.
David L. Stover -- Chairman, President and Chief Executive Officer
Good morning, Brian.
Brian Singer -- Goldman Sachs -- Analyst
Wanted to start with the Leviathan ramp that you see happening in 2020, you've highlighted 900 million a day of gross volume under contract you plan to increase that to 1 Bcf a day and I believe the nameplate capacity is even higher. Can you talk about the assumption I think that you made about 800 million a day of volume online or gross volumes in 2020 and the risk-reward around that?
David L. Stover -- Chairman, President and Chief Executive Officer
Yes Brian, I mean, you're exactly right. We haven't changed our assumption that is in our base plan from the 800. The expectation is, as you've said, we will have more than that under contract, but some of that may not start up until a little bit later in 2020 or into 2021 so forth so. At this point from our line of sight, we're going to stick with the 800 and we will play that out. I'd say the demand over there is still extremely strong. So to your point, we have additional capacity, our first emphasis in the area is going to be continued to fill up that additional capacity, whether it's due. We've talked about in the past, maybe firmly contracting up to 1 Bcf a day, but we have capacity up to 1.2 Bcf a day and we've seen how at Tamar that's rapidly filled up kind of build it and they will come and we know in all three markets whether it's Egypt, Israel and Jordan, they're all looking for more gas. So, at this point, we'll stay with the 800 for 2020 and we'll see how it plays out as we get the project on.
Brian Singer -- Goldman Sachs -- Analyst
Would you have the capability of producing more or 800 is what you actually think you would have the capability of producing. So, in other words, is the constraint to the 800 a demand constraint effectively or is it more of a supply constraint?
David L. Stover -- Chairman, President and Chief Executive Officer
It is not a constraint. It is a demand and timing assumption. There is not a well or facility constraint there.
Brian Singer -- Goldman Sachs -- Analyst
Great, thanks. And then separately, if we look at that long-term guidance that $0.5 billion of free cash flow or return to shareholders in 2020 plus, if you decide to move forward with major project expansions in excess of $200 million to $300 million a year and I'm not actually sure if that's even a consideration of yours or if you move forward with any consolidation since Brent brought that up, how would that impact the plan if at all to return $0.5 billion of free cash flow plus to shareholders in 2020?
David L. Stover -- Chairman, President and Chief Executive Officer
Well, I think the fundamental piece of the plan is the return of that $500 million to shareholders and we're staying grounded in that. I think other things we can adjust and cover as we need to cover them, but we're staying grounded and committed to that -- returning that $500 million to shareholders.
Brian Singer -- Goldman Sachs -- Analyst
Great, thank you.
Operator
The next question will be from Ryan Todd of Simmons Energy. Please go ahead.
Ryan Todd -- Simmons Energy -- Analyst
Thanks. Maybe a follow-up on the last one, I mean your commentary on 2020 plus, it's hard to tell if that -- it's just some sort of spend or bucket for major project capital there, does that suggest that we could see progress and potential FID of another Eastern Med project by 2020? And if so, what sort of milestones need to be cleared between now and then to feel comfortable moving forward?
David L. Stover -- Chairman, President and Chief Executive Officer
We could. I mean, there is definitely the inventory of high quality projects and that'll be dependent on how the marketing plays out. As I mentioned earlier, the first phase, the marketing, filling up and fully utilizing the existing infrastructure in place at Leviathan, I know Keith and his team continue to look at how we look at modular's and different components of capital efficient expansion as we go forward from there. I think that $200 million to $300 million in there, that we kind of highlighted for exploration and major project additions will cover what we need the next couple of years and then we'll look at the timing beyond that, how some of these things come together, but don't forget, we've got other ways and -- that we've talked about how to fund this, different expansions and so forth. We've also talked about over time, we may decide to monetize the portion of Leviathan to help fund some of the additional expansions overtime too, so we got a lot of levers to pull. The great part is, we have got a lot of opportunity, a lot of high return, high value opportunity.
Brent J. Smolik -- President and Chief Operating Officer
The other thing to keep in mind is that earlier question that was talking about the profile of Leviathan. We could see increasing production profile in Leviathan with no incremental cost over the next couple of years, that's not modeled, right. So it's sort of negative decline if you want to think about it that way. So it's a real huge advantage as we think about certainty around future cash flow and return to shareholders in 2020 and beyond.
Ryan Todd -- Simmons Energy -- Analyst
Great, thanks. And then maybe you mentioned a target of $500 million to $1 billion of portfolio proceeds this year to support the balance sheet. What type of asset should we be looking at?
David L. Stover -- Chairman, President and Chief Executive Officer
Yes, without getting into specific assets, they'd be non-core assets, we've continually and always look at the portfolio. I'd say we've probably got 15% to 20% of that done already, this year. So I'm confident we will have the things that makes sense, either from the standpoint that they're worth more to somebody else because of the way they look at it or that -- it's an opportunity to highlight value that isn't highlighted and recognized in the company at this point. So, those are the things we'll continue to look at. But it's just part of the ongoing portfolio management.
Ryan Todd -- Simmons Energy -- Analyst
Thanks, Dave.
Operator
The next question will be from David Deckelbaum of Cowen. Please go ahead.
David Deckelbaum -- Cowen -- Analyst
Good morning, Dave. And thanks for taking my questions.
David L. Stover -- Chairman, President and Chief Executive Officer
Hey David.
David Deckelbaum -- Cowen -- Analyst
I wanted to clarify the point just as you're thinking about long-term development philosophically, you targeted the $500 million of free cash at the corporate level, in '20 and we're going to turn all of that to shareholders. You talked about sort of future exploration projects. I guess, beyond that is, now should we think about the construct with a $50 to $55 world that we wouldn't be developing the onshore program necessarily faster, and that we would see a 100% of excess free cash return to shareholders overtime?
David L. Stover -- Chairman, President and Chief Executive Officer
I think what we've tried to lay out here is kind of a pace for the onshore program that shows that moderate growth. And then it's supplemented by specific major project additions as they come on, I mean, we're seeing that in 2020. When you look at the impact of the Leviathan coming on, on top of our underlying profile from the onshore development and that's just what we think the prudent way to manage the business in a $50 to $55 world.
David Deckelbaum -- Cowen -- Analyst
I appreciate that. And then just my follow-up was, you talked about funding potential of Eastern Med projects, how do you guys think about managing that from just a CapEx perspective, would you be looking to kind of sell down assets ahead of time to fund something like that or would it come from organic sources overtime?
David L. Stover -- Chairman, President and Chief Executive Officer
I think, if we sold down some interest, it would be just like we did with Tamar where we have to set a great value marketer. And I don't think that probably will happen before the projects come online, like the Leviathan. So, I don't think there's any rush to do anything like that. And we'll just play that out over time. I tell you the -- with Leviathan being this close to coming on production, it's getting a lot more attention in the world, it's very noticeable. And I think that cash flow stream will be very, very noticeable here by the end of the year or so. So we will just play that out and see how things match up from valuation and timing of capital needs as we move forward.
David Deckelbaum -- Cowen -- Analyst
Noted. I appreciate the color. And good luck with first sales.
David L. Stover -- Chairman, President and Chief Executive Officer
Thank you, Dave.
Operator
The next question will be from Paul Grigel of Macquarie. Please go ahead.
Paul Grigel -- Macquarie Capital -- Analyst
Hi, good morning. On Slide 10, on maintenance CapEx, a couple of clarifying items. Is that an exit-to-exit rate or a year-over-year rate on the maintenance capital spend in 2020 there?
David L. Stover -- Chairman, President and Chief Executive Officer
I think we're really thinking of it as year-over-year in this math and so we have enough capital to $1.6 billion to replace global production year-over-year average.
Paul Grigel -- Macquarie Capital -- Analyst
Okay. And then as a corollary on the corporate decline or any comment of moving into the low 20% range once Leviathan's on, is that contemplating the current program as it is with the growth in 2019 or is that just the underlying program as it exists today entering a low 20s decline rate at that point?
David L. Stover -- Chairman, President and Chief Executive Officer
I'm not sure exactly the question. Say it again, --?
Paul Grigel -- Macquarie Capital -- Analyst
Does it build in the current plan, such that in 2020 post Leviathan, you would be at a low 20% rate or is that just production as it stands today on its normal decline working through and going forward?
David L. Stover -- Chairman, President and Chief Executive Officer
That assumes '19 and '20 capital, when we talk about the changes in base decline. Yes, it -- Capital.
Brent J. Smolik -- President and Chief Operating Officer
As you've highlighted, you can see the impact, when you bring the Leviathan on and you combine that with Tamar and even lower decline in West Africa at that point as you move in from '19 into '20, you just change your whole decline picture, you change your whole maintenance capital picture and it just sets you up for, providing more certainty on the ability to generate free cash flow going forward.
Paul Grigel -- Macquarie Capital -- Analyst
Certainly an impactful change. Thank you very much.
David L. Stover -- Chairman, President and Chief Executive Officer
Thank you.
Operator
The next question will be from Gail Nicholson of Stephens. Please go ahead.
Gail Nicholson -- Stephens Inc. -- Analyst
Good morning. I was wondering if you guys can provide some more information on the Alen gas monetization, I know, (inaudible) in the first half of '19. But I was wondering if you could just talk about the scope of the project, cost of the project and then kind of what that would entail maybe from a standpoint of the pricing when it comes online in 2021?
David L. Stover -- Chairman, President and Chief Executive Officer
Hey Gail, we'll be able to provide you a lot more detail, when we reach sanctions on that as Brent mentioned, I think that the target is to finish the ongoing negotiations and get that to a sanction by midyear. So, probably wait for some of that detail to lend, what I will say is, Alen is about 600 Bcf growth, we will be able to bring on two to three wells that will be able to deliver, I think, plus or minus 300 million a day. So that gives you a little bit of context and really the cost from facility modifications and a pipeline to shore and that's really what you have to do to hook it up.
Gail Nicholson -- Stephens Inc. -- Analyst
Great. And then just speaking on West Africa, I was doing the incremental, bringing the incremental well online at saying this year. Is there more opportunity to do that in the future to further mitigate decline in 2020 forward?
Kenneth M. Fisher -- Executive Vice President and Chief Financial Officer
Yes, we don't have many of the current plans that we've been rolling out for you, but there's, as Dave mentioned, there's a lot of gas there.
Gail Nicholson -- Stephens Inc. -- Analyst
Okay, great. Thank you.
Operator
The next question will be from Tim Rezvan of Oppenheimer. Please go ahead.
Tim Rezvan -- Oppenheimer -- Analyst
Hi, good morning folks. You've given a lot of color on the progress toward first production at Leviathan, but my question is on how you see pricing overall for Israeli gas, Israeli Electric has been in the press, talking about lower prices for Tamar and new production at Karish and Tanin, if there is pricing, closer to $4 a dekatherm announced for those projects. So how should we think about Israeli pricing in 2020 and beyond given these dynamics?
David L. Stover -- Chairman, President and Chief Executive Officer
Yes. Thanks, Tim. I don't think our outlook really changed. I think we still have a strong pricing outlook, whether it's in Israel or on some of the regional markets, we've got a base position with IEC, I know they've come out and talked about some things recently on trying to provide some more room, but essentially for us what it does is enable us to free up some volumes that we can tie into some longer-term contracts in Israel. So, I don't see that as a negative at all. I think it's the opportunity as we see even with some of these other projects coming on, as you look at the coal conversion in Israel, you look at just some of the movement to some of the other incentives they've put in place, you look at the demand in Jordan, you look at demand in Egypt and I think the pricing outlook we have for what we've laid out is very realistic as we go forward.
Tim Rezvan -- Oppenheimer -- Analyst
Okay and then just as a follow-up on that. With Karish and Tanin coming online, is there any concern about losing some of your Tamar customers to that new lower priced gas?
David L. Stover -- Chairman, President and Chief Executive Officer
No, not really. I think there's going to be room for everybody. In fact that was part of the framework, was to make sure that there was multiple sources of gas in the country and they're going to need all those. So I think that gets back to that demand outlook and what the need is going to be in the country and what we can supply and supply both in country and on a regional basis, then that regional demand outlook is pretty astounding when you look at it and it's playing out as you've seen things develop, as we've been involved in the discussions with everyone, there is no backing off of wanting Leviathan or Tamar gas. I can tell you that.
Tim Rezvan -- Oppenheimer -- Analyst
I appreciate the comments. Thank you.
Operator
And the final question this morning will be from Michael Hall of Heikkinen Energy. Please go ahead.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Thanks. Appreciate the time. Well done on the quarter. Just curious on the Delaware program in 2018 and I apologize if I missed any of this, my phone dropped, but can you just talk a little bit more about kind of what you learned with the 2018 Delaware program and then how you're approaching that as it relates to spacing and development configurations going forward, particularly in the context of kind of parent child relationships and what you've seen on that front?
David L. Stover -- Chairman, President and Chief Executive Officer
Yes, Michael, I think we learned a lot in 2018. I think, Brent had a lot of that in his prepared comments, but we knew going into the year, we wanted to test some of the acreage we have designated as maybe a little lower quality down to the Southwest, because there were some lease expirations coming up over the next few years there. So it behooved us to understand that as well as we could as quick as we could. We did that, we saw some of that, we also tested some more as you will of the parent child type understanding and as we got some of that knowledge and learned more about that, it helped solidify our thought process of moving to row development and that's why we moved to row development to set ourselves up, so we can mitigate those factors going forward.
I think that positions us well as we go forward, Brent talked about you know and also has highlighted how we focus where our activity is, we saw some of the benefits of that in the fourth quarter results that Brent highlighted. So when you look at the acreage as a whole, it is very high quality acreage. I think that's borne out by the one slide that shows over the two year period how well that acreage has performed even relative to others in that area. So, very confident of the reservoir quality and marry that up here with some operational adjustments that to the row development and so forth and actually some of the results we saw in the second half of the year and I think that bodes well for that program going forward. Brent, do you want to add anything?
Brent J. Smolik -- President and Chief Operating Officer
And I think that you covered it well, David, just if we continue to see the results that we're expecting as these row development wells come on, it only motivates us to want to block up that acreage even more.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay and what specific spacing configurations are you guys developing those rows on?
David L. Stover -- Chairman, President and Chief Executive Officer
I think we are still on the scenario of about six wells in the upper Wolfcamp A and then six toward the lower Wolfcamp and then where applicable three to four Bone Springs wells, Third Bone Springs wells, and I don't think that's changed from the way we talked about at the last half of last year.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay, that's helpful. And then as it relates to the returns of capital to shareholders, any kind of early thoughts on, I guess, preferred means in terms of dividends versus buybacks or special dividends?
David L. Stover -- Chairman, President and Chief Executive Officer
We look at both. We will look to balance the both, I mean, if you look in 2018, it was pretty close, we had a little over $200 million in dividends and close to $300 million in buyback. I mean that may change in any one year going forward. We've consistently talked about investors being able to count on dividend growth as cash flow growth. So that's probably first and foremost, and then we'll supplement that with buy back as we go as it makes sense.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Appreciate it. Thanks again.
David L. Stover -- Chairman, President and Chief Executive Officer
Thank you, Michael.
Operator
And ladies and gentlemen, this will conclude our question and answer session. I would like to hand the conference back over to Brad Whitmarsh for any closing remarks.
Brad Whitmarsh -- Vice President, Investor Relations
Sure. Thanks. I want to say thanks to everybody for joining us today for the call. The Investor Relations team is around and happy to talk on the phone should you have any follow-up questions. Have a great day.
Operator
Thank you, sir. Ladies and gentlemen, the conference has concluded. Thank you for attending today's presentation. You may now disconnect your lines.
Duration: 66 minutes
Call participants:
Brad Whitmarsh -- Vice President, Investor Relations
David L. Stover -- Chairman, President and Chief Executive Officer
Brent J. Smolik -- President and Chief Operating Officer
Robert Morris -- Citigroup -- Analyst
Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst
Phillip Jungwirth -- BMO Capital Markets -- Analyst
Kenneth M. Fisher -- Executive Vice President and Chief Financial Officer
Charles Meade -- Johnson Rice -- Analyst
Jeanine Wai -- Barclays -- Analyst
Brian Singer -- Goldman Sachs -- Analyst
Ryan Todd -- Simmons Energy -- Analyst
David Deckelbaum -- Cowen -- Analyst
Paul Grigel -- Macquarie Capital -- Analyst
Gail Nicholson -- Stephens Inc. -- Analyst
Tim Rezvan -- Oppenheimer -- Analyst
Michael Hall -- Heikkinen Energy Advisors -- Analyst
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