Hess - Q3 2018
October 31, 2018
Transcript
Speaker 0
Good day, ladies and gentlemen, and welcome to the Third Quarter 2018 Hess Corporation Conference Call. My name is Gigi, and I will be your operator for today. At this time, all participants are in listen only mode. Later, we will conduct a question and answer session. As a reminder, this conference is being recorded for replay purposes.
I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.
Speaker 1
Thank you. Good morning, everyone, and thank you for participating in our Q3 earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements.
These risks include those set forth in the Risk Factors section of Hess' annual and quarterly reports filed with the SEC. Also on today's conference call, we may discuss certain non GAAP financial measures. A reconciliation of the differences between these non GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Now as usual with me today are John Hess, Chief Executive Officer Greg Hill, Chief Operating Officer and John Reilly, Chief Financial Officer. I'll now turn the call over to John Hess.
Speaker 2
Thank you, Jay. Welcome to our Q3 conference call. I will provide a strategy update, Greg Hill will then discuss our operating performance and John Reilly will review our financial results. We delivered another strong quarter of execution with higher production than guidance and lower unit costs than guidance, while keeping capital and exploratory expenditures flat with guidance for the year and generating a profit for the quarter. We continue to execute our strategy to deliver capital efficient growth in our resources and production, investing in the highest return projects to move down the cost curve and be profitable in a lower price environment with increasing cash generation and returns to shareholders.
Fundamental to this strategy is our focused high return portfolio with Guyana and the Bakken as our growth engines, where we plan to invest about 75% of our capital and exploratory expenditures over the next 5 years and Malaysia and the Deepwater Gulf of Mexico as our cash engines. Pro form a for our asset sales, our high graded portfolio is on track to deliver capital efficient compound annual production growth of approximately 10% through 2023, while driving cash unit costs down approximately 30% to less than $10 per BOE over the same period. The combination of growth and margin expansion is expected to drive compound annual cash flow growth of approximately 25% through 2023 at a $60 per barrel Brent oil price. An integral part of our strategy is maintaining a strong balance sheet and liquidity position to ensure we have the financial capacity to fund our world class investment opportunity in Guyana and maintain our investment grade credit rating. Our position in Guyana is truly world class in every respect and transformational for our company.
As of June, gross discovered recoverable resources for the Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator, have grown and are estimated to be more than 4,000,000,000 barrels of oil equivalent with multibillion barrels of additional exploration potential. In late August, we announced a 9th oil discovery on the block at the Hammerhead No. 1 well located approximately 13 miles southwest of the Liza 1 well, proving a new play concept for potential development. This month, a second exploration vessel, the Noble Tom Madden, arrived to accelerate exploration and appraisal activities on the block, starting with a Pluma prospect located 17 miles south of Turbot, where we expect to spud in early November. The Liza Phase 1 development, which was sanctioned in June of last year, is well advanced with first production of gross 120,000 barrels of oil per day expected by early 2020.
Phase 2 development with gross production of 220,000 barrels of oil per day is on track for start up by mid-twenty 22. A third phase of development at the Payara field is expected to have a gross production capacity of approximately 180,000 barrels of oil per day with first production in 2023. We now see the potential to produce on a gross basis more than 750,000 barrels of oil per day by 2025 with industry leading returns and cost metrics. Also key to our strategy is the Bakken, where we have a premier acreage position and a robust inventory of high return drilling locations with a significant infrastructure advantage. During the quarter, we continued testing limited entry plug and perf completions and higher proppant loadings and initial results are encouraging.
In September, we added a 6th rig and we expect to generate capital efficient production growth of 15% to 20% per year through 2021, along with a meaningful increase in free cash flow generation over this period. Now turning to our financial results. In the Q3, we had net income of $52,000,000 or $0.14 per share compared to a net loss of $624,000,000 or $2.02 per share in the year ago quarter. On an adjusted basis, net income was $123,000,000 or $0.38 per common share compared with an adjusted net loss of $324,000,000 or $1.07 per common share in the Q3 of 2017. Compared to 2017, our improved 3rd quarter financial results primarily reflect higher realized crude oil selling prices combined with lower operating costs and DD and A expense.
We had a strong operating performance across our portfolio. 3rd quarter production was above the high end of our guidance range, averaging 279,000 net barrels of oil equivalent per day, excluding Libya. Net production from Libya was 18,000 barrels of oil equivalent per day in the quarter. For full year 2018, we expect production to average approximately 255,000 net barrels of oil equivalent per day, excluding Libya, at the top end of our previous guidance of 245,000 to 255,000 net barrels of oil equivalent per day. In the Q4, production is expected to average approximately 265,000 net barrels of oil equivalent per day, excluding Libya.
3rd quarter net production in the Bakken averaged 118,000 barrels of oil equivalent per day compared to 103,000 barrels of oil equivalent per day in the year ago quarter.
Speaker 3
For the full year
Speaker 2
2018, we continue to forecast that Bakken net production will average between 115,000 120,000 barrels of oil equivalent per day. In summary, our ReShape portfolio is positioned to deliver a decade plus of capital efficient production Day on Wednesday, December 12 in Houston. I will now turn the call over to Greg for an operational update.
Speaker 3
Thanks, John. I'd like to provide an update of our operational performance for the quarter as we continue to execute our strategy. In the Q3, company wide production averaged 279,000 net barrels of oil equivalent per day, excluding Libya. This was nearly 10% above the midpoint of our guidance range of 250,000 to 260,000 net barrels of oil equivalent per day for the quarter and reflects strong performance across our portfolio. In the Bakken, production averaged 118,000 net barrels of oil equivalent per day, in line with our guidance for the quarter, and we drilled 34 wells and brought 29 new wells online.
Consistent with previous guidance, we added a 6 Bakken rig and a 3rd frac spread in the 3rd quarter. For the Q4, we forecast Bakken net production will increase to approximately 125,000 net barrels of oil equivalent per day and we expect to drill approximately 35 wells and bring 31 wells online, bringing the total for full year 2018 to 120 wells drilled and 100 new wells brought online. Average IP 180 for the year, which will be dominated by our 60 stage sliding sleeve completion design, is expected to exceed 125,000 barrels of oil, an increase of approximately 15% from full year 2017. We are also seeing encouraging results from our transition to limited entry plug and perf completions. Of the 100 gross operated wells we now expect to bring online this year, approximately 30 are planned to be plug and perf.
We will provide further details regarding these new high intensity completions at our Investor Day in December. On August 31, we closed on the sale of our JV interest in the Utica Shale Plate to Ascent Resources for approximately $400,000,000 As a result of the sale, 4th quarter net production will be reduced by approximately 10,000 net barrels of oil equivalent per day relative to the Q3. Turning to the Gulf of Mexico, Net production came in well above guidance at 71,000 net barrels of oil equivalent per day, reflecting the return of production from Conger field in July, minimal weather related downtime and strong operating performance across all assets. As a result, we are raising our full year guidance to approximately 55,000 net barrels of oil equivalent per day. For the Q4, we forecast Gulf of Mexico production to average approximately 65,000 net barrels of oil equivalent per day, which includes 6,000 net barrels of oil equivalent per day of planned downtime, primarily associated with an inspection of 1 of the risers at the counter field.
Now moving to the Gulf of Thailand. Production from our Asian assets averaged 68,000 net barrels of oil equivalent per day during the Q3. At the joint development area in which Hess has a 50% interest, production averaged 37,000 net barrels of oil equivalent per day in the 3rd quarter. Production is forecast to average approximately 36,000 net barrels of oil equivalent per day over the full year 2018. At the North Malay Basin, where Hess holds a 50% interest and its operator, production averaged 31,000 net barrels of oil equivalent per day in the 3rd quarter, which came in higher than expected due to a one time rebalancing of entitlement volumes.
Production is forecast to average approximately 26,000 net barrels of oil equivalent per day in 2018. Company wide, we forecast 4th quarter production to be approximately 265,000 net barrels of oil equivalent per day excluding Libya. Strong year to date performance across our portfolio enables us to raise our full year guidance to approximately 255,000 net barrels of oil equivalent per day, which is at the upper end of our previous guidance range of 245,000 to 255,000 net barrels of oil equivalent per day despite the loss of volumes associated with the sale of our Utica assets. Now turning to exploration. In August, we announced our night discovery Hammerhead on the Stabroek Block offshore Guyana in which Hess holds a 30% interest and ExxonMobil is the operator.
The well, which is located about 13 miles Southwest of the Liza-one discovery well, encountered 197 feet of high quality, oil bearing, Miocene age sandstone reservoir, opening up a new plate type. We recently completed a successful flow test and further appraisal activities are planned. The Stena Carron rig will now go to Las Palmas in the Canary Islands in Spain for recertification and is expected return to the block in late December when we plan to spud a well on the Upper Cretaceous Amara prospect located 24 miles southeast of the Turbot discovery. A second exploration vessel, the Noble Tom Madden drillship has arrived in theater and is scheduled to spud a well on the Pluma prospect in early November. The well location is approximately 16 miles south of Turbot and will also target upper Cretaceous reservoirs on trend with the Turbot and long tail discoveries.
In Suriname, Kosmos announced earlier this month that the Pontineau well on Block 42 in which Hess has a 1 third interest failed to encounter commercial hydrocarbons and the well was expensed in the Q3. The partners are studying the results of the well and will reprocess seismic to improve our understanding of the subsurface and regional geology. We continue to see multiple additional large prospects on the block, which are independent from targeting a large subsalt structure analogous to those found in the Gulf of Mexico. Moving to Guyana developments. Liza Phase 1, sanctioned in June 2017, remains on track for first oil by 2020 with a nameplate capacity of 120,000 barrels of oil per day.
Liza Phase 2 is also on track for 1st oil by mid-twenty 22 with a nameplate capacity of 220,000 barrels of oil per day. And finally, Phase 3 is currently in feed with first oil expected in 2023. The operator is focused on maximizing value through rapid phase developments and accelerated exploration plans. In closing, we have once again demonstrated strong execution and delivery and we are well positioned to deliver significant value to our shareholders. I will now turn the call over to John Reilly.
Thanks, Greg.
Speaker 4
In my remarks today, I will compare results from the Q3 of 2018 to the Q2 of 2018. For the Q3 of 2018, we had net income of $52,000,000 compared with a net loss of $130,000,000 in the Q2 of 2018. On an adjusted basis, which excludes items affecting comparability of earnings between periods, we had net income of $123,000,000 in the Q3 of 2018 compared with a net loss of $56,000,000 in the previous quarter. Turning to E and P. On an adjusted basis, E and P net income was $203,000,000 in the Q3 of 2018 compared to $21,000,000 in the Q2 of 2018.
The changes in the after tax components of adjusted E and P earnings between the Q3 and Q2 of 2018 were as follows: higher sales volumes increased earnings by $146,000,000 higher realized selling prices increased earnings by $65,000,000 Lower cash costs increased earnings by 12,000,000 Higher DD and A expense reduced earnings by $39,000,000 Higher exploration expense reduced earnings by $13,000,000 All other items increased earnings by $11,000,000 for an overall increase in 3rd quarter earnings of $182,000,000 Turning to Midstream. The Midstream segment had net income of $30,000,000 in both the 3rd Q2 of 2018. Midstream EBITDA before the non controlling interest amounted to $130,000,000 in the 3rd quarter compared to $126,000,000 in the previous quarter. For corporate, after tax corporate and interest expenses were $122,000,000 in the Q3 of 2018 compared to $191,000,000 in the Q2 of 2018. After tax adjusted corporate and interest expenses were $110,000,000 in the Q3 of 2018 compared to $107,000,000 in the previous quarter.
Turning to our financial position. Excluding Midstream, cash and cash equivalents were $2,600,000,000 total liquidity was $7,000,000,000 including available committed credit facilities and debt was $5,700,000,000 at September 30, 2018. Cash flow from operations before working capital changes and items affecting comparability was $738,000,000 in the 3rd quarter, while cash expenditures for capital and investments were $566,000,000 in the quarter. Changes in working capital reduced cash flows from operating activities by $258,000,000 in the 3rd quarter, reflecting premiums paid of $105,000,000 on WTI crude oil hedging contracts for calendar 2019 and a payment of $84,000,000 related to previously accrued legal claims associated with our former downstream interests. For calendar 2019, we have purchased WTI put options with a notional amount of 95,000 barrels of oil per day that have a monthly floor price of $60 per barrel.
In the Q3, we completed the sale of our joint venture interest in the Utica Shale play for net cash consideration of approximately $400,000,000 We also entered into a sale and leaseback agreement for a floating storage and offloading vessel to handle produced condensate at our North Malay Basin project and received net proceeds of approximately 100 and $30,000,000 The gross lease obligation is reported as debt on our balance sheet and we will recover our partner share through future joint interest billings over the lease term. In the Q3, we purchased $250,000,000 of common stock, bringing total share repurchases under our previously announced $1,500,000,000 stock repurchase program to $1,250,000,000 We plan to purchase the remaining $250,000,000 in the 4th quarter. Now turning to guidance for E and P. In the Q3, our E and P cash costs were $11.41 per barrel of oil equivalent, including Libya and $11.87 per barrel of oil equivalent, excluding Libya, which beat guidance on strong production and lower costs. On a pro form a basis, excluding Libya and Utica, which was sold in August, cash costs in the 3rd quarter were 12 point point $2.0 per barrel of oil equivalent.
We project cash costs for E and P operations, excluding Libya, in the 4th quarter to be in the range of 12 point $5.0 to $13.50 per barrel of oil equivalent, which includes planned maintenance costs at the Conger field in the Gulf of Mexico. Full year 2018 cash costs are expected to be $12.50 to $13.50 per barrel of oil equivalent, which is down from previous guidance of $13 to $14 per barrel of oil equivalent. DD and A expense in the 3rd quarter was $16.14 per barrel of oil equivalent, including Libya and $17.03 per barrel of oil equivalent, excluding Libya, which was below guidance. On a pro form a basis, excluding Libya and Utica, unit DD and A rates in the 3rd quarter were $17.68 per barrel of oil equivalent. DD and A expense excluding Libya is forecast to be in the range of $18 to $19 per barrel of oil equivalent in the Q4 of 2018 and full year DD and A expense is projected to be $17 to $18 per barrel of oil equivalent, which is down from previous guidance of $18 to $19 per barrel of oil equivalent.
This results in projected total E and P unit operating costs, excluding Libya, of $30.50 to 32 point $5.0 per barrel of oil equivalent for the 4th quarter and $29.50 to 31.50 for the full year of 2018. Exploration expenses excluding dry hole costs are expected to be in the range of $55,000,000 to $65,000,000 in the Q4 with full year guidance expected to be in the range of $190,000,000 to $200,000,000 which is in the lower end of our previous guidance. The midstream tariff is projected to be approximately $170,000,000 for the 4th quarter and approximately $655,000,000 for the full year of 2018, which is up from previous guidance of approximately $635,000,000 to $650,000,000 The E and P effective tax rate, excluding Libya, is expected to be a benefit in the range of 0% to 4% for the 4th quarter. The full year effective tax rate is expected to be a benefit in the range of 7% to 11%, which is updated from the previous guidance of a benefit in the range of 16% to 20%. For full year 2018, our E and P capital and exploratory expenditures guidance remains unchanged at $2,100,000,000 Our 2018 crude oil hedge positions remain unchanged.
We have $50 WTI put option contracts on a notional 115,000 barrels per day for the remainder of the year. We expect amortization of the premiums on these hedge contracts will reduce our financial results by approximately $50,000,000 in the 4th quarter. For calendar 2019, we have purchased $60 WTI put option contracts with a notional amount of 95,000 barrels of oil per day for $116,000,000 We expect amortization of the calendar 2019 option premiums will reduce our financial results by approximately $29,000,000 per quarter in 2019. For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be approximately $30,000,000 in the Q4 with the full year guidance of approximately $115,000,000 remaining unchanged. For corporate, for the Q4 of 2018, corporate expenses are estimated to be in the range of $25,000,000 to $30,000,000 and for the full year guidance to be in the range of $100,000,000 to $105,000,000 which is in the lower end of our previous guidance.
Interest expenses are estimated to be approximately $85,000,000 in the 4th quarter and approximately $340,000,000 for the full year of 2018, which is also at the low end of our previous guidance. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.
Speaker 0
Your first question comes from the line of Bob Morris from Citigroup. Your line is now open.
Speaker 5
Thank you. Nice quarter, John.
Speaker 2
Thank you.
Speaker 5
Greg, on the Bakken, you've got 35 wells still to drill here in the Q4. It looks like you've added 5 plug and perf wells to the slate. Where are those wells spread out between the 4 different areas in Q4? And where are you primarily drilling the plug and perf wells between Keene, Stoney Creek, East Nesson and Capa?
Speaker 3
Well, they're actually spread out in a number of areas across the field. I don't have the actual well numbers in front of me, but it's really spread out over our whole position.
Speaker 5
Okay. I didn't know if there was one area that sort of was left for the year end. So in the 6th rig that you just added, where was that put, what area?
Speaker 3
That was put in the core.
Speaker 5
In Keene or Stoney Creek?
Speaker 3
No, it was put in East Nesson.
Speaker 5
East Nesson. Okay. And then I was going to ask about the continued outperformance at Stoney Creek in Keene, but I guess you'll give us an update on all that here in December?
Speaker 3
I will, absolutely, in Investor Day.
Speaker 5
Okay, great. That's all I had for now. Thanks.
Speaker 0
Thank you. Your next question is from Doug Leggate from Bank of America. Your line is now open.
Speaker 6
Thanks. Good morning. I wonder if I could take a couple of questions on exploration in Guyana to start off. Greg, I realize that Guyana is probably going to be a focus on December 12, but I just wonder if you could touch on the visibility you have today. I want to reflect on comments you made back in August about potentially fast tracking Hammerhead.
That's not in the 750 or the more than 750 is our standard. And similarly, the latest thoughts on the scale of PayaraLiza 3? And I've got a follow-up, please.
Speaker 3
Okay, Doug. Well, first of all, Hammerhead, we just completed it at BST. Couple of comments on Hammerhead to start. This is a massive accumulation, a very thick sand package. In fact, it's the thickest single sand package that we drilled on the block.
It's a very large structure, so it's going to require some additional appraisal. What we can say is that the results of the DST were good, meaning that the reservoir quality is excellent and the reservoir seems to be well connected. You're right to say that that will be hammerheads accretive to the 4,000,000,000 barrels And it could jump the queue in some of the other in terms of being ahead of some of the other phases that were on the turbot cluster, but it's too early to say that because we need some additional appraisal before we make that final decision. But again, it is accretive to the 4,000,000,000 barrels. On the Payara cluster, as you mentioned, we're in feed.
Right now, the vessel is sized at 180,000 barrels a day, but that's still under discussion and will be part of the final project sanction in towards the end of 2019.
Speaker 6
Great. Thank you for that, Greg. My follow-up on Guyana, if I may, is the exploration program, you mentioned the Armada prospect. I just want to be clear, is that did that have another name? Was that Escalade or is that something different?
And if you could just give us an idea of where Ranger now fits in the queue, because my understanding was then I was going to go back to a Ranger appraisal at some point.
Speaker 3
Yes, Doug, you have a great memory. Amarra is Escalar, used to be called Escalar. Regarding the sequence of expiration and appraisal next year, That's still under discussion with the operator. We'll let you know once we get our budget finalized in 2019. But Ranger will be one of the things in the Q in 2019 obviously.
But we've got some Hammerhead appraisal we want to do. There's some more work that we want to do in the Turbot area. So all that sequence is still being worked out.
Speaker 6
Last one for me, if I may, guys, is for the 2 Johns. And John Hess, I realize you've made your thoughts on share buybacks quite clear. But I guess I'm looking at the strength of the cash flow this quarter, the underlying cash flow, the demonstrable part of the portfolio obviously in this environment is pretty punchy. What's the right level of cash carry on the balance sheet? And what's at the back of my mind really is, you've got your preference issue maturing next year.
I'm just wondering if there's a potential offsetting buyback that could revert dilute that or offset that dilution we're going to see next year? And I'll leave it there. Thanks.
Speaker 2
Yes. Doug, as you know, we are currently purchasing our stock under our current program. We constantly assess our allocation of capital. And as you know, we have been a leader among our peers in return of capital. So we will continue to balance investing in our highest return projects and returning capital to shareholders.
That's our investment proposition and that's the path we've been following and we will continue to follow.
Speaker 6
Great stuff. Appreciate the answers guys. Thank you.
Speaker 0
Thank you. Your next question comes from the line of Bob Brackett from Bernstein Research. Your line is now open.
Speaker 3
Good morning. I understand you're probably not willing to talk too much about the 2019 program, but can you talk about the planning process and how you balance oil price uncertainty against the capital program and against building free cash flow?
Speaker 4
Sure, Bob. So the first thing is you heard that we were looking at, we've always looked at 2019 again is with our bridge to Guyana coming in 2020. And we know we're investing in Phase 1 and now you know we're going to be also investing in Phase 2 and others that the first thing we did, we put the 95,000 barrels a day of WTI put options in place. So watching oil volatility, we made sure we put a floor on that price for us for a good part of our production to ensure that we have that base cash flow. So we will as you said, we'll be talking a lot more about this later on in our Investor Day.
But while our budgeting process is underway, we are really excited about our capital exploratory expenditure program through 2025. We think it's distinctive kind of as John Hess talked about earlier that it will deliver capital efficient production growth that generates significant free cash flow over the period. So just to be high level, talking about the activity levels that Greg was discussing, our 2019 budget will be closer to $3,000,000,000 But it's important to note that all that incremental spend between 2018 2019 will be targeted in our view to 2 of the highest return investments in the E and P business and that's our Bakken and Guyana assets. And then just going longer term and again we'll give more detail on this, but maintaining our disciplined capital allocation, we currently expect capital and exploratory expenditures to average approximately $3,000,000,000 per year through 2025 and the portfolio to be cash generative post 2020. And I would tell you for now what we're looking at from a planning assumption cases is using a $60 WTI and a $65 Brent.
But again, we'll provide more information later on in our Investor Day in December. But again, really excited about that. Just specifically, because Greg had mentioned it, what's going on in the Bakken, it's basically an incremental spend is almost half and half between the Bakken and Guyana. So in Bakken, we're going to be operating 6 rigs. That's 30% higher rig count than 2018.
And right now, probably approximately 50% more wells online in 2019 than 2018. So the vast majority also of those wells in 2019 are expected to be the higher intensity plug and perf completions, which currently carry an incremental cost of about $1,500,000 per well versus our previous sliding sleeve design. But these wells are expected to deliver increases in both IP rates and more significantly in NPV. So it will result in our Bakken production exceeding our previous guidance of 175,000 barrels per day by 2021. Then in Guyana, we have the peak spend on Phase 1 in 2019 from our previous sanction release in 2019.
It was about an $80,000,000 increase in 2019 for Phase 1. And now you're going to see the commencement of spending for Phase 2. And remember, Phase 1, the initial year was $110,000,000 So Phase 2 is obviously bigger than Phase 1. So you're going to see a little more spending for that. As well now feed costs for FPSOs 3 and 4 most likely, and we are bringing the additional drill ship in the Noble Tom Madden for year.
So that's kind of just high level. We'll go into more detail on it. But again, from our overall program, we're going to be generating significant free cash flow over the period because of these investments in Bakken and Guyana.
Speaker 3
Great. I appreciate the color. Quick follow-up. Adding that second exploration rig to Guyana, can you talk about how many wells you can get down in 2019? And how you'd split those across exploration of brand new concepts, exploration across the proven concepts and then kind of appraisaledevelopment?
Well, Bob, obviously, it depends on what we find as we continue to explore the block. Again, that whole sequence hasn't been lined out yet with the operator, but we know that we want to do some more appraisal in Hammerhead, so there will be some more there. We know we've got some more explorationappraisal around Turbot. We know that we've got appraisal at Ranger. We know that we're going to drill this Haimara well, which could lead to more appraisal.
And in addition to that, we have 20 additional prospects and leads that we'd like to drill on the block. So it's going to be a mix of exploration and appraisal and it really depends upon what we find as to how much appraisal we need. So we'll give you more color in when we do our budget in for 2019. Thank you.
Speaker 0
Thank you. Your next question comes from the line of Brian Singer from Goldman Sachs. Your line is now open.
Speaker 7
Thank you. Good
Speaker 2
morning. Good morning.
Speaker 7
As we try to figure the cash flow piece of the equation for next year and we look specifically at the Gulf of Mexico, issues over the last year and a half. Is 70,000 barrels a day a issues over the last year and a half. Is 70,000 barrels a day, a BOE a day, the new normal when there's no downtime? And how do you think about a more sustainable run rate of production and then the CapEx required to keep it there?
Speaker 4
So what we've always said that in the Gulf of Mexico is that 65,000 barrels a day is a level of production that we can maintain here for several years because of the tieback opportunities that we have. So in 2019, we do have 2 rigs contracted, right? So we'll be completing the drilling in Stampede with those 2 rigs. And then we talked about between kind of like $100,000,000 $150,000,000 that we'd spend every year just to do some tieback opportunities and hold that Gulf of Mexico production right around 65,000 barrels per day.
Speaker 7
Got it. Thank you. And then shifting to the Bakken, and I guess, obviously, we'll get more details shortly here in December. But, to follow-up on the points you just made on the closer to $3,000,000,000 in 'nineteen CapEx overall, Can you talk more on the Bakken specifically in terms of rig adds and then also expectations for well productivityintensity and then also takeaway?
Speaker 3
Okay. Let me take the first two and then John can talk about takeaway. Certainly, our plan for next year is to hold 6 rigs flat. So we added that 6th rig in the Q3 and our plan is just to hold the rig count at 6. As I mentioned, we're transitioning to plug and perf completion.
So that will be a £10,000,000 per well profit loading. That was confirmed as the optimum in the Bakken study. Just a few words about the Bakken study. Remember that was an independent third party look that examined over 10,000 wells, both ours and our competitors. And the study confirmed a couple of things.
First of all, it confirmed that our use of sliding sleeves and tight spacing during the downturn maximize DSU NPV, which has always been our objective. And then secondly, that the transition to plug and perf in 2018, as a result of improving technology and lower costs in that space is the right strategy to deliver more value going forward. As John mentioned, John Reilly mentioned previously, the cost of those wells currently right now is running about $7,500,000 per well, so about $1,500,000 above the sliding sleeve completion. However, just as we did with sliding sleeves, we begin to apply lean manufacturing to that process and we're reasonably confident that we can bring those well costs down over time as we apply lean manufacturing. But we will transition to that design over the remainder of 2018 and into 2019 on Plug and perf.
And again, we'll give more color on that in our Investor Day in December.
Speaker 2
Yes. And Brian, fair question in terms of takeaway. Our company does not have an issue in terms of takeaway capacity from the Bakken because of the pre investment we've done to have access to multiple export markets. And that flexibility really positions us well to maximize the value of our sales netbacks. The recent widening in the Clearbrook differential began with October trading and is primarily the result of unusually high Mid Continent refinery maintenance, not a takeaway issue, where that maintenance shut in more than 1,000,000 barrels per day of refinery capacity.
We expect this refinery demand to return in December with differentials narrowing towards historical levels. And our strategy of having these multiple export markets to maximize the value of our sales netbacks, recently in June when Clearbrook was a premium, it was about $1 over WTI, we were actually maxing sales into the Clearbrook market. And in the current market, we are currently delivering about 70% of our crude to export markets where we receive Brent based pricing, which is about $6 over WTI. And in terms of the future, we're well positioned now, but we will continue to look at potential pipeline expansions as they may occur and may add additional firm transportation in the future to further optimize our marketing efforts.
Speaker 0
Your next question comes from the line of Michael Hall from Heikkin Energy Advisors.
Speaker 8
Thanks. Good morning. Just curious on the comment on the Williston and the new plug in perf focused program being able to deliver higher peak volumes relative to the prior 175 MBOE a day that you all had discussed. What any willingness to talk about what that new peak looks like and how long you can hold it on what sort of rig and annual completion cadence is required to do that?
Speaker 3
No. We will talk about that at our Investor Day in December. But you're right, the peak is going to go up. Our current plan on the Bakken, which again we'll cover in Investor Day, is to take it to that new peak level, drop the rigs to 4 and then hold it at that new peak level for a number of years. And yes, and that at that point the Bakken becomes a massive cash generator for the company.
So that will cash flow will be significantly up in the Bakken. So as John Reilly mentioned, post 2020, you really have all of our assets generating free cash, significant amounts of free cash flow. And then of course in 2022 when Phase 2 comes on, then Guyana becomes a major cash flow generating asset. So you'll have all four assets generating significant amounts of cash when Phase 2 comes on.
Speaker 8
Okay. That's helpful. How about how long you can hold that peak? Any commentary there at this point?
Speaker 3
We'll again talk about that in December, but it will be multiple years.
Speaker 5
Okay.
Speaker 8
And then I guess maybe just on Suriname, any additional color or commentary on what you guys have learned here postmortem on the initial test? And it sounds like additional activity is not planned until 2020, but any spending that we should
Speaker 3
first of all, the Pontino well encountered 63 meters of really high quality reservoir. Unfortunately,
Speaker 7
it was wet.
Speaker 3
But now we're taking all that data from the well. We're going to recalibrate the seismic, rerun all the seismic and that will help inform future exploration in Suriname. But despite the dry hole, we still believe the block has significant resource potential as there is multiple plate types on the block. So as you mentioned, current thinking is we won't get back to drilling until 2020 on the block and give us a good amount of time to reprocess things and understand what we saw.
Speaker 8
Okay. Great. That's helpful. Thanks.
Speaker 0
Thank you. Your next question comes from the line of Ejune Jayaraman from JPMorgan. Your line is now open.
Speaker 9
Takeaway where I think you are a better position than your peers given your 50 kilobytes D or so on DAPL, etcetera. And I think you only sell about 20% in the local markets today. My question is, as we think about the incremental barrel that you produce in the Bakken, in our model, we had you going from the mid-70s in oil to the low-90s in oil. So for those incremental barrels, where would you be selling those? Would they be on rail, etcetera?
So just trying to understand what kind of dips you could see on the incremental barrels that you produce next
Speaker 2
Good question, Arun. Our plan would be to continue to access Brent based pricing between pipeline deliveries to the Gulf Coast and also rail deliveries either to the Gulf Coast, East Coast or West Coast.
Speaker 9
Got it. Got it. And that's based on rail capacity that you have today or one or
Speaker 2
capacity field? Yes. We're positioned for this now. And we'll also look at, as I said, potential pipeline expansions and may add additional firm transportation on those to ensure that we continue to optimize our differentials by getting access to offshore Brent based pricing.
Speaker 9
Okay. And I understand you guys are going to leave quite a bit for the Bakken for the December update. But the plan, as I understand, is to do about 50% more POPs are tied in line in the Bakken in 2019. Is that correct? Like 150 wells or so?
Speaker 4
Yes. Yes. That's my you can make that assumption there with the 6 rigs at right around 150, maybe a little bit more.
Speaker 10
Got it. And my
Speaker 9
final question is, John, you mentioned that CapEx could approach $3,000,000,000 or so in 2019. Is that just in the E and P level or does that include with the consolidation of the midstream, the midstream piece of that as well or if you could separate the 2 that would be helpful.
Speaker 4
That's the E and P portion and includes the spend for exploration as well. Exploration. That's just that E
Speaker 5
and P. Yes. Okay.
Speaker 4
Thanks a lot. Sure.
Speaker 0
Thank you. Your next question comes from the line of Paul Cheng from Barclays. Your line is now open.
Speaker 11
Hey guys, good morning.
Speaker 8
Good morning.
Speaker 11
A quick question. John, on the well capacity, can you tell us that how much you plan to ship some Bakken in the Q4? And also that we've heard from people saying that the well operated that they are unwilling to increase the volume unless you are willing to sign multiple year contract. Is that what you guys are seeing?
Speaker 2
In terms of takeaway capacity, right now, I mentioned it before, is about 70% of our crude is going to export markets where we can receive Brent based pricing, most of it on dappled out to Nederland, and then some to both the East Coast and the West Coast via train. And in terms of going forward, there are multiple pipeline expansion opportunities. We're looking at them and the terms and conditions of those vary.
Speaker 11
Can you share with us that, I mean, how much is the cost for you to move from Bakken to the East Coast if you're going to well yet?
Speaker 2
Well, I tell you, what I would say is going down south to needle in is about $7 and trains a little bit higher than that, West Coast being closer to that number, East Coast being a little higher.
Speaker 11
Okay. Thank you.
Speaker 0
Thank you. Your next question comes from the line of Roger Read from Wells Fargo. Your line is now open.
Speaker 12
Red, Reed, whatever it needs to be today, I guess. Good morning, guys.
Speaker 2
How are you doing? Doing all right.
Speaker 12
Thanks. Just one thing I'd like to follow-up on, on the CapEx side, the move from kind of $2,100,000,000 $2,200,000,000 this year to $3,000,000,000 overall. You mentioned kind of half between the Bakken and half between Guyana. What's since we had obviously a little spending on Utica and maybe some other places this year, kind of what's the right increment? Is that to think about it as $900,000,000 $450,000,000 $450,000,000 or it's a larger number as you the starting point is slightly different?
And then maybe the other way to think about it is, does exploration spending go up from here relative to what we've seen, which I would think has to happen given a second rig in Guyana and then potential in 2020 to restart in Suriname. So maybe just a little clarity on that if you could.
Speaker 4
Sure. So first, outside, like you said Utica or assets like that, we were not spending much capital in 2018 on that. So the base that you should start with is the $2,100,000,000 because our capital guidance remains unchanged. And so then moving up, I'd say going through that closer to $3,000,000,000 there's a little bit more going to Bakken than Guyana. And if you can just I'll do some simple math for you.
Bakken guidance was approximately $900,000,000 for this year. We're about at 4.75 rigs and we're going to 6 for the full year. On average, we're 4.75 rigs. Just do the math on that, you'll get about $240,000,000 just with everything being exactly the same. Then as Greg and I had mentioned, the current plug and perf wells are approximately $1,500,000 higher.
We're going to be drilling a lot more of them next year than we did this year. So just simply, if you took that $150,000,000 times 1.5 percent, put our working interest around 80% or so in it, you can kind of see how you're getting to the numbers there in the Bakken. So it's simply like that. And then Guyana, it's exactly what I talked about before. It's just the additional drill ship.
That factors in for exploration. So when I was talking about Guyana, that included this additional exploration spend from that additional drill ship.
Speaker 2
Yes. And Roger, just again to I'd say reemphasize the point that John made earlier. The increment in CapEx is going to very high return projects, the increment being probably in the range of 30% to 50% IRRs, very quick paybacks, While next year, we'll ramp up in CapEx, we should start becoming cash flow positive in a $60 WTI, dollars 65 Brent World in 2020. Covering the CapEx and dividend, we should become cash flow generative there. And then the outlook going past that, and we'll go over this in Investor Day, is that a CapEx going forward probably is going to be in the range of $3,000,000,000 holding flat out to 2025.
So our portfolio becomes very cash generative, putting us in a great position to balance investing in the business and high returns going forward and also returning capital to our shareholders.
Speaker 12
That's great clarity. Thank you.
Speaker 0
Thank you. Our next question is from Jeffrey Campbell from Tuohy Brothers. Your line is now open.
Speaker 13
Good morning. I wanted to just ask a quick question regarding the expectations for the Plooma exploration well that you mentioned in the press release. And I'm really asking this because I'm trying to get some sort of a feel for how the hubs are going to develop. If it was successful, would it more likely be a tie in to turbo or could it potentially support standalone production?
Speaker 3
No, I think it will be part of that what we call the greater turbot complex. We're really trying to define that to understand how many vessels it's going to take to evacuate that, right? That area, there's a lot of accumulations there that we want to get a drill bit in.
Speaker 13
Okay. That's helpful. Thank you. And I just wanted a quick question just a little color on the improved Bakken well performance that was mentioned in the press release. So I was just wondering is there anything new going on in the completion kit?
Or was this just an example of exceeding prior expectations?
Speaker 3
No, I think it's just a continuous improvement in completion practices. That number that I gave you is primarily dominated by sliding sleeves. So recall, this year we increased the profit loading in our 60 stage sliding sleeves to £140,000 per stage. So that's about £8,400,000 on the sliding sleeve. So that primarily that number I gave you reflects that increase in proppant in sliding sleeve.
In addition to that, we're also transitioning to plug and perf and based on the results of the Bakken study and some of the very preliminary results that we got from our early plug and perf trials, that move to £10,000,000 is going to be very value accretive. So we'll give you some more color on that in December. But there that will be 2. The first jump was sliding sleeve move. The next jump will be plug and perf and you'll get an increment on each of those.
Speaker 13
Okay, great. That's very helpful. I look forward to the Analyst Day in December. Thank you.
Speaker 0
Thank you. Our next question is from Paul Sankey from Mizuho. Your line is now open.
Speaker 14
Hi, everyone. Actually, John Hess just hit the nail on the head. I was going to ask about the run rate of CapEx given next year's number, but you clearly answered that one. So thank you there. I wonder maybe I could ask on DD and A coming down.
Could you give the outlook for that dynamic? What caused it to
Speaker 6
come in below expectations? And what do you think
Speaker 14
the outlook is there?
Speaker 2
Marriage. I want to get that output.
Speaker 14
I appreciate that, John. Thank you very much indeed.
Speaker 4
Paul, the DDA in the Q3, really the better performance in guidance was due to the production. So what we had was that higher production in the Gulf of Mexico with lower DD and A. And so that's what's driving that Q3 DD and A rate down. And then on a go forward basis, as we project into the future kind of what John was talking about with our capital being focused in those high return Bakken and Guyana assets, we continue to see over this period through 2025 that our DD and A rate will continue to come down and we'll give more information on that at the Investor
Speaker 6
Day. Great.
Speaker 14
Thank you, gentlemen.
Speaker 0
Thank you. Your next question comes from the line of Pavel Molchanov from Raymond James. Your line is
Speaker 10
now open. Thanks for taking the question. It seems like every week now there is a parent company that is taking back in and acquiring its MLP. In that context, I thought I would get your thoughts on how committed you are and Global Infrastructure Partners is to maintaining Hess Midstream as a standalone public entity?
Speaker 4
Yes. So I mean, it hasn't been that long since we've done the IPO of the Midstream and the Midstream has been performing fantastically. And it's been a great partner for us in this build out of infrastructure. And as we're going to talk about, obviously, moving to the plug and perf and our increase in production above the 175, having that midstream partner, GIP and Hess Midstream overall has will really help us in that. And as John had mentioned before in our takeaway capacity, it's really just in general put us in a great place from a revenue standpoint and a cost standpoint.
So where we are with that, I know what you've been talking about. We've been watching that happen in the market, but it's early days. We've got plenty of growth left in that public midstream vehicle that we have. We're happy with this performance and expect it to continue to perform well.
Speaker 10
And one question about Guyana. You may hold off on this until the Analyst Day, but you're very close to approving Phase 2. You're talking about 5 total. For a country as small as Guyana and that has never had an oil industry, are you facing any any labor shortages or other kinds of bottlenecks as you're creating essentially a brand new value chain where none has existed before?
Speaker 3
No. So far, there's no issues with labor shortage. Remember, this is an offshore development. So the majority of everything is floated in, right, and the work's all done offshore.
Speaker 2
And I think ExxonMobil as operator has done a great job in maximizing local content where possible.
Speaker 5
All right. Appreciate it, guys.
Speaker 0
Thank you. Your next question comes from the line of Doug Leggate from Bank of America. Your line is now open.
Speaker 6
Hey guys, sorry for lining up again. I just wanted to clarify something on the capital program. So John Reilly, I know you don't want to give details on the Guyana fiscal contract, but exploration costs on the entire block, as I understand it, can be recovered from any revenue. Is that still the case? In which case, once you've got first oil, what can you say about the cost recovery on the exploration dollars?
Speaker 4
The contract works as the whole block is the ring fence. So all costs can be recovered once production starts. So you are correct in what you said.
Speaker 6
That applies to development dollars on subsequent phases as well?
Speaker 4
Yes, it does.
Speaker 6
Great stuff. Thank you. And just one final quick one on the MLP, given that question just got asked. Is your plan still to monetize units from the MLP over time?
Speaker 2
We are committed to the MLP, and we don't have the need, as Hess, to monetize anything right now and neither does GIP because basically the dropdowns from Hesco into midstream partners. And we have a multiyear runway where we don't need to do any dropdowns into the MLP. So I just want to be clear. And I also want to be clear that Hess and GIP are committed to the MLP and continuing the growth trajectory and really maximizing value from our investment in the midstream business. Great.
Thanks, Jose.