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Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2018 Hess Corporation Conference Call. My name is Amanda and I’ll be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] 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.
Thank you, Amanda. Good morning everyone and thank you for participating in our fourth quarter 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 risk 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.
As usual, with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. I'll now turn the call over to John Hess.
Thank you, Jay. Good morning and welcome to our fourth quarter conference call. I will review our progress in executing our strategy, Greg Hill will then discuss our operating performance, and John Rielly will then review our financial results.
Our strategic priorities are; first, to invest only in high return low cost opportunities. Through 2025, we plan to allocate about 75% of our capital expenditures to our Guyana and Bakken assets, two of the highest return investment opportunities in the industry.
Second, we have built a focused portfolio with a combination of short-cycle and long-cycle investment opportunities with Guyana and Bakken as our growth engines and the deepwater Gulf of Mexico and the Gulf of Thailand is our cash engines.
As we discussed at our recent Investor Day, our portfolios position to deliver approximately 20% compound annual cash flow growth and more than 10% compound annual production growth through 2025 with a portfolio breakeven of less than $40 per barrel Brent by 2025.
Third, we will continue to ensure that we have the financial capacity to fund our world-class investment opportunities and maintain an investment grade credit rating. We entered 2019 with 2.6 billion of cash on the balance sheet, 95,000 barrels of oil per day hedged in 2019 with $60 WTI put options and the spending flexibility to reduce our capital program by up to $1 billion should oil prices move lower on a sustained basis.
Fourth, we are focused on growing free cash flow in a disciplined and reliable manner. We are adding an exciting inflection point, transitioning from an investment phase in 2019 to a free cash flow generation phase beginning in 2020 with a start-up of the Liza Phase 1 development offshore Guyana, followed by the Bakken growing to 200,000 barrels of oil equivalent per day in 2021. And then the Liza Phase 2 start-up offshore Guyana by mid-2022 with an additional ship planed in Guyana for each year thereafter through 2025.
Finally, as our portfolio generates increasing free cash flow, we will prioritize return of capital to shareholders through dividend and opportunistic share repurchases. As we execute our strategy, we will continue to be guided by our long-standing commitment to sustainability in terms of safety, protecting the environment, and social responsibility.
A key driver of our strategy is Guyana where Hess has a 30% interest in the Stabroek Block and ExxonMobil is the operator. In December, we announced the tenth discovery on the block at Pluma. As a result of this new discovery, and further evaluation of previous discoveries, the estimate of gross discovered recoverable resources for the block was increased to more than 5 billion barrels of oil equivalent with multi-billion barrels of additional exploration potential.
Earlier this month, drilling began on the Haimara-1 exploration well, 19 miles east of the Pluma-1 discovery and on the Tilapia-1 exploration well in the Turbot area. The Liza Phase 1 development is on track to start-up in early 2020. Project sanction for Liza Phase 2 is expected in the first quarter of 2019 with start-up expected by mid-2022.
Sanctioning of a third development Payara is expected towards the end of 2019 with start-up, as early as 2023. Also, key to our strategy is the Bakken. Our largest operated growth asset where we have more than a 15-year inventory of high return drilling locations. Our transition to plug-and-perf completions should increase net present value of the asset by approximately $1 billion.
Net production is expected to grow to 200,000 barrels of oil equivalent per day by 2021, generating approximately $750 million of annual free cash flow post 2020 at current oil prices.
Now, turning to our 2018 financial results. Our adjusted net loss was $176 million, compared to a loss of $1.4 billion in 2017, and cash flow from operations before changes in working capital was $2.1 billion, up from $1.7 billion in the prior year.
In 2018, we delivered proved reserve additions of $172 million net barrels of oil equivalent representing an organic replacement rate of 166% at an F&D cost of just under $12 per barrel of oil equivalent. The majority of these additions were in the Bakken.
Proved reserves at the end of the year stood at 1.19 billion barrels of oil equivalent and our reserve life was 11.5 years. Full-year 2018 production was 257,000 barrels of oil equivalent per day, excluding Libya. Pro forma for our asset sales and Libya, our production was 248,000 barrels of oil equivalent per day in 2018, 10% higher than the pro forma 224,000 barrels of oil equivalent per day produced in 2017.
In 2019, our production is forecast to average between 270,000 and 280,000 barrels of oil equivalent per day, excluding Libya. Bakken net production is forecast to average between 135,000 and 145,000 barrels of oil equivalent per day in 2019.
In summary, we are extremely well-positioned to deliver increasing and strong financial returns, visible and low risk production growth, and significant future free cash flow, the majority of which will be deployed towards increased return of capital to our shareholders.
I will now turn the call over to Greg.
Thanks, John. 2018 was a year of strong operational execution and continued delivery of our strategy. We delivered production of 250,000 net barrels of oil equivalent per day in 2018, excluding Libya, which exceeded our original production guidance of 245,000 to 255,000 net barrels of oil equivalent per day. This was achieved within our capital guidance of 2.1 billion and even after accounting for the sale of our JV interest in the Utica, which reduced full-year 2018 net production by approximately 5,000 barrels of oil equivalent per day versus guidance.
In Guyana, on the 6.6 million-acre Stabroek Block where Hess has a 30% interest and ExxonMobil is the operator, we continued our extraordinary run as exploration success with five further major discoveries over 2018 at Ranger, Pacora, Longtail, Hammerhead and Pluma.
In December, the estimate of gross discovered recoverable resources for the Stabroek Block were increased to more than 5 billion barrels of oil equivalent, up from about 3.2 billion barrels of oil equivalent a year ago. The growing resource base on the block reinforces the potential for at least five floating production storage and offloading vessels or FPSOs, producing more than 750,000 barrels of oil per day by 2025.
Guyana is world-class investment opportunity in every respect. The combination at scale, exceptional reservoir quality, shallow producing horizons, and timing of the development in the cost cycle provide industry-leading breakevens, which is key to moving Hess towards a $40 per barrel Brent breakeven oil price by 2025, while delivering significant growth in returns on invested capital and cash flow generation.
In the Bakken, we have a 15-year inventory of drilling locations that can on average generate IRRs of more than 50% at $60 per barrel WTI. Through field trials and an independent study, we confirmed that our planned transition to plug-and-perf completions in 2019 from our previous 60 stage sliding sleeve design is significantly value accretive.
Based on these results, we expect production to grow to approximately 200,000 net barrels of oil equivalent per day by 2021, after which the asset should generate approximately $750 million of free cash flow annually at current prices through the middle of the next decade. In 2018, we also brought further focus to our portfolio by successfully closing on the sale of our JV interest in the Utica shale play to Ascent Resources for approximately $400 million in late August.
Now, turning to production. In the fourth quarter, production averaged 267,000 net barrels of oil equivalent per day, excluding Libya, above our guidance of approximately 265,000 net barrels of oil equivalent per day on the same basis.
For the full-year 2019, we forecast production to average between 270,000 and 280,000 net barrels of oil equivalent per day, excluding Libya, which on a pro forma basis is approximately 10% above 2018. In the first quarter of 2019, we forecast production to average approximately 270,000 net barrels of oil equivalent per day.
Now, turning to the Bakken. In the fourth quarter, production averaged 126,000 net barrels of oil equivalent per day, which represented an increase of approximately 15% over the year ago quarter and above our previous guidance of 125,000 net barrels of oil equivalent per day. For the full-year 2018, production averaged 117,000 net barrels of oil equivalent per day in-line with full-year guidance of 115,000 to 120,000 net barrels of oil equivalent per day.
For the full-year 2019, we forecast our Bakken production to average between 135,000 and 145,000 net barrels of oil equivalent per day approximately 20% above 2018 levels. In the first quarter of 2019, we expect Bakken production to average approximately 130,000 to 135,000 net barrels of oil equivalent per day. In 2019, we plan to drill approximately 170 wells and bring approximately 160 new wells online, compared to 121 wells drilled and 104 wells brought online in 2018.
Moving offshore in the deepwater Gulf of Mexico, production averaged approximately 68,000 net barrels of oil equivalent per day in the fourth quarter and 57,000 net barrels of oil equivalent per day for the full-year 2018 above our guidance, reflecting strong performance from our new Penn State Deep 6 well and the early return to production of the Conger field. We forecast 2019 production from our deepwater Gulf of Mexico assets to average between 65,000 and 70,000 net barrels of oil equivalent per day.
At the Malaysia Thailand joint development area and the Gulf of Thailand in which Hess has a 50% interest, production averaged 35,000 net barrels of oil equivalent per day in the fourth quarter and 36,000 net barrels of oil equivalent per day for the full-year 2018.
At the North Malay Basin, also on the Gulf of Thailand, net production averaged 28,000 net barrels of oil equivalent per day over the quarter and 27,000 net barrels of oil equivalent per day for the full-year 2018. Combined production from our JDA and North Malay Basin assets is forecast to average between 60,000 and 65,000 net barrels of oil equivalent per day for the full-year 2019.
Turning to Guyana. Earlier this month the Stena Carron drillship began drilling the Haimara-1 well, located 19 miles east of the Pluma-1 discovery and the Noble Tom Madden drillship began drilling a second well, Tilapia-1, located 3 miles west of the Longtail-1 discovery, both in the southeastern part of the Stabroek Block. We expect to have results from both of these Wells shortly.
Following completion of drilling operations on these wells, the Stena Carron will conduct a drill stem test at the Longtail discovery and the Noble Tom Madden will drill an additional exploration well on the Turbot area, likely Yellowtail. Beyond these wells, 2019 drilling on the Stabroek Block is expected to include appraisal of the Hammerhead and Ranger discoveries, and further exploration and appraisal in the Turbot area.
Additional prospects and play types on the block, where we continue to see multibillion barrels of exploration upside, will also be prioritized for the drill schedule. The Liza Phase 1 development is progressing the schedule, drilling of Phase 1 development wells in the Liza field by the Noble Bob Douglas drillship is well advanced.
Subsea equipment is being prepared for installation, and the topside facilities modules are being installed on the Liza Destiny FPSO in Singapore. Preparations are underway for the installation of subsea umbilicals, risers and flowlines in the second quarter and the Liza Destiny FPSO is expected to sale from Singapore and arrive offshore Guyana in the third quarter of 2019. Also, as mentioned earlier, we continue to expect sanction of Liza Phase 2 in the first quarter and the Payara development to be sanctioned later this year.
In closing, I believe that we have built distinctive capabilities and created a world-class portfolio that together will enable us to deliver industry-leading performance and significant shareholder value for many years to come.
I will now turn the call over to John Rielly.
Thanks, Greg. In my remarks today, I will compare results from the fourth quarter of 2018 to the third quarter of 2018, and provide guidance for 2019. We incurred a net loss of $4 million in the fourth quarter, compared to a net loss of $42 million in the third quarter. Excluding items affecting comparability of earnings between periods, results in the fourth quarter were a net loss of $77 million, compared to net income of $29 million in the previous quarter, resulting primarily from lower realized crude oil prices.
Turning to E&P. On an adjusted basis, E&P incurred a net loss of $5 million in the fourth quarter, compared to net income of $109 million in the third quarter. The changes in the after-tax components of adjusted E&P results between the fourth quarter and third quarter of 2018 were as follows: Lower realized selling prices reduced results by $122 million. Lower exploration cost improved results by $78 million. Higher DD&A expense reduced results by $58 million. All other items reduced results by $12 million for an overall reduction in fourth quarter results of $114 million.
Turning to Midstream. The midstream segment had net income of $32 million in the fourth quarter, compared to $30 million in the third quarter of 2018. Midstream EBITDA before the noncontrolling interest amounted to $127 million in the fourth quarter, compared to $130 million in the previous quarter.
After-tax corporate and interest expenses were $31 million in the fourth quarter of 2018, compared to $122 million in the third quarter of 2018. On an adjusted basis after-tax corporate and interest expenses were $104 million in the fourth quarter of 2018, compared to $110 million in the previous quarter.
Turning to our financial position. Excluding midstream, cash and cash equivalents were $2.6 billion, total liquidity was $7 billion, including available committed credit facilities, and debt was $5,691 million at December 31, 2018. Cash flow from operations before working capital changes was $584 million, while cash expenditures for capital were $664 million in the fourth quarter.
Changes in working capital increased cash flows from operating activities by $297 million in the fourth quarter, due to an increase in accounts payable and a reduction in accounts receivable. In the fourth quarter, we purchased $250 million of common stock, which completed our previously announced $1.5 billion stock repurchase program.
Now turning to guidance, we project E&P cash cost, excluding Libya to be in the range of $12.50 to $13.50 per barrel of oil equivalent in the first quarter of 2019, and $13 to $14 per barrel of oil equivalent for full-year 2019, which includes costs for pre-production activities for Guyana Phase 1 and pre-development costs for future phases.
DD&A expense, excluding Libya is forecast to be in the range of $18 to $19 per barrel of oil equivalent for the first quarter of 2019, and for the full-year of 2019. This results in projected total E&P unit operating cost, excluding Libya of $30.50 to $32.50 per barrel of oil equivalent for the first quarter and $31 to $33 per barrel of oil equivalent for the full-year 2019.
As guided earlier, capital and exploratory expenditures in 2019 are expected to be $2.9 billion. Exploration expenses, excluding dry hole costs are expected to be in the range of $45 million to $55 million in the first quarter with full-year 2019 forecast to be in the range of $200 million to $220 million. The midstream tariff is expected to be approximately $170 million in the first quarter with full-year 2019 projected to be in the range of $750 million to $775 million.
The E&P effective tax rate, excluding Libya is expected to be an expense in the range of 0% to 4% for the first quarter and full-year 2019. Our 2019 crude oil hedge positions remain unchanged. We have 95,000 barrels of oil per day hedged for calendar 2019 with $60 WTI put option contracts. We expect option premium amortization will be approximately $29 million per quarter in 2019.
For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be approximately $35 million in the first quarter with full-year 2019, expected to be in the range of $170 million to $180 million.
Turning to corporate, for the first quarter of 2019, corporate expenses are estimated to be in the range of $25 million to $30 million, and full-year guidance to be in the range of $105 million to $115 million. Interest expenses are estimated to be in the range of $80 million to $85 million in the first quarter and in the range of $315 million to $325 million for the full-year of 2019. This concludes my remarks.
We will be happy to answer any questions. I will now turn the call over to the operator.
[Operator Instructions] Our first question is from the line of Doug Leggate of Bank of America Merrill Lynch. Your line is open.
Thanks. Good morning, everybody. John Rielly, the CapEx plan obviously hasn't changed given you only just put out a few weeks back, but given the dynamics of the oil price what would it take, I guess given the hedge position you are in, what would it take for you to need to cut, I guess going into perhaps the second half of this year, what I'm really thinking is, obviously oil prices are well below where they were when you set the budget, I'm just curious if you’ve got any contingency plan just to where the flexibility would come?
Sure, Doug. I mean, as we laid out at our Investor Day, we do have this long-term strategy and we do intend to continue to execute it. We really feel that we have the portfolio on a really nice place from the asset sales and we’re really – now this portfolio can deliver the 10% production growth and the 20% cash flow growth as John Hess mentioned earlier. So, the only thing that we can't predict with this, with our portfolio is commodity prices. So, all we’re doing now is trying to manage uncertainty. So, what did we do with proceeds from the asset sales?
We’ve left $2.6 billion of cash on the balance sheet and we have the hedges in place for 2019 and that’s 95,000 barrels of oil per day with the $60 floor price and that’s WTI. So, the company is well-positioned to deliver that strategy even in this low-price environment. Now, if we get extended in an extended low-price environment and really would have to go really more into 2020, the tail-end of 2019 into 2020, in that case an extended low-price environment we have the flexibility as we mentioned to reduce our annual CapEx by as much as $1 billion and that’s principally by reducing rigs in the Bakken. But right now, our plan is to execute with six rigs in the Bakken and deliver everything that we said that we laid out in Investor Day.
Okay. I appreciate. Obviously, we’re not expecting at this point, but we will keep an eye on it. My follow-up if I may is on exploration and it’s kind of couple of part question, I guess. The Tom Madden as I understand was only contracted for 2 well slots, I was just wondering if that has now been extended and if so, what do you have in the plan for this year by way of total exploration wells? And I realize that can move around, but well test and so on, and if I may just on that last point, Greg, I wonder if you could just characterize Haimara for us in terms of scale, it looks like it's a big green block to the east of the Turbot-Longtail, but as you probably saw from the other day, our understanding is that service sector is telling is that is already under test, which would imply discovery. So, any confirmation or color you can offer around that would be appreciated? Thanks.
Yes, thanks Doug. So, Haimara’s operations are currently underway and as we said in our opening remarks, we expect to announce something on that shortly, as well as the Tilapia well. Regarding the Tom Madden, yes, we plan to use that rig throughout 2019. We really have, without talking about specific well numbers because again it does depend on kind of what we find in testing and etcetera as we go forward, but our main objectives on the block this year are really threefold. One is, to appraise Hammerhead; second is to appraise Ranger; and then our third objective is to continue to explore/appraise around Turbot. And the purpose of those three objectives is really to underpin vessels four and five, where are they, how big are they, et cetera. So, those are our main objectives this year, and we’ll do that with two rigs in the exploration/appraisal theater.
Just to be clear, the $200 million guide that’s a G&G cost not a dry hole cost, right?
I'm sorry Doug, the 200 million guide from…?
Yes, the guidance that you suggested I think for exploration, that is G&G, not dry hole?
Okay. So, exploration spend for 2019 is going to be $440 million that’s what we laid out in Investor Day.
Sorry. I thought I [indiscernible].
Oh, so are you talking from my – when my guidance that I give out, we give exploration expenses without dry hole costs, so, that’s the expense. The capital spend for exploration will be approximately $440 million in 2019.
Right. Got it. Thank you.
Thank you. Our next question is from the line of Brian Singer of Goldman Sachs. Your line is open.
Thank you, good morning.
Good morning.
Wanted to follow-up actually on the point on Guyana you were just talking about with regards to appraisal, so what degree does the appraisal program over the next 6 months to 9 months, as you said, just underwrite FPSO is 4 to 5 versus open up the door for additional FPSOs beyond 5 or it is the emphasis on the plus – 5 plus FPSOs expansion beyond 5 contingent on additional exploration as opposed to appraisal success?
Yes, Brian. So, the answer is both. I mean, as I said in my remarks earlier, one of the primary intentions though with the program this year is to underpin vessels 4 and 5. So, where are they? We know that there will be one or more potentially in the Turbot complex so it is likely to be one or more on the Hammerhead, and then finally Ranger or how does that play in and when does it play in. And as you mentioned, we will additionally be doing additional exploration on new prospectivity on the block above and beyond that. So, it’s really both, but we’re anxious to get 4 and 5 underpinned, obviously, because we want to keep the cadence of design one, build many, kind of, a ship a year coming online. So, it’s important to understand where those are, get them engineered, get them designed, and more importantly how big to build them.
Great. Thanks. And then my follow-up is that with regards to the Bakken, can you just give us the latest that you're seeing in terms of the service cost environment of may be unrelated to your shift to the plug-and-perf, but just more of the service cost environment in the Bakken and then what you're currently seeing on the realization front? Thank you.
Yes. So, I’ll take the service cost. So, I guess first point Brian is, you know the Bakken is very different than the Permian. It’s a more regional market. Therefore, it’s not experiencing the level of cost inflation that the Permian is seeing. Now, having said that, we’re seeing an average cost increase of 5% to 10% on average in the Bakken in 2019. Most of that’s in the form of higher labor cost, but having said, we’re confident that with the combination of the performance-based service contracts we've established with our suppliers or many of our suppliers and our lean-manufacturing capabilities we will be able to cover all of that inflation. So, from a well cost guidance standpoint, we're very confident we’ll deliver what we promised, in spite of the inflation.
And just Brian to your question on the realizations, they are back to normal in the Bakken. So, during the fourth quarter, at the beginning of the fourth quarter, the Clearbrook spread moved from a plus $0.78 of the [TI] to minus $8.30 per barrel and that was due to about 1 million barrels of demand going away just due to refinery maintenance. So, now like the refineries are back online, the differentials are back around normal. They’ve been a dollar above to a dollar under and so we’re just seeing more of the normal type of Bakken differentials. And if I can just add again, our strategy is to have multiple export markets there to provide us flexibility to move our oil into the highest value market. So, we can get about 70% of our oil to the coast to get the Brent influenced pricing. So – and that’s through a combination of our firm transportation of pipelines in rail.
Thank you.
Thank you. And our next question is from the line of Ryan Todd of Simmons Energy. Your line is open. And Mr. Todd, you line might be on mute, your line is open.
Sorry, I apologize for that. A couple of quick questions on the Bakken. Of the 35 wells that you brought under in the fourth quarter how many of those if any were plug-and-perf and can you comment on how early production looks relative to expectations in your targeted type curve for the 2019 program?
So, in the fourth quarter it was 13 were plug-and-perf that came online and as we said basically going forward, it’s almost 100%. We could have had some carryover sliding sleeves being coming online, but really all our program is plug-and-perf. I’ll turn it over to Greg on performance in the plug-and-perf.
Sorry. I was on mute for a second. Just a reminder, the high intensity plug-and-perf completions are expected to deliver a 15% to 20% increase in IP 180. At least a 5% increase in EUR. That increase is our plateau production to 200,000 barrels a day from the previously guided 175. And importantly an increase in overall Bakken NPV by over $1 billion at $60 per barrel WTI, and what I will say is that results so far indicate that we are meeting or beating expectations on IP rates. So, we’re in good stead going forward.
Alright. It’s good to hear and maybe any near-term impacts from the weather, and you had a relatively strong oil mix in the fourth quarter as well, I know that bounces around every time is ask you from quarter-to-quarter, but anything on those two things?
Now there has been some minor weather impacts. You know, it’s extremely cold. So, the polar vortex is alive and well in North Dakota just like the rest of the nation, but we expect to recover from all that as normal.
And then, just going to the oil cut too and I know the way you asked your question you’re right. I mean oil cut is going to fluctuate quarter-on-quarter really due to changes in gas volumes captured, NGL's extracted and also NGL pricing, but just from our guidance standpoint, we do expect to average in the low-to-mid 60% range for the foreseeable future. So, the increase in Q4 relative to our gas it was driven by lower gas was gathered because we did have Tioga Gas Plant maintenance in the quarter, and that drove up the oil cut.
Perfect. I appreciate the help. Thanks guys.
Thank you. Our next question is from the line of Jeffrey Campbell of Tuohy Brothers. Your line is open.
Good morning and congratulations on the quarter.
Thank you.
I was just wondering could you add some, kind of color with regard to the Guyana, 2019 well test program, you know how specifically how that’s going to help you to confirm or eliminate development options for the future?
Well, I think, you know the purpose of the testing program, the primary purpose is always to establish reservoir continuity. So, is there compartmentalization or anything like that going on so far. All of our drill stem tests have indicated very good reservoir continuity everywhere we go. So, that’s important as you think about vessels 4 and 5 to have some tests under your belt to understand how many wells will it take to evacuate those reservoirs. So that will be the purpose again, if looking at 4 and 5 and the majority of the testing will be dedicated to that or new discoveries that we would like to get drill stem testing, while we’re there.
Okay, thank you. And I was just wondering, could you comment broadly on the distribution of the drilling and completions in your best areas such as Keene and Stony Creek versus East Nesson and Beaver Lodge in 2019? Just kind of wondering how you're going to distribute the rigs around the completion?
Yes. So, if you think about the 160 wells online that we're going to drill, about 45 of those would be in Keene, about 30 or more be in Stony Creek, 40 or so will be in East Nesson, and then 20 will be in the Beaver Lodge, kind of [cap area], and then we have another 25 miscellaneous wells that are really spread out to try different loadings etcetera. So, kind of test wells in other parts of the field.
On the 25, is that – I know that other operators in the Bakken have talked about this as well, is that sort of an effort to try more moderate completions may be in areas where you haven’t done it recently to see if you can push those EURs up?
Yes. I think so. You know those 25 wells, we’re going to be about 11 in Goliath and 14 in Red Sky. So, really that as you kind of move out, how do we think about profit loading and potentially even spacing in those areas of the field. So, we want to get some of that experience under our belt this year. But if you look at the program for this year, the IP 180's are going to average 120 to 125. And certainly, the EURs will be well north of 1 million barrels for the program. So, good healthy program and returns in the 50% to 100% range.
Great. I appreciate that color. Thank you.
Thank you. And our next question comes from the line of Bob Brackett of Bernstein Research. Your line is open.
Hi, good morning. Could you talk in terms of Guyana, the pending government and regulatory approvals. How do you see the milestones coming through the first quarter and are they influenced by the election down in Guyana?
Let’s handle it two ways. With the recent no-confidence vote in elections still being scheduled, there is absolutely no impacts to our exploration or development activities. Liza Phase 1 remains on track to achieve first oil in early 2020. And we also expect Liza Phase 2 to start up by mid-2022. The government on the final approval on plan of development it’s just a question of getting a third-party engineering firm in place, which is underway to work with ExxonMobil to basically vet the details of the plan of development and we anticipate getting that in the first quarter and moving forward, but I think the important thing there Bob is that – all steam ahead.
Yes. That’s clear. Related follow-up that the F&D of under $12 a barrel is quite strong. If you look back to the 2017, that was an amazing $5 a barrel as those Liza bookings came through. How do we think about the cadence of Guyana reserves booking either on project sanction or then production-related revisions as we go forward?
Sure, Bob. We really believe we’ve got competitive advantage with our reserve resource and backlog basically. One, just so you know we only have 40 million barrels of Guyana booked at this point, and as Exxon says there’s greater than 5 billion barrels discovered. And it is this cadence because with the cadence we have the sanction of the Phase 1. We’ve booked the approximately 40 million barrels and did not book any barrels here in 2018. So, when Phase 2 as John says get sanctioned, we will pick up barrels then. Phase 3 is Exxon is same by the end of the year. We’ll pick up those barrels. Then also as we drill the production wells now for Phase 1 and begin to start-up performance on Phase 1, we’ll be picking up additional reserves at that time. So, from a reserve standpoint, Guyana will be the gift that keeps on giving for us here over the time because as John Hess mentioned earlier, as we expect to have these phases come on once every year, we’ll continue to record additional reserves every year as this moves out and you saw the low F&D cost associated with that. So, little on the scale and just the uniqueness of the low-cost reserves it just puts us in a terrific competitive advantage.
Great. And thanks for that color.
Thank you. And our next question comes from the line of Roger Read of Wells Fargo. Your line is open.
Yes, thanks. Good morning. Maybe just to follow-up on some of the Guyana stuff, can you talk to us a little bit about, I guess what some of the issues we should watch for in terms of completion and delivery of the destiny vessel and then anything else on the development drilling or any other critical equipment timelines we should be watching to remain comfortable with the early 2020 start-up?
Yes. So, I think as I mentioned in my opening remarks, you know the cadence of when the vessel will show up and whatnot, we’re on schedule to do that, so there are no issues foreseen yet. We are on schedule to get the vessel on location. I think the next key thing to watch is all of the surf activities that really start in the second quarter in Guyana. So, those are key activities, but we are – based on the project progress to date, we are on schedule to deliver oil in early 2020. Then you will ramp those wells up over a 4-month to 6-month period so it won't be an instantaneous ramp. The reason for that is you will bring them on flow just to make sure that you don't have any say in control issues. So, there will be a ramp of 4-months to 6-months, according to the operator.
Yes, of course understand that. And then just one last question on balance sheet flexibility, obviously hedged up for this year the 95,000 barrels, I was curious is there and you may have mentioned this, I may have just missed this in the original commentary, but what’s been done or could be done for 2020 or what do envision maybe needing to do for 2020, if the opportunity to hedge at $60 would represent itself again?
Yes. We will continue to look to add hedges as we move into 2020 or 2021. As I said earlier, we’re just looking to manage the uncertainty, and we do like to have that healthy insurance to ensure our program and continue to be executed because, as I said earlier, we really like where the portfolio is right now and what it can deliver that 10% production growth and 20% cash flow growth. So, with the 95,000 barrels a day hedged at the $60 WTI floor for 2019, once we look to 2020, we will look to put on hedges as well to add insurance.
And I think it’s important to know that the structure we’d use would be similar where we protect the downside, but we don't cap the upside.
Okay, great. Thank you.
Thank you. And our next question comes from the line of Paul Cheng of Barclays. Your line is open.
Hi, guys. Good morning.
Good morning.
John Rielly, I have to apologize, you gave a number about amortization cost per quarter for the hedges is that 29 million after tax?
Yes. That is 29 million after tax?
Okay. And John just curious that, I mean, have you or Exxon have ever reached out to the opposition party and see what is their current view about contract and everything?
Yes. So, you know that both major parties, the current ruling party, as well as the opposition party have stated that they are supportive of the development and have consistently stated their intention to honor our PSCR contract.
And based on the current trend, when the consortium will start to developing the natural guess for the local market?
Paul, that project is still under review and under discussion with the government and we were doing some early engineering studies to figure out what it will take, but in any case, it will be a small amount – relatively small amount of gas going onshore in the main to deliver to a gas fired power plant. But that project has not been sanctioned. It’s still under feasibility studies and whatnot.
Great comment. So, that saved me some reading through the entire PSC, is that being specified in the PSC in terms of this scoop and the when that gets the market and need to be developed?
No. All that’s still under discussion with the government.
Okay. So, that is actually subject to discussion is not framed into PSC?
No. I think we’ve agreed for the necessity for it, but timing and how it all is going to work and all that is yet to be determined.
Okay. And at Bakken, at 200,000 barrel per day of the peak, many years that you can sustain based on the [full rigs]?
4 to 5.
4 to 5 rigs. I mean how many years [indiscernible]?
Based on what we know today. I mean 4 rigs, but 4 to 5 years at a peak, you know obviously based on what we know today, you know completion technology could get better. I mean there’s lots of things that could get better that could extend that?
But the current base on what you know today the resource is 4 years to 5 years on that?
Right. That’s roughly 200,000 barrel a day peak. At a 4-rig level, so let me be clear about that?
Yes. John Rielly on the Midstream, can you tell us what is the expected CapEx for 2019 and 2020?
For 2019, the Midstream has put out its guidance. It’s 275 million to 300 million of CapEx for Midstream. There is some small amounts that are in that Midstream related to water assets, because you know the water asset sale is expected to close in the first quarter. That’s approximately 25 million to 30 million on top of that, but that’s the gross amount that I was giving you.
Okay. How about 2020, any kind of rough number?
No. We don't have guidance out on that. So, again, it will depend all on our plans, as well as any potential third-party opportunities that the Midstream has.
Okay. Thank you.
Thank you. And our next question comes from the line of Ross Payne of Wells Fargo. Your line is open.
How are you doing guys? Obviously, Venezuela got involved with Exxon’s exploration ship on the very western part of the Guyana border, can you give us an update on when you think that will be resolved through the UN? Thank you.
Drilling and development operations in offshore Guyana are unaffected by the incident that involved the seismic acquisition vessels on Saturday, December 22 when the vessels were approached by the Venezuelan Navy. The area where the incident occurred is more than 110 kilometers from the Ranger discovery, the closest of our 10 oil discoveries, and approximately 190 kilometers from the Liza development area. So, the point is, our drilling and development operations in offshore Guyana are unaffected by that incident.
And I think it’s also important to know that exploration and development drilling is continuing in the Southeast area of the Stabroek Block. Greg just talked about that. The activities related to Liza Phase 1 development, which is expected to be producing up to 120,000 barrels oil a day in early 2020 also unaffected. And in terms of where it goes from here, it will be going to an international court. The UN fully supports Guyanese position. The United States supports the Guyanese position, as well as the CARICOM. So, this is an issue that is diplomatic that will have to be handled through the court, but at the end of the day we're very optimistic and encouraged that the Guyanese position will prevail.
Okay, thank you very much. One more question on the Bakken, can you, it sounds like you can get about 70% of your barrels to the Gulf, what percentage is pipeline versus rail and is that mix going to change at all in 2019 or 2020?
So, what we have right now is approximately 50,000 barrels a day that goes on DAPL. So that can get to Patoka, it can get to [Netherland], you can export from there. Then we have approximately from the rail that can go east, west or Gulf Coast. You've got like 25,000 to 30,000 barrels a day on rail that we can move. So that's basically how we get to the Gulf – to the various coasts and get the Brent-link pricing.
And we will – there are multiple potential expansions going out such as DAPL and we'll continue to look to keep that competitive advantage as our Bakken production grows to again access more of those Gulf – I keep saying Gulf, but coast pricing to get Brent-link pricing on our crude. So, we are looking at some of these expansions such as DAPL.
So, you looked at the future of the majority of our movements to market our Bakken crude will be through pipeline and the rail will be there for flex.
Okay, perfect. Thanks guys.
Thank you. Our next question is from the line of Pavel Molkanov of Raymond James. Your line is open.
Thanks for taking the question guys. Back to the general topic of takeaway capacity in the Bakken, any issues with gas flaring or anything around those lines that are facing constraints as you continue to ramp volumes?
No, we don't anticipate any gas flaring restrictions as we ramp our volumes. We have adequate capacity in place.
Okay. And then just a quick one on buyback, having completed the previous authorization in Q4 as you mentioned is it fair to say that no additional buyback is envisioned as part of the 2019 capital allocation?
Our first second and third priority is to maintain a strong cash and balance sheet position, ample liquidity to ensure that we can fund our world-class investment opportunities in Guyana and the Bakken without the need for further debt or equity financing by the way. As we transition from our investment phase and our portfolio begins to generate recurring free cash flow, and you go forward in time out to 2025. We plan to return the majority of that free cash flow to shareholders through higher dividends and opportunistic share repurchases.
Alright. Very good, appreciate it.
Thank you. And our next question is from the line of John Herrlin of Societie Generale. Your line is open.
Hi, just some unrelated ones. With reserve additions this year you said they were primarily Bakken where most of the addition is extensions Greg?
It was actually a mixture John of extensions and add. So, generally with the ads you're going to get the extra year in the five-year program, so we’re going to get those ads. Then you get some of these technical ones where you could have had in a program well A, in the previous year and now well A, is out, you got well B, so you get ads versus revisions, but you do get the additional year of the pods and then you get some revisions pick up. The prices were higher, so you do pick up some revisions from that as well.
Okay. Would you ever consider discussing your captive resource base given the fact that reserve additions are going to be lagged in Guyana and it’s so large and you do have other resource potential elsewhere because it's not something you frequently discuss?
No. We don't – we typically don't discuss this like the 6P type resource number, but what we do and as we laid out on Investor Day and Exxon has laid out that we do have greater than 5 billion barrels growth in Guyana. Obviously, we have a 30% working interest. So, people can get the scale of that and as I mentioned we only have 40 million of that booked right now.
And then in the Bakken, obviously with our 15-year well inventory that we have with greater than 50% returns and then we have obviously an inventory of well locations beyond that. So, that's how we give that flavor because to your point, we do believe we have a real good competitive advantage with our backlog, our resources and reserve position.
Greg. And the estimated EUR in the Bakken is somewhere around 2.3 billion barrels there as well.
Thanks, Greg. Since, John was answering a lot of the questions, where do you capitalize on this year in terms of interest expense for 2019?
John, I'm going have to dig that one out.
We can do it off-line that’s fine.
Yes, maybe I can get back to you off-line on exactly what that is.
Yes. That's fine. And then the last one for me as for 2018 costs incurred. Could you give us a sense of what was exploration? What was development?
So, from our cost incurred standpoint in 2018. Our exploration spend was $440 million.
Okay, great. Thanks.
Thank you.
Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.