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Hess Corp. (HES) Q4 2018 Earnings Conference Call Transcript

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Hess Corporation (NYSE: HES)
Q4 2018 Earnings Conference Call
Jan. 30, 2019, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good day ladies and gentlemen, and welcome to the 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. If at any time, you require operator assistance, please press * followed by 0, and we will be happy to assist you. 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.

Jay Wilson -- Vice President of Investor Relations

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 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's annual and quarterly reports filed with the SEC. Also, on today's conference call, we may discuss certain non-gap financial measures. A reconciliation of the differences between these non-gap financial measures and the most directly comparable gap 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.

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John Hess -- Chief Executive Officer

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 as our cash engines. As we discussed at our recent Investor Day, our portfolio is positioned 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 $40.00 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 $60.00 WTI PUD 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 at an exciting inflection point, transitioning from an investment phase in 2019 to a free cash flow generation phase beginning in 2020, with the 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 planned 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 five billion barrels of oil equivalent, with multi-billion barrels of additional exploration potential.

Earlier this month, drilling began on the Himara-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 -- Puyara -- is expected toward 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 $12.00 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 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 toward increased return of capital to our shareholders. I will now turn the call over to Greg.

Greg Hill -- Chief Operating Officer

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 245,000-255,000 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 interests 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 of exploration success with five 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 a world-class investment opportunity in every respect -- the combination of scale, exceptional reservoir quality, shallow producing horizons, and timing of the development in the cost cycle provide industry-leading break-evens, which is key to moving Hess toward a $40.00 per barrel Brent breakeven oil price by 2025, while delivering significant growth, and 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 $60.00 per barrel WTI. Through field trials, and an independent study, we confirmed that our plan 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 interests 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 about 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 of 2018, production averaged 117,000 net barrels of oil equivalent per day, in line with full-year guidance of 115,000-120,000 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 130,000-135,000 net barrels of oil equivalent per day. In 2019, we plan to drill approximately 170 wells, and bring approximately 160 new wells on-line, compared to 121 wells drilled, and 104 wells brought on-line in 2018.

Moving off-shore -- 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 of 2018 -- above our guidance, reflecting strong performance from our new Penn State Deep No. 6 Well, and the early return to production of the Conger field. We forecast 2019 production from our deep-water 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 in 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 in 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 JVA 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 Himara-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 three 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 completive drilling operations on these wells, the Stena Carron will conduct the drill-stem tests at the Longtail discovery, and the Noble Tom Madden will drill an additional exploration well in 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 multi-billion barrels of exploration upside, will also be prioritized for the drill schedule.

The LIZA Phase 1 development is progressing to schedule. Drilling in Phase 1 development wells in LIZA field by the Noble Bob Douglas drillship is well advanced. Sub-sea equipment is being prepared for installation, and the topside facility's modules are being installed on the LIZA Destiny FPSO in Singapore. Preparations are under way for the installation of sub-sea umbilicals, risers, and flow lines in the second quarter, and the LIZA Destiny FPSO is expected to sail from Singapore, and arrive off-shore 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 Puyara 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.

John Rielly -- Chief Financial Officer

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 expiration costs 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 non-controlling interest amounted to $127 million in the fourth quarter, compared to $130 million in the previous quarter.

For corporate: after-tax corporate 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 $5,691,000,000.00 at December 31st, 2018. Cash flow from operations before working capital changes was $585 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 decrease 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 costs -- excluding Libya -- to be in the range of $12.50-$13.50 per barrel of oil equivalent in the first quarter of 2019, and $13.00-$14.00 per barrel of oil equivalent for full year 2019 -- which includes cost 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 $18.00-$19.00 per barrel of oil equivalent for the first quarter of 2019, and for the full year of 2019. This results in projected E&P operating costs -- excluding Libya -- of $30.50-$32.50 per barrel of oil equivalent for the first quarter, and $31.00-$33.00 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 $45-55 million in the first quarter, with full year 2019 forecast to be in the range of $200-220 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 $750-775 million. The E&P effective tax rate -- excluding Libya -- is expected to be an expense in the range of 0-4% in 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 year 2019, with $60.00 WTI PUD 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 $170-180 million. Turning to corporate: for the first quarter of 2019, corporate expenses are estimated to be in the range of $25-30 million, and full-year guidance to be in the range of $105-115 million. Interest expenses are estimated to be in the range of $80-85 million in the first quarter, and in the range of $315-325 million for the full year of 2019.

This concludes my remarks. We will happy to answer any questions. I will now turn the call over to the operator.

Questions and Answers:

Operator

Well, ladies and gentlemen, if you have a question, please press * followed by 1 on your phone. If your question has been answered, or if you wish to withdraw your question, press the # key. Questions will be taken in the order received. Please press *1 to begin.

Our first question is from the line of Doug Leggate of Banc of America Merrill Lynch -- your line is open.

Doug Leggate -- Banc of America Merrill Lynch -- Research Analyst

Thanks -- good morning, everybody. John Rielly, the capex plan obviously hasn't changed, given you only put it out a few weeks back -- but given the dynamics of the oil price, what would it take -- I guess given the hedge position you're in -- what would it take for you 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.

John Rielly -- Chief Financial Officer

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 in a really nice place from all the -- 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 our -- with the proceeds from the asset sales? We've left $2.6 billion of cash on the balance sheet, and we had the hedges in place for 2019 -- and that's 95,000 barrels of oil per day -- with the $60.00 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, it would have to go more into 2020, you know -- the tail end of '19 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 on Investor Day.

Doug Leggate -- Banc of America Merrill Lynch -- Research Analyst

Okay, I appreciate it -- obviously, we're not expecting it at this point, but we'll keep an eye on it. My follow-up, if I may, is on exploration -- and it's kinda a couple-part question, I guess. The Tom Madden, as I understand it, was only contracted for two well slots. I was just wondering if that has now been extended, and -- if so -- what you have in the plan for this year, by way of total exploration wells. Now, I realize that can move around -- with well tests, and so on -- and if I may, just on that last point -- Greg, I wonder if you can characterize Himara for us -- in terms of scale. It looks like a big green blob to the East of Turbot Longtail, but -- as you probably saw from our note the other day -- our understanding is that -- the service sector's telling us that is already under tests, which would imply discovery -- so anyway, any confirmation, or color you could offer around that would be appreciated. Thanks.

Greg Hill -- Chief Operating Officer

Yeah, thanks, Doug. So -- Himara's operations are currently under way, 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 -- kinda -- what we find, and testing, and etc. -- 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 objective to really -- to underpin vessels four and five -- where are they? How big are they, etc. So those are our main objectives this year, and we'll do that with two rigs in the exploration/appraisal theater.

Doug Leggate -- Banc of America Merrill Lynch -- Research Analyst

Just to be clear -- the $200 million guide -- that's a D&D cost, not a dry hole cost, right?

John Rielly -- Chief Financial Officer

I'm sorry, Doug -- the $200 million guide from --?

Doug Leggate -- Banc of America Merrill Lynch -- Research Analyst

Yeah, the guidance that you suggested -- I think for exploration -- that's D&D, not dry hole?

John Rielly -- Chief Financial Officer

Okay, so our exploration spend for 2019 is gonna be $440 million -- that's what we laid out in Investor Day.

Doug Leggate -- Banc of America Merrill Lynch -- Research Analyst

Sorry, I thought I heard you --

[Crosstalk]

John Rielly -- Chief Financial Officer

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 '19.

Doug Leggate -- Banc of America Merrill Lynch -- Research Analyst

Right -- got it. Thank you.

Operator

Thank you. Our next question is on the line of Brian Singer of Goldman Sachs -- your line is open.

Brian Singer -- Goldman Sachs -- Managing Director

Thank you -- good morning.

John Hess -- Chief Executive Officer

Morning.

Brian Singer -- Goldman Sachs -- Managing Director

I wanted to follow-up, actually -- on the points on Guyana you were just talking about, with regards to appraisal. To what degree does the appraisal program -- over the next six to nine months -- as you said, just underwrite FPSOs four to five, versus open up the door for additional FPSOs beyond five, or -- is the emphasis on the "plus?"

So five-plus FPSOs, or expansion beyond five contingent on exploration, as opposed to appraisal success?

Greg Hill -- Chief Operating Officer

Yeah, Brian, so -- the answer is both. I mean -- as I said in my remarks earlier -- one of the primary intentions of the program this year is to underpin vessels four and five. So -- where are they? We know that there will be one or more -- potentially -- in the Turbot complex. There's likely to be one or more in the Hammerhead, and then -- finally, Ranger. 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 four and five underpinned, obviously, because we wanna 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.

Brian Singer -- Goldman Sachs -- Managing Director

Great -- thanks, and then -- my follow-up is the -- with reduction to Bakken. Can you just give us the latest that you're seeing, in terms of the service cost environment -- maybe -- unrelated to your shift to 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.

Greg Hill -- Chief Operating Officer

Yes, I'll take the service cost. I guess first point, Brian -- is 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 5-10% on average in the Bakken in 2019. Most of that's in the form of higher labor costs, but -- having said that -- 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, that we'll 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.

John Rielly -- Chief Financial Officer

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 like, +$0.78 of TI to -$8.30 per barrel -- and that was due to about 1 million barrels of demand going away, just due to refinery maintenance. So now that the refineries are back online, the differentials are back around normal. They've been $1.00 above to $1.00 under, and so we're just seeing more of the normal type of Bakken differentials -- and [inaudible] 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 on pipelines, and rail.

Brian Singer -- Goldman Sachs -- Managing Director

Thank you.

Operator

Thank you -- and our next question is on the line of Ryan Todd of Simmons Energy -- your line is open...and Mr. Todd, your line might be on mute. Your line is open.

Ryan Todd -- Simmons Energy -- Senior Research Analyst

Sorry, I apologize for that. A couple 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?

John Rielly -- Chief Financial Officer

So, in the fourth quarter, it was 13 that were plug-and-perfs that came online, and then -- as we said -- basically, going forward, it's almost 100%. We could have some carryover sliding sleeves coming online, but really -- all our program is plug-and-perf, and I'll turn it over to Greg on performance from the plug-and-perf.

Greg Hill -- Chief Operating Officer

Sorry -- I was on mute for a second. Just a reminder -- the high-intensity plug-and-perf completions are expected to deliver a 15-20% increase in IP 180 -- at least a 5% increase in the UR. That increases our plateau production to 200,000 barrels a day from the previously guided 175,000 -- and importantly, an increase in overall Bakken MPV, by over $1 billion -- at $60.00 per barrel, WTI. And what I will say is that results -- so far -- indicate that we're meeting, or beating expectations on IP rates, so we're in good speed going forward.

Ryan Todd -- Simmons Energy -- Senior Research Analyst

All right -- that'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 I've asked you, from quarter to quarter, but -- anything on those two things?

Greg Hill -- Chief Operating Officer

No, 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.

John Rielly -- Chief Financial Officer

And then -- just going to the oil cut to -- and I know the way you asked your question -- you're right, oil cut is going to fluctuate quarter-on-quarter -- really due to changes in gas volumes, captured NGLs 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.

Ryan Todd -- Simmons Energy -- Senior Research Analyst

Perfect -- I appreciate the help. Thanks, guys.

Operator

Thank you; our next question is from the line of Jeffrey Campbell of Tuohy Brothers. Your line is open.

Jeffrey Campbell -- Tuohy Brothers -- Senior Analyst

Good morning, and congratulations on the quarter.

John Hess -- Chief Executive Officer

Thank you.

Jeffrey Campbell -- Tuohy Brothers -- Senior Analyst

I was just wondering -- could you add some kind of color, with regard to the Guyana 2019 well test program -- specifically how that's going to help you confirm, or eliminate development options for the future?

Greg Hill -- Chief Operating Officer

Well, I think --you know, the purpose of the testing program -- the primary purpose is always to establish reservoir continuity, so is there any compartmentalization, or anything 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 four and five -- to have some tests under your belt, to understand how many wells will it take to evacuate those reservoirs, so -- yeah, so that'll be the purpose -- again -- is looking at four and five, the majority of the testing will be to do that, or new discoveries that we would like to get a drill stem test in while we're there.

Jeffrey Campbell -- Tuohy Brothers -- Senior Analyst

Okay, thank you -- and I'm 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 kinda wondering how you're gonna distribute the rigs around, and the completion [crosstalk].

Greg Hill -- Chief Operating Officer

Yeah, so -- if you think about the 160 wells online that we're gonna drill -- about 45 of those will be in Keene; about 30 of them will be in Stony Creek; 40 or so will be in East Nesson, and then 20 will be in the Beaver Lodge -- kinda Kappa area -- and then we have another 25 miscellaneous wells that are really spread out to try different loadings, etc. -- so kinda test wells in other parts of the field.

Jeffrey Campbell -- Tuohy Brothers -- Senior Analyst

And just a moment, Paul -- no, just a moment -- on the 25 -- is that -- I know that other operators the Bakken have talked about this, as well. Is that -- sort of -- an effort to try more modern completions -- maybe in areas where you haven't done it recently, to see if you can push those EURs up?

Greg Hill -- Chief Operating Officer

Yeah, I think so -- and those 25 wells -- we're gonna do about 11 in Goliath, and 14 in Red Sky, so -- really, that's as you kinda move out, how do we think about profit loading, and -- potentially even spacing in those areas of the fields? So we wanna get some of that experience under our belts this year, but if you look at the program for this year, the IP 180s are gonna average 120-125, and -- certainly, the EURs'll be well north of 1 million barrels for the program -- so a good healthy program, and returns in the 50-100% range.

Jeffrey Campbell -- Tuohy Brothers -- Senior Analyst

Okay, great-I appreciate that color. Thank you.

Operator

Thank you -- and our next question comes from the line of Bob Brackett of Bernstein Research. Your line is open.

Bob Brackett -- Bernstein Research -- Senior Research Analyst

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 election down in Guyana?

John Hess -- Chief Executive Officer

Let's end with two ways -- you know, with the recent no-confidence vote -- and the election's still being scheduled -- there is absolutely no impact to our exploration, or our 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 is just a question of getting a third-party engineering firm in place -- which is under way -- 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.

Bob Brackett -- Senior Research Analyst

Yeah, that's clear. Related to follow up -- that the F&D of under $12.00 a barrel is quite strong. If you look back to the 2017, that was an amazing $5.00 a barrel, as those LIZA bookings came through. How do we think about the cadence of Guyana reserves bookings -- either on project sanction, or then -- production-related revisions, as we go forward?

John Rielly -- Chief Financial Officer

Sure, Bob. We -- I mean, we really believe we have a 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 did8 not book any barrels here in 2018. So in Phase 2 -- as John says -- get sanctioned; we will pick up barrels then. Phase 3 is -- as Exxon is saying -- 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 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 costs associated with that. So -- let alone the scale, and just the uniqueness of the low-cost reserves -- it just puts us in a terrific competitive advantage.

Bob Brackett -- Senior Research Analyst

Great -- and thanks for that color.

Operator

Thank you -- and our next question comes from the line of Roger Read of Wells Fargo -- your line is open.

Roger Read -- Wells Fargo -- Senior Energy Analyst

Yeah, thanks -- good morning [crosstalk]. 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 terms8 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?

John Hess -- Chief Executive Officer

Yes, as I think I mentioned in my opening remarks -- the cadence of when the vessel will show up, and whatnot -- we are on schedule to do that -- so there are no issues foreseen yet. We're on schedule to get the vessel on location. I think the next thing to watch is all 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'll ramp those wells up over a four to six month period -- so it won't be an instantaneous ramp. The reason for that is -- you'll bring them on slow just to make sure that you don't have any sand control issues, so it'll be a ramp of four to six months, according to the operator.

Roger Read -- Wells Fargo -- Senior Energy Analyst

Yeah, of course -- I 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 it in the original commentary, but -- what's been done, or could be done for 2020 -- or what do you envision -- maybe -- needing to do for 2020, if the opportunity to hedge at $60.00 were to present itself again?

John Rielly -- Chief Financial Officer

Oh, yes, we will continue to look to add hedges as we move into 2020, or '21. From -- 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 can 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 $60.00 WTI floor for '19 -- once we look to 2020, we will look to put on hedges, as well -- to add insurance.

John Hess -- Chief Executive Officer

Yeah, and I think it's important to note that the structure we'd use would be similar, where we'd protect the downside, but we don't cap the upside.

Roger Read -- Wells Fargo -- Senior Energy Analyst

Okay, great -- thank you.

Operator

Thank you -- and our next question comes from the line Paul Cheng of Barclay's. Your line is open.

Paul Cheng -- Barclays -- Analyst

Hey, guys -- good morning.

John Hess -- Chief Executive Officer

Morning.

Paul Cheng -- Barclays -- Analyst

John Reilly, I have to apologize there -- you gave a number about the amortization cost for the quarter for the hedges -- is that $29 million after tax?

John Rielly -- Chief Financial Officer

Yes, that is $29 million after tax.

Paul Cheng -- Barclays -- Analyst

Okay, John -- just curious there -- have you, or Exxon have ever reached out to the opposition party, and see -- what is their current view about the contract, and everything?

John Hess -- Chief Executive Officer

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.

Paul Cheng -- Barclays -- Analyst

And that -- based on the current trend, when the consortium will start developing natural gas for the local market?

Greg Hill -- Chief Operating Officer

Paul, that project is still under review, and under discussion with the government. I mean, we're doing some early engineering studies to figure out what it will take, but -- in any case, it'll be a small amount of -- 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.

Paul Cheng -- Barclays -- Analyst

Right -- great, so that saved me some reading, through, then -- Thai PSC -- is that being specified in the PSC, in terms of the scope, and the when that gas market needs to be developed?

Greg Hill -- Chief Operating Officer

No, it's still -- all that's still under discussion with the government.

Paul Cheng -- Barclays -- Analyst

Okay, so that is actually subject to discussion; it's not framed, then -- in the PSC.

Greg Hill -- Chief Operating Officer

No, I think we've agreed for the necessity for it -- but timing, and how it all is gonna work, and all that has yet to be determined.

Paul Cheng -- Barclays -- Analyst

Okay -- and the Bakken -- at 200,000 barrels per day -- of the peak -- how many years, then, can you sustain, based on the full rig?

Greg Hill -- Chief Operating Officer

Four to five.

Paul Cheng -- Barclays -- Analyst

Four to five rigs. No, I mean, how many years are you Results is four to five years?

[Crosstalk]

Greg Hill -- Chief Operating Officer

Based on what we know today. I mean, four rigs -- but four to five years, at a peak -- obviously, based on what we know today -- completion technology could get better. I mean, there's lots of things that could get better that could extend that.

Paul Cheng -- Barclays -- Analyst

But the current -- based on what you know today, the results is four to five years on that?

Greg Hill -- Chief Operating Officer

Right -- on that -- roughly 200,000 barrel-a-day peak, at a four-rig level, so -- let me be clear about that.

Paul Cheng -- Barclays -- Analyst

John Rielly, then -- on the Midstream, can you tell us, then -- what is the expected capex for 2019, and '20?

John Rielly -- Chief Financial Officer

For '19, the Midstream has put out its guidance; it's $275-300 million of capex for Midstream. There is some small amounts that aren't in that Midstream -- related to water assets, because the water asset sale will -- is expected to close in the first quarter. That's approximately $25-30 million, on top of that -- but that's the gross amounts that I was giving you.

Paul Cheng -- Barclays -- Analyst

Okay. How about 2020 -- any kind of rough number?

John Rielly -- Chief Financial Officer

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.

Paul Cheng -- Barclays -- Analyst

Okay, thank you.

Operator

Thank you, and our next question comes from the line of Ross Payne of Wells Fargo -- your line is open.

Ross Payne -- Wells Fargo -- Managing Director

How 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.

John Hess -- Chief Executive Officer

Drilling and development operations in offshore Guyana are unaffected by the incident that involved the seismic acquisition vessels on Saturday, December 22nd, 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 ten 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's talked about that -- the activities related to LIZA Phase 1 development -- which is expected to be producing up to 120,000 barrels of oil a day in early 2020 -- also unaffected, and -- in terms of where it goes from here -- it'll be going to an international court.

The UN fully supports the Guyanese position; the United States supports the Guyanese position, as well as the Caracom, so this is an issue that is diplomatic -- that'll 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.

Ross Payne -- Wells Fargo -- Managing Director

Okay, thank you very much. And -- one more question on the Bakken: can you -- 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 '19,or '20?

Greg Hill -- Chief Operating Officer

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 Nederland; you can export from there. Then you have approximately -- from the rail that can go East, West, or Gulf Coast -- you've got like, 25,000-30,000 barrels a day on rail that we can move. So that's basically how we get to the Gulf -- I mean, to the various coasts, and get the Brent pricing.

Ross Payne -- Wells Fargo -- Managing Director

Okay.

[Crosstalk]

Greg Hill -- Chief Operating Officer

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 Brentling pricing on our crude -- so we are looking at some of these expansions, such as DAPL.

John Hess -- Chief Executive Officer

Yeah, so you look to the future -- the majority of our movements to market our Bakken crude will be through pipeline, and the rail will be there for flex.

Ross Payne -- Wells Fargo -- Managing Director

Okay, perfect. Thanks, guys.

Operator

Thank you. Our next question is from the line of Pavel Molchanov of Raymond James -- your line is open.

Pavel Molchanov -- Raymond James -- Analyst

Thanks for taking the question, guys. Kind of -- back to the general topic of takeaway capacity in the Bakken: any issues with gas flaring, or anything around those lines, that are safety constraints, as you continue to ramp volumes?

Greg Hill -- Chief Operating Officer

No, we don't anticipate any gas flaring restrictions as we ramp our volumes. We have adequate capacity in place.

Pavel Molchanov -- Raymond James -- Analyst

Okay -- and then -- just a quick one on buyback: having completed the previous operation in Q4 -- as you mentioned -- is it fair to say that no additional buyback is envisioned, as a part of the 2019 capital allocation?

John Hess -- Chief Executive Officer

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.

Pavel Molchanov -- Raymond James -- Analyst

All right -- very good. Appreciate it.

Operator

Thank you -- and our next question is from the line of John Herrlin of Société Général -- your line is open.

John Herrlin -- Société Général -- Analyst

Yeah, hi -- just some unrelated ones. With the reserve additions this year -- you said they were primarily Bakken -- were most of the additions extensions, Greg?

Greg Hill -- Chief Operating Officer

I was actually a mixture, John -- of extensions and adds. So -- generally, with the adds, you're gonna get the extra year in the five-year programs -- you're gonna get those adds, then you get some of these technical ones, where you could have had -- in a program -- Well A in a previous year, and now Well A's out -- and you got Well B, so you get adds, versus revisions, but you do get the additional year of the PUDS, and then you get -- some revisions pick up. Prices were higher, so you do pick up some revisions from that, as well.

John Herrlin -- Société Général -- Analyst

Okay -- would you ever consider discussing your captive resource base, given the fact that reserve additions are gonna 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.

Greg Hill -- Chief Operating Officer

No, we don't -- we typically don't discuss like, the 6-P 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 gross 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 really good competitive advantage with our backlog -- our resources, and reserve position.

John Herrlin -- Société Général -- Analyst

Great --

[Crosstalk]

Greg Hill -- Chief Operating Officer

And the estimated EUR on the Bakken is somewhere around 2.3 billion barrels there, as well.

John Herrlin -- Société Général -- Analyst

Thanks, Greg. Since John was answering a lot of the questions, what are you capitalizing this year, in terms of interest expense for 2019?

John Rielly -- Chief Financial Officer

John, I'm gonna have to dig that one out.

John Herrlin -- Société Général -- Analyst

We can do it offline; that's fine.

John Rielly -- Chief Financial Officer

Yeah, maybe I can get back to you offline on exactly what that is.

John Herrlin -- Société Général -- Analyst

Yeah, that's fine -- and then the last one for me is: for 2018 costs incurred, could you give us a sense of what was exploration -- what was development?

John Rielly -- Chief Financial Officer

So from our costs incurred standpoint in 2018, our exploration spend was $440 million.

John Herrlin -- Société Général -- Analyst

Okay, great -- thanks.

John Hess -- Chief Executive Officer

Thank you.

Operator

Thank you very much; this concludes today's conference. Thank you for your participation; you may now disconnect. Have a great day.

Duration: 57 minutes

Call participants:

Jay Wilson -- Vice President of Investor Relations

John Hess -- Chief Executive Officer

Greg Hill -- Chief Operating Officer

John Rielly -- Chief Financial Officer

Doug Leggate -- Banc of America Merrill Lynch -- Research Analyst

Brian Singer -- Goldman Sachs -- Managing Director

Ryan Todd -- Simmons Energy -- Senior Research Analyst

Jeffrey Campbell -- Tuohy Brothers -- Senior Analyst

Bob Brackett -- KeyBank -- Senior Research Analyst

Roger Read -- Wells Fargo -- Senior Energy Analyst

Paul Cheng -- Barclays -- Analyst

Ross Payne -- Wells Fargo -- Managing Director

Pavel Molchanov -- Raymond James -- Analyst

John Herrlin -- Société Général -- Analyst

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