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Hess Corp (HES) Q3 2020 Earnings Call Transcript

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Hess Corp (NYSE: HES)
Q3 2020 Earnings Call
Oct 28, 2020, 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 Third Quarter 2020 Hess Corporation Conference Call. My name is Andrew and I'll be your operator for today. [Operator Instructions] I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Jay R. Wilson -- Vice President, Investor Relations

Thank you, Andrew. Good morning, everyone and thank you for participating in our third quarter earnings conference call. Our earnings release was issued this morning and appears on our website at 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 Factor section of Hess's 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.

John B. Hess -- Chief Executive Officer

Thank you, Jay. Welcome to our third quarter conference call. I hope you and your families are well and staying healthy during these challenging times. Today, I will provide an update on our progress in executing our strategy in the current low oil price environment. Then, Greg Hill will discuss our operations and John Rielly will review our financial results.

Before we address this quarter, I would like to talk briefly about the macro outlook for oil and how it informs our strategy. The International Energy Agency just published its 2020 World Energy Outlook that provides an aggressive sustainable development scenario in which if all the pledges of the Paris Climate Agreement are met, oil and gas would still be 46% of the energy mix in 2040. The energy transition will take time and major breakthroughs in technology will be needed. While we need policies to encourage renewable energy to battle climate change, oil and gas will be needed for many decades to come and will continue to be fundamental to world economic growth and human prosperity.

The key for our company is to have a low cost of supply in any price environment. By investing only in high-return, low-cost opportunities, we have built a differentiated portfolio of assets that we believe will provide industry-leading cash flow growth over the course of the decade, which is superior to our peers and to most companies in the S&P 500. Our portfolio is underpinned by significant cash engines in the Bakken, deepwater Gulf of Mexico and Southeast Asia as well as multiple phases of low-cost Guyana oil developments, which we believe will drive our company's breakeven price to under $40 per barrel Brent by mid-decade. To realize our long-term strategy, we must manage the short-term challenges facing our industry. Our priorities during this low-price environment are to preserve cash, preserve capability and preserve the long-term value of our assets.

In terms of preserving cash, we came into 2020 with approximately 80% of our oil production hedged with put options for a 130,000 barrels per day at $55 per barrel West Texas Intermediate and 20,000 barrels per day at $60 per barrel Brent.

To enhance cash flow and maximize the value of our production, in March and April when U.S. oil storage was near capacity, we chartered three very large crude carriers or VLCCs to store 2 million barrels each of May, June and July of Bakken crude oil production. The first VLCC cargo of 2.1 million barrels was sold in China at a premium to Brent in September. The second and third VLCC of our cargoes are expected to be sold in Asia, by the end of the year. We have also reduced our 2020 capital and exploratory budget by 40%, from $3 billion to our current revised guidance of $1.8 billion, primarily by reducing our Bakken rig count from 6 to 1 and we reduced our full-year 2020 cash operating costs by $275 million. At the end of September, we had $1.28 billion of cash, a $3.5 billion dollar undrawn revolving credit facility and no debt maturities until the term loan comes due in 2023.

In terms of preserving capability, we have been operating one rig in the Bakken since May, down from 6 rigs at the beginning of the year. To maintain the lean manufacturing capabilities and innovative practices that Greg and his team have built more -- for over more than 10 years. Our plan is to remain at one rig until oil prices approach $50 per barrel WTI. Before reducing the rig count, we achieved our goal of 200,000 barrels of oil equivalent per day, 6 months ahead of schedule. In addition, our Bakken team has cut our average drilling and completion costs below $6 million per well and we continue to see further opportunities for cost reductions.

In terms of preserving the long-term value of our assets, Guyana, with its low cost of supply and industry-leading financial returns, remains our top priority. We are very pleased that on September 30, the government of Guyana approved the development plan for the Payara Field, the third oil development on the Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator.

Payara is targeted for first oil in 2024 and we expect to have at least 5 FPSOs on the block producing more than 750,000 gross barrels of oil per day by 2026. The three-sanctioned oil developments, Liza-1, which is producing and Liza-2 in Payara, which are in construction, have breakeven Brent oil prices of between $25 and $35 per barrel, which are world-class by any measure.

On September 8th, we also announced the Redtail and Yellowtail-2 discoveries, bringing total discoveries on the block to 18, incorporating the current assessment of additional volumes from the Redtail, Yellowtail-2 and Uaru discoveries. We are increasing the estimate of gross discovered recoverable resources for the Stabroek Block to approximately 9 billion barrels of oil equivalent. We also now see the potential for up to five -- 10 FPSOs to develop the current discovered recoverable resource base.

We announced on October 5th, an agreement to sell our 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico to BHP Billiton, the field's operator, for a total consideration of $505 million at an effective date of July 1, 2020. This transaction brings value forward in the low price environment and further strengthens our cash and liquidity position until the lease of Phase 2 development in Guyana comes online in early 2022. We expect to close the transaction before the end of the year. Our strategy will continue to be guided by our company's long-standing commitment to sustainability, which we believe creates value for all our stakeholders.

Earlier this month, the transition pathway initiative or TPI published its 2020 report on the progress of a 163 energy companies in transitioning to a low-carbon economy and supporting efforts to mitigate climate change in line with the task force on climate-related financial disclosures or TCFD recommendations. In TPI's 2020 report, Hess is the only U.S. oil and gas company to achieve a level 4-star rating, which is only awarded to companies that demonstrably manage climate-related risks and opportunities from a governance, operational and strategic perspective and satisfy all TPI management quality criteria.

In summary, we continue to execute our long-term strategy, delivering strong operational performance while prioritizing the preservation of cash, capability and the long-term value of our assets during this low price environment. As a result, Hess is uniquely positioned to deliver industry-leading cash flow growth and financial returns over the decade. As our portfolio generates increasing free cash flow, we will prioritize debt reduction and increasing cash returns to our shareholders.

I will now turn the call over to Greg for an operational update.

Gregory P. Hill -- President and Chief Operating Officer

Thanks, John. In the third quarter, we once again delivered strong operational performance. Companywide net production averaged 321,000 barrels of oil per day, excluding Libya, which was within our guidance range of 320,000 to 325,000 barrels of oil equivalent per day.

Bakken net production averaged 198,000 barrels of oil equivalent per day, up 21% from the prior year quarter and above our guidance of approximately 185,000 barrels of oil equivalent per day. Our strong Bakken performance offset hurricane-related downtime in the Gulf of Mexico, where production for the quarter averaged 49,000 barrels of oil equivalent per day, just below our guidance range of 50,000 to 55,000 barrels of oil equivalent per day.

In the fourth quarter, we expect companywide net production to be approximately 300,000 barrels of oil equivalent per day excluding Libya. This guidance assumes that the Shenzi sale closes December 1st and that transitory hurricane-related impacts in the Gulf of Mexico will reduce production in the fourth quarter by approximately 25,000 barrels of oil equivalent per day. We anticipate all hurricane recovery work to be completed before the end of the year, which will allow our shut-in Gulf of Mexico production to be fully restored. For the full-year 2020, our net production guidance is approximately 325,000 barrels of oil equivalent per day excluding Libya, compared to our previous guidance of 330,000 net barrels of oil equivalent per day.

Moving to the Bakken. In the third quarter, we drilled six wells and brought 22 new wells online. For the fourth quarter, we expect to drill six wells and bring 11 new wells online. And for the full-year 2020, we still expect to drill 70 wells and bring 110 new wells online. In the third quarter, efficiency gains enabled us to further reduce our average drilling and completion cost per well to $5.9 million, which we believe is top quartile for the Bakken. Through the continued application of technology and lean manufacturing techniques, we expect to reduce our D&C cost even further.

For the fourth quarter, we expect Bakken net production to average between 180,000 and 185,000 barrels of oil equivalent per day. For the full year 2020, we now expect Bakken net production to average approximately 190,000 barrels of oil equivalent per day, up from our previous guidance of 185,000 barrels of oil equivalent per day. Although we have a large inventory of future drilling locations that generate good financial returns at current prices, to preserve capital discipline and keep the asset free cash flow positive, we plan to maintain a one-rig program until oil prices approach $50 per barrel WTI. Operating a single rig allows us to preserve our lean manufacturing capability that we have worked hard to build over the years, both within Hess and among our primary drilling and completion contractors.

Moving to the offshore. The Gulf of Mexico has felt the effects of seven named storms this season, including Hurricane Zeta, which is currently in the Gulf, that have disrupted operations across the industry. Production from the Conger and Llano fields is expected to remain shut-in for approximately 40 and 75 days respectively during the fourth quarter due to hurricane recovery work and the Penn State-6 well will remain shut-in until a workover can be completed in December.

In the fourth quarter, Gulf of Mexico net production is expected to average approximately 40,000 barrels of oil equivalent per day. And for the full-year 2020, we expect net production to be in the range of 55,000 to 60,000 barrels of oil equivalent per day, down from our previous guidance of 65,000 barrels of oil equivalent per day. Again, we expect all hurricane impacted production to be fully restored before the end of the year. Also on the Gulf, in September, the Esox-1 well reached a gross peak rate of approximately 17,000 barrels of oil equivalent per day or 9,000 barrels of oil equivalent per day net to Hess. The BP operated Galapagos Deep exploration well, in which Hess held a 25% working interest was not a commercial success. The data from this well in the play will be incorporated into the continued assessment of our acreage position in the Cretaceous, which remains highly prospective.

Moving to the Gulf of Thailand. Net production in the third quarter increased to an average of 50,000 barrels of oil equivalent per day compared to 44,000 barrels of oil equivalent per day in the second quarter as a result of higher nominations. We expect fourth quarter net production to be flat with the third quarter at approximately 50,000 barrels of oil equivalent per day, reflecting continued COVID uncertainties. Our guidance for full year 2020 net production is now approximately 50,000 barrels of oil equivalent per day compared to our previous guidance range of 50,000 to 55,000 barrels of oil equivalent per day.

Now turning to Guyana. In the third quarter, gross production from Liza Phase 1 averaged 63,000 barrels of oil per day or 19,000 barrels of oil per day net to Hess. Ongoing work to complete commissioning of the natural gas injection system continues and once complete will enable the Liza Destiny floating production storage in offloading vessel or FPSO to reach its nameplate capacity of a 120,000 gross barrels of oil per day in December. It is important to note that the delays in commissioning the gas injection system are mechanical in nature and the reservoirs and wells continued to deliver at or above expectations.

The design one build many concept for the FPSOs will allow the learnings to be captured and applied to future projects. Production from the vessel has been averaging approximately 105,000 barrels of oil per day for the last few weeks. The Liza Phase 2 development is progressing the plan, with approximately 80% of the overall top sides whole and subsea work completed. The project will have a gross production capacity of 220,000 barrels of oil per day and remains on track for first oil by early 2022.

In September, we announced the final investment decision to proceed with the development of the Payara field. Payara will utilize the prosperity FPSO, which will have the capacity to produce up to 220,000 gross barrels of oil per day and will initially target a resource base of about 600 million barrels of oil. First oil is expected in 2024. Ten drill centers are planned with a total of 41 wells, including 20 production wells and 21 injection wells. Also, in December, we announced the 17th and 18th discoveries on the Stabroek Block offshore Guyana.

The Yellowtail-2 well encountered 69 feet of high quality oil bearing reservoir, adjacent to and below the Yellowtail-1 discovery. In addition, the Redtail-1 well encountered approximately 232 feet of high quality oil bearing reservoir. The well is located approximately 1.5 miles northwest of the Yellowtail discovery.

A drill stem test is planned at Redtail in the fourth quarter. These discoveries further demonstrate the significant exploration potential of the Block and contribute to the discovered recoverable resource estimate increasing to approximately 9 billion barrels oil equivalent and will likely form the basis of our fourth development on the block.

In terms of exploration, the Stena Carron drillship is currently drilling in the Tanager-1 well on the Kaieteur Block, approximately 46 miles northwest of Liza. This well, which is the deepest well drilled offshore Guyana is designed to penetrate multiple geologic intervals, including the Campanian, Santonian and Toronian. The next exploration well on the Stabroek Block will be Hess-1, which will target Campanian-age reservoirs approximately 30 miles east of the Liza Field. This well should spud near the end of the year and we expect results during the first quarter.

Before I leave Guyana, I think it's important to remind you of what makes the Stabroek Block so unique. First, its size and scale. The block is 6.6 million acres, which is equivalent in size to 1,150 Gulf of Mexico Blocks. So far, we have drilled 20 prospects and have made 18 discoveries. They contain approximately 9 billion barrels of recoverable oil and gas resources, with multi-billion barrels of exploration potential remaining. Secondly, its world-class reservoir quality with exceptional permeability and porosity that results in high flow rates and high recovery factors. Third, the reservoirs are shallow and there is no salt, that allows us to drill wells in a fraction of the time and cost of other deepwater basins. Fourth, there is a production sharing contract with the competitive cost recovery mechanism. Fifth, development is occurring at the bottom of the offshore cost cycle. Excess capacity throughout the offshore supply chain greatly reduces the risk of project delays and cost overruns. Sixth, ExxonMobil is arguably the best project manager in the world for this type of development and their operatorship greatly reduces execution risk. And finally, it's low cost to supply. The first three developments have industry-leading Brent breakeven prices of between $25 and $35 per barrel. For all these reasons, Guyana will create extraordinary long-term value for our shareholders and for the citizens of Guyana.

In closing, I'd like to recognize our team for delivering strong results across our portfolio, while ensuring the safety of our workforce and the communities in the midst of a pandemic and a challenging hurricane season in the Gulf of Mexico.

I will now turn the call over to John Rielly.

John P. Rielly -- Executive Vice President and Chief Financial Officer

Thanks, Greg. In my remarks today, I will compare results from the third quarter of 2020 to the second quarter of 2020. We incurred a net loss of $243 million in the third quarter of 2020, compared with a net loss of $320 million in the second quarter. Excluding items affecting comparability of earnings between periods, we incurred an adjusted net loss of $216 million in the third quarter.

Turning to E&P, on an adjusted basis, E&P incurred a net loss of $156 million in the third quarter of 2020, compared to a net loss of $249 million in the previous quarter. The changes in the after-tax components of adjusted E&P results between the third quarter and the second quarter of 2020 were as follows. Higher realized selling prices improved results by $134 million. Higher sales volumes improved results by $33 million. Higher exploration expenses reduced results by $40 million. Higher cash costs, driven by production taxes reduced results by $23 million. Higher DD&A expense reduced results by $6 million. All other items reduced results by $5 million for an overall increase in third quarter results of $93 million.

As John mentioned earlier, we sanctioned the Payara Field development in September. The Corporation's net share of development costs, excluding pre-sanctioned costs and FPSO purchase cost is forecast to be approximately $1.8 billion, which is consistent with the projections from our December 2018 Investor Day presentation. The timing of the FPSO purchase is still being evaluated. Our net share development costs is forecast to be approximately $250 million in 2021, $450 million in 2022, $500 million in 2023, $300 million in 2024 and $225 million in 2025.

Now turning to Midstream, the Midstream segment had net income of $56 million in the third quarter of 2020, compared to $51 million in the previous quarter, reflecting higher throughput volumes. Midstream EBITDA, before noncontrolling interest, amounted to $180 million in the third quarter of 2020, compared to $172 million in the previous quarter. For corporate, on an adjusted basis, after-tax corporate and interest expenses were $116 million in the third quarter of 2020, compared to $122 million in the previous quarter.

Turning to our financial position, at quarter-end, excluding Midstream, cash and cash equivalents were approximately $1.3 billion and our total liquidity was $4.8 billion, including available committed credit facilities. While debt and finance lease obligations totaled $6.6 billion, our fully undrawn $3.5 billion revolving credit facility is committed through May 2023. Net cash provided by operating activities before changes in working capital was $468 million in the third quarter, compared with $301 million in the previous quarter, primarily due to higher realized selling prices.

In the third quarter, net cash provided from operating activities after changes in working capital was $136 million, compared with $266 million in the prior quarter. Changes in working capital during the third quarter decreased cash flow from operating activities by $332 million, primarily due to a reduction in payables reflecting reduced operating activity levels and the temporary increase in accounts receivable and inventory, resulting from our VLCC transactions, which will reverse over the next two quarters. We have hedged over 80% of our remaining crude oil production for 2020. At September 30, 2020, the fair value of open hedge contracts was approximately $205 million, while realized settlements on closed contracts during the first nine months of the year were approximately $700 million. Proceeds from the sale of the first VLCC cargo of 2.1 million barrels of oil were received in October and proceeds from the sale of the second and third VLCC cargoes totaling 4.2 million barrels of oil are expected to be received in the first quarter of 2021.

During the 4th quarter, we expect to close on the sale of our working interest in the Shenzi Field for total consideration of $505 million with an effective date of July 1, 2020. The proceeds from the Shenzi sale will allow us to fund our Guyana investment program in a $40 oil price environment through the start-up of Liza Phase 2 with cash flow from operations and cash on hand. As Phase 2 comes online, our operations in Guyana will begin to generate free cash flow for the corporation, even in a $40 oil price environment and depending on commodity prices at that time, the Corporation will begin generating free cash flow between 2022 and 2024. As we generate free cash flow, we plan to first reduce debt and then increase returns to shareholders.

Now turning to guidance. First for E&P, our E&P cash costs were $9.86 per barrel of oil equivalent including Libya and $9.69 per barrel of oil equivalent, excluding Libya in the third quarter. We project E&P cash costs, excluding Libya to be in the range of $11 to $11.50 per barrel of oil equivalent for the fourth quarter, which reflects the impact of hurricane related shutdowns in the Gulf of Mexico. Full-year guidance is unchanged at $9.50 to $10 per barrel of oil equivalent. DD&A expense was $16.16 per barrel of oil equivalent in the 3rd quarter. DD&A expense excluding Libya is forecast to be in the range of $15.50 to $16 per barrel of oil equivalent for the fourth quarter and in the range of $16 to $16.50 per barrel of oil equivalent for the full year, which is in the lower end of our previous guidance range. This results in projected total E&P unit operating costs, excluding Libya to be in the range of $26.50 to $27.50 per barrel of oil equivalent for the fourth quarter and $25.50 to $26.50 per barrel of oil equivalent for the full year.

Exploration expenses, excluding dry hole costs, are expected to be in the range of $35 million to $40 million in the fourth quarter and approximately $135 million for the full year, which is down from previous guidance of $140 million to $150 million. We expect to recognize an additional $7 million of dry hole costs associated with the Galapagos Deep Well in the fourth quarter. The Midstream tariff is projected to be approximately $240 million in the fourth quarter and approximately $945 million for the full year, which is up from previous guidance of $905 million to $930 million. E&P income tax expense, excluding Libya, is expected to be in the range of $10 million to $15 million for the fourth quarter and $25 million to $30 million for the full year. Our crude oil hedge positions remain unchanged. We expect that non-cash option premium amortization will be approximately $95 million for the fourth quarter and approximately $280 million for the full year. Our E&P capital and exploratory expenditures are expected to be approximately $400 million in the fourth quarter and approximately $1.8 billion for the full-year, which is down from previous guidance of approximately $1.9 billion, primarily from Guyana spend coming in under budget.

For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be approximately $55 million in the fourth quarter and approximately $220 million for the full year, which is up from previous guidance of $195 million to $205 million. For corporate, corporate expenses are estimated to be in the range of $30 million to $35 million for the fourth quarter and $115 million to $120 million for the full-year, which is in the lower end of our previous guidance range. Interest expense is estimated to be approximately $95 million for the fourth quarter and approximately $375 million for the full year, which is in the lower end of our previous guidance range.

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

Questions and Answers:

Operator

[Operator Instructions] Your first question comes from the line of Doug Leggate with Bank of America.

Doug Leggate -- Bank of America / Merrill Lynch -- Analyst

Well, thanks and good morning, everybody.

John B. Hess -- Chief Executive Officer

Good morning Doug.

Doug Leggate -- Bank of America / Merrill Lynch -- Analyst

I hope everyone is doing well at there.

John B. Hess -- Chief Executive Officer

Yes. Thank you. You too.

Doug Leggate -- Bank of America / Merrill Lynch -- Analyst

John Rielly probably is my first question. John, I'd like to ask you about the cash burn in the quarter pre and post working capital. And how you think about the trajectory of balance sheet surety if you like going through the end of the year, because there's obviously a lot of moving parts with Shenzi and the VLCC sales. So just how are you going to manage the balance sheet through the next phase of development in Guyana, given what looks like continued worsening in oil prices?

John P. Rielly -- Executive Vice President and Chief Financial Officer

Sure, Doug. Thanks for the question. I guess what I want to start with is our cash position. So if you look at September 30th, we have approximately $1.3 billion of cash. And as we mentioned, we have the Shenzi sale closing in the fourth quarter. So let me just use round numbers, you could take that $1.3 billion and you add that Shenzi sale of $500 million to it, on a pro forma basis, it get you up to about $1.8 billion of cash. The next thing above and beyond what our cash flow from operations will be generating over the next couple of quarters is the VLCC transactions. So we have not received any of that cash right now. And so, we have over 6 million barrels that we will be receiving cash for as these VLCC transactions close. One we've already closed. So we have that cash in October for that. The other two, as we said close around the end of the year. So we'll probably get that early next year. But if you take that 6 million barrels times current prices, I'll just round it down even and say it's $200 million. Therefore, you go from the $1.3 billion plus the $500 million of Shenzi, plus that $200 million, we essentially have $2 billion on a pro forma basis of cash. So that's the first thing I think to start with. We've really put ourselves in a position with that Shenzi sale and the VLCC transactions to actually act as a hedge here as we move with -- into this next year with this low price environment.

So starting with that $2 billion. The next thing, as you mentioned was just to look at our quarter and our cash flow. So after working capital, we had that reduction from working capital of $332 million. And if I can just again use round numbers, about half of that is due to the VLCC transactions. We've got receivable on the books, plus the inventory builds from the crude oil going on the ships, that's just going to reverse naturally as I said over the next two quarters. The other thing that we have in there is reduction of payables. And it's really just reducing operating activity levels, capex is coming down, other costs are coming down as we reduce activity. And now, we're getting to a point where it's stabilizing, right. Our capital levels you saw for the quarter down to $331 million in the third quarter, so we'll be stabilizing. So we won't be having those pulls. And if prices do come back at some point and activity levels, which they will, we'll increase at that point, we'll actually get some inflow from working capital, it's just how it works. When that activity levels come down, you going to pull and when activity levels go up, you begin to get an inflow. So if you actually looked at our cash flow from operations, we have $468 million there and on our cash flow statement, you see the outflow for capital was $426 million. So except for that temporary increase from the working capital, we actually exceeded, our cash flow, exceeded our capital. And basically, if you didn't have that working capital pull, we'd be kind of on a cash flow breakeven for the quarter.

So again, as we move forward, we're continuing to focus on reducing capital and reducing cost and doing everything we can and getting our cash balance to a point that we can withstand this low prices. And like I said, we're in a position even in this low price environment to fund all the way through to Phase 2 when we get 60,000 barrels a day, approximately a Brent based production coming into and generating cash flow for the corporation.

Doug Leggate -- Bank of America / Merrill Lynch -- Analyst

That's just a really thorough explanation, a $2 billion number I think is what I was really looking at. So thank you for that.

My follow-up is, John -- John Hess, this is probably a bit of a curve-ball really. But one of your competitor companies the other day when announcing their acquisition Pioneer talked about a handful of investable E&Ps and I'm glad to say that you were sited as one of them on a go-forward basis. But my question is, when you look at consolidation across the sector, and clearly Hess doesn't need to do anything, given Guyana. But from the point of lowering the cost base for the broader industry, I'm just curious what your view is on Hess' participation, potentially one way or the other in the current consolidation wave we seemed to be undergoing right now? I'll leave at there, Thanks.

John B. Hess -- Chief Executive Officer

Yeah, Doug. Obviously, our first, second and third priority is to remain focused on executing our strategy, which we believe will maximize value for our shareholders. We have built a high quality and differentiated portfolio that provides a long-term resource growth with a low cost of supply. So we already are on that trajectory for that low-cost of supply. We don't need M&A to get there and it's underpinned obviously by multiple phases of Guyana oil developments.

And all of this together will position our company to deliver industry-leading cash flow growth over the course of the decade. Obviously, we're giving some guidance now of increasing our resource estimate in Guyana and the Stabroek Block to approximately 9 billion barrels of oil equivalent, with a potential for 10 ships, not just five ships. Obviously, a lot of work needs to be done to bring those forward. So we have a great hand to provide industry-leading cash flow growth and at the same time go down the cost curve, which will generate industry-leading free cash flow with a passage of time. So we're always looking to optimize our portfolio, but we see nothing in the M&A market that will compete for capital against our existing portfolio of high return opportunities.

Doug Leggate -- Bank of America / Merrill Lynch -- Analyst

Great. Thanks again guys. Appreciated you taking my questions.

Operator

Your next question comes from the line of Arun Jayaram with JPMorgan Chase.

Arun Jayaram -- JPMorgan Chase -- Analyst

Yeah, good morning. Arun Jayaram from JP Morgan. My first question really revolves around Payara. Greg, the F&D cost came in a bit higher than buy side expectations. So I was wondering if you could maybe put the budget in the context around contingencies and any implications for Phase 4 or Phase 5 F&D, or capital efficiency in Guyana?

Gregory P. Hill -- President and Chief Operating Officer

Yeah. In terms of that guidance, I suggest that John Rielly address that.

John P. Rielly -- Executive Vice President and Chief Financial Officer

Sure. So Arun, as you know, as I said, the net development cost for Hess is $1.8 billion. So when you gross that up, it's approximately $6 billion. We do have contingencies in our numbers for that, it's set especially fairly high contingencies early in the process and it comes to that $6 billion on a gross-up basis. And the one thing you also have to add when you're doing the F&D is the ultimate purchase cost from the FPSO. We did not include that in our numbers, because that's still -- the timing of that is being evaluated and the cost gets lower as you move out in time. So we don't know what that is. Exxon in its Phase 2 release had the FPSO at approximately $1.6 billion, that's what they disclosed for Phase 2. We expect it to be lower with synergies. So if I round that, it's $1.5 billion, so you get about $7.5 billion there. And then, we do have some pre-sanctioned cost to add. And I know Exxon has got some additional contingencies beyond that.

But Exxon is -- we're really happy with them as an operator. They've been performing great. And as part of that performance, they have been coming in under budget. So what I would say from that, the other thing that I want to add with Payara is all the costs and the contingencies that we have in our numbers and the pre-sanctioned cost and the expected FPSO cost is in that calculation for the $32 Brent breakeven. So this truly is a world-class asset and adds to obviously then will be the third project in Guyana and we're looking forward to doing the next project. After that it looks like it's going to be the greater Yellowtail area based on early drilling a size that we see there. We actually expect those costs to be lower than Payara and probably the breakeven therefore will come between $25 and $32 for the greater Yellowtail area.

Arun Jayaram -- JPMorgan Chase -- Analyst

Great, that's great color. My follow-up, John is if you could give us some color -- you touched upon this in your prepared remarks on the FPSO related capex, I believe the consortium did lease the destiny for 10 years with a 10 year option, but you do have a purchase option, which I believe last for up to two years. So I was wondering if you could provide the current thoughts on exercising the option and are you anticipating some of that FPSO related capex to be incurred in 2021?

John P. Rielly -- Executive Vice President and Chief Financial Officer

Okay. So, at our -- at the current date right now and Exxon on behalf of the group is discussing with SPM, the date, the timing of purchasing all the FPSOs, and that would be Liza Phase 1, Phase 2 and Payara. So as of right now, we do not expect any cost -- for purchase cost for Liza Phase 1 in 2021, but again the timing is -- unfortunately, Arun, I can't really go much beyond that, that timing is still being discussed and part of the discussion is moving out some of the timing of the purchase of those FPSOs, but nothing has been decided at this point. But right now for 2021, it is not expected to have any purchase cost in it.

Arun Jayaram -- JPMorgan Chase -- Analyst

And is it fair to say that the net to Hess that the purchase costs on the Destiny would be around $250 million, just net to the Hess.

John P. Rielly -- Executive Vice President and Chief Financial Officer

Okay. So depending on timing, It can vary. The earlier on, it could be somewhere closer to 300, still under 300 and then it will decrease as you move out in time.

Doug Leggate -- Bank of America / Merrill Lynch -- Analyst

Great, thanks a lot.

John P. Rielly -- Executive Vice President and Chief Financial Officer

You're welcome. Thank you.

Operator

Thank you. Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer -- Goldman Sachs -- Analyst

Thank you. Good morning.

John P. Rielly -- Executive Vice President and Chief Financial Officer

Good morning, Brian.

Brian Singer -- Goldman Sachs -- Analyst

My first topic is Guyana with regards to the 9 billion boe approximate estimate for discovered resource and then also, I think you mentioned you would believe that, that can support up to 10 FPSOs. So just a couple of questions there. Number one, given that there is no longer the greater than or the plus sign there, can you just remind us what's in that and not in that relative to the recent discoveries, you made some comments that seems like Yellowtail and Redtail have been updated, but is there anything that's not in that. And have there been any downward revisions to any of the path discoveries within that approximately 9 billion boe number and then as it relates to up to 10 FPSOs, how should we think about a peak oil production number? Is it as easy as 180 times one plus up to 220 times 9 or would you expect some FPSOs to be in decline when later developments are brought online.

John P. Rielly -- Executive Vice President and Chief Financial Officer

Fair enough. Greg, do you want to tackle the resource number and what really was behind that.

Gregory P. Hill -- President and Chief Operating Officer

Sure. Yeah, so the upgrade from the the greater to 8 -- greater than 8 to 9 really reflected the results of the drilling remember in Uaru, Yellowtail-2 and Redtail-1. So, a good portion of the results of that were included in that billion barrel call at resource upgrade. So that brings us close to being up-to-date. There is obviously some additional upside to that number that we'll figure out with further testing and potential appraisal in and around that area. So there is more upside coming on top of that number, but that really reflects the results of those three wells.

And to your question on the 10 FPSOs, again, as John said in his opening remarks that we still have to do a lot of engineering work on those 10 FPSOs, but I think this regular cadence of one a year you could assume -- and then, obviously as you get further out in time, some of those earlier FPSOs could be in decline. However, remember, we still have multi-billion barrels of upside that hasn't been explored or appraised. So how all that kind of works out and works all age fillers, new hubs, is yet to be determined and I think furthermore, Brian, if you think about the Santonian, remember the Santonian is 3000 feet deeper than the Campanian, they currently represents that 9 billion barrels.

And if you look at it on seismic, the extent of the channel systems is as extensive or more extensive than the Campanian. And the industry has got five penetrations in it, two on Stabroek and three in Suriname obviously on Apache's block. So that will be a subject of a lot of exploration and appraisal drilling over the next couple of years and depending on how that turns out, the Santonian also as well as multi-billion barrels of remaining upside in the Campanian, all of that could be used as both all age fillers and new hub class developments. So I would like to say Guyana is a story that's going to go on more than 10 years because of that multi-billion barrels of upside and we haven't even scratched the surface of the Santonian yet and we're in the early innings in the Campanian still.

John P. Rielly -- Executive Vice President and Chief Financial Officer

And obviously, Greg great contacts and Brian, obviously we wanted our investors to know, there is still tremendous potential here as Greg is talking about, but a lot more work needs to be done in terms of exploration and appraisal to inform the specifics of the size of the ships, the timing of the ships, but generally speaking, one a year is a good estimate to think about, but the most important thing is we need to work with the government, and we need to work with our partners. So, it's still early days, but we want people to realize in 2018, I think the resource estimate was 4 billion barrels of oil equivalent and that's when we talked at least 5 ships and at least 750,000 barrels a day. So we wanted investors to get an update of what the potential number of ships could be based upon the resource upgrade that we're giving. So a lot more work needs to be done, but it's obviously very exciting.

Brian Singer -- Goldman Sachs -- Analyst

That's great. Thank you for that color. My follow-up is on more of the financial side, can you just talk about any updates to how you're thinking about either maintenance capital or 2021 capital plans and then in the context of some of the balance sheet, questions and free cash flow discussion earlier, how you think about hedging versus not hedging into next year.

John P. Rielly -- Executive Vice President and Chief Financial Officer

Sure. So let me start with the capital. What we see now. I mean, obviously, we're still going through our budget process and we'll give our final guidance on our January call, but we see 2021 capital being comparable to 2020 as we move forward and basically you have Bakken because we went from six rigs to one, their capital coming down and then with our Payara sanction adding some additional rigs next year for development and exploration that Guyana's capital is going up. So those are the two big movements, but we see it as being comparable and Brian, I get asked a lot on with the lower capital, 40% down this year, these. maintenance capital levels and it is not actually because what happens from our standpoint if we stay at one rig, there will be some declines in the Bakken and if we don't do you tieback wells in the Gulf of Mexico, we will get some decline there. But this is the uniqueness of Guyana, right. When we bring on Phase 2, it's again approximately 60,000 barrels a day Brent equivalent type pricing for that production. So we're picking up 60,000 barrels a day there, that offsets the declines in Bakken and Gulf of Mexico. Then you have Payara 2024 and then as both John and Greg, we're saying we're kind of on pace for one a year, as you go after that. So we can continue to actually grow at these lower capital levels. If Southeast Asia stays flat at that $150 million to $200 million type level of capital. So we can have that about 65,000 barrels a day. So actually our maintenance capital levels would be a good bit lower than where we are at this lower level.

So again with neatness where we can grow and it's just because Guyana's returns and the profile of it are so good that we can grow and generate free cash flow, because of the low-cost nature of these developments, the low breakeven.

Oh, sorry, I think you did, you had one other question about hedging.

Brian Singer -- Goldman Sachs -- Analyst

Yeah.

John P. Rielly -- Executive Vice President and Chief Financial Officer

So just to get to your hedging question, so obviously we continue to have the 130,000 barrels a day of put options at 55 WTI for the remainder of 2020 and we have 20,000 barrels a day of our Brent put options at $60 remainder of 2020. So as we move into 2021, we clearly would like to put on a hedge and put some insurance to put a floor on for next year because we are still investing with this Guyana Phase 2 coming on in early 2022. So we'd like to put a floor on. Now the great hedge position that we have for this year, the Shenzi sale, the VLCC that I told you, have put us in a good position going into it. So there is no rush for us to have to get hedges on right now. We'd like to use put options to get the full insurance, which obviously paid off this year. Put options are expensive due to the time value of money, if you're further away from the period you want to hedge and then obviously you know where volatility is right now in the market. So you will see us hedge, it could be later this year, it could be early in 2021, but you should look for us to put on a significant, again, insurance position for a floor for us next year.

Brian Singer -- Goldman Sachs -- Analyst

Great, thank you for that detail.

Operator

Thank you and our next question comes from the line of Jeanine Wai with Barclays.

Jeanine Wai -- Barclays Capital -- Analyst

Hi, good morning everyone, thanks for taking my questions. This is Jeanine Wai.

John P. Rielly -- Executive Vice President and Chief Financial Officer

Morning, Jeanine.

Jeanine Wai -- Barclays Capital -- Analyst

Good morning.

Gregory P. Hill -- President and Chief Operating Officer

Hi, Jeanine.

Jeanine Wai -- Barclays Capital -- Analyst

In terms of Guyana that's what my question is on, in terms of the Payara development cost, I know you've touched on this already. We know that the aerial extent, it's a little larger than the prior developments, which is contributing to the cost but Payara also has more resource and I think I heard you mentioned earlier in the Q&A that the next phase is likely to be lower on the breakeven. So I was just wondering can you provide a little more color on this lower breakeven, maybe in terms of all the different moving pieces? Can you discuss how the Payara development could compare to future development phases in terms of size and probably scope?

John P. Rielly -- Executive Vice President and Chief Financial Officer

Yeah, I think Greg just hitting Yellowtail, both in terms of the thickness aerial extent than what we've seen with Redtail as well. Just to give the context, we can't be more specific than that now. We still got the DST to go on Redtail, but we're relatively optimistic about the economic attractiveness of that being the next development.

Gregory P. Hill -- President and Chief Operating Officer

Sure. I think what the Yellowtail and the Redtail wells both showed -- remember Redtail is only a mile and a half from the Yellowtail well, is that the reservoir extent is very large. It's larger than we thought, just based on the results of the Yellowtail-1. So there is a huge resource base there. We know that the reservoir quality is very similar to, I'll say, Liza-2 and also the crude quality is Liza-like and so very -- bigger tanks, bigger reservoirs in and around that greater Yellowtail area and that's why John had mentioned it will likely have a lower development cost. It looks like you will probably need fewer wells to get the same amount of resource. However, I will say, we've still got engineering work to do, we've got to get through our various gates and our development process to be further definitive about that, but also because of the nature of the PSC, you'll have more barrels on, which affects the rate of cost recovery, which will also tend to drive that breakeven lower. But I think as you look at the reservoir of Yellowtail versus Payara, it's big, it's very big.

Jeanine Wai -- Barclays Capital -- Analyst

Okay, great. Thank you very much and I hope everyone is doing well out there.

John P. Rielly -- Executive Vice President and Chief Financial Officer

Thank you.

Gregory P. Hill -- President and Chief Operating Officer

Thank you. You too.

Operator

Your next question comes from the line of Ryan Todd with Simmons Energy.

Ryan Todd -- Simmons Energy -- Analyst

Great, thanks. Maybe if we start out in the Bakken. In the Bakken, production continues to exceed expectations and congrats on hitting the 200,000 barrels a day target early. I know you've said the one rig isn't enough to hold production flat, you know how it declines, but given the continued outperformance, can you give us an idea of how you think about maybe an update of that idea? How you think about extra rate declines, 2021 versus 2020, or going forward from here?

John P. Rielly -- Executive Vice President and Chief Financial Officer

Yeah, Greg?

Gregory P. Hill -- President and Chief Operating Officer

Yeah, we're still -- we're in the throes of our development plan right now for next year. So I want to give you guidance in January, like we always do on the Bakken. I think that'd be more appropriate, well, I think the development as we speak.

Ryan Todd -- Simmons Energy -- Analyst

Maybe. With that, do you still have DUC to work down? Or will till then wells drilled be at a similar level next year?

Gregory P. Hill -- President and Chief Operating Officer

We don't really -- we don't carry a large DUC inventory, particularly with one rig. We did in the first part of the year, because remember, we had six rigs that built-in inventory, that will effectively be worked off during the fourth quarter. And it will be -- then it will just be normal work in process, right? So there won't be a DUC inventory, so to speak, other than, well is just waiting on a completion crew.

John B. Hess -- Chief Executive Officer

Yeah. And Greg, maybe just to provide some context for Ryan, you might remind everyone what the role of the Bakken is in the portfolio and that takes precedent over what the rig rate is or what the production rate is and that sort of thing. And then also it takes about two to keep production flat. You might just remind people of that.

Gregory P. Hill -- President and Chief Operating Officer

Sure, yeah.

John B. Hess -- Chief Executive Officer

Even though we're working on final guidance for a quarter from now.

Gregory P. Hill -- President and Chief Operating Officer

It would take, as John mentioned, let me start with what it would take to hold the Bakken flat. Take two rigs to hold it flat, broadly in the 180,000 barrel a day range with two rigs we could hold it at that level, but I think, as John mentioned important context for the Bakken, the role of the Bakken in the portfolio now is to be a cash generator and so the rig count will be a function of obviously oil price, but also corporate cash flow needs. That is what will govern the rate at which we develop the Bakken. Now in order to maintain that magnificent cash firepower that the Bakken has, obviously we would like to at least hold it flat, right? So it doesn't decline away and you lose some of that cash firepower capability. As we -- as I said in my opening remarks though, we won't consider adding that second rig to hold it flat until WTI prices approach $50. At that point, we would look at where we are and we'd make an informed decision on whether to add that second rig. But the Bakken, again, it's primary role is cash. It's not the growth engine. Guyana is the growth engine. It will be the cash engine and of course, we could grow it as oil prices improve.

Ryan Todd -- Simmons Energy -- Analyst

Thanks. I guess maybe, is that the natural follow up -- transition to follow up on the Gulf of Mexico, which I think is -- generally plays a similar role in the portfolio as a cash-cow underpinning the under-developments, can you maybe talk a little bit more about the decision to sell your stake in the Shenzi Field? Is that just opportunistically helping you to bridge the -- pull forward that cash flow to bridge the gap to Payara or to start off the Phase 2 start-up?

Gregory P. Hill -- President and Chief Operating Officer

Yeah, John...

Ryan Todd -- Simmons Energy -- Analyst

Or has there been any change, I guess, in how you think about the use of that asset, going forward?

John B. Hess -- Chief Executive Officer

No. To be clear, the Gulf of Mexico is a core focus area for the company and it will be for the future, but we did have a unique opportunity to monetize Shenzi. John Rielly can provide some background Sure. So just to reiterate, our Gulf of Mexico strategy has not changed with the Shenzi sale. John said it's core part of our portfolio. We plan to pursue both infill and tie-back opportunities to our existing hubs, as well as hub-class exploration as oil prices recover. So again, it really does remain unchanged. With this Shenzi sale with BHP being the operator, we were able to get a price for Shenzi that met our value expectations. So therefore, the sale fit well with our strategy to preserve cash and the long-term value of our assets in this current low oil price environment. And then as I mentioned, the proceeds there add to our kind of $1.3 billion that we already have on the balance sheet and we can use it to fund our investment opportunities in Guyana and we will use our cash on hand and cash flow from operations to fund Guyana all the way through to Phase 2, where we get a step up in cash flow, when Phase 2 comes online.

Ryan Todd -- Simmons Energy -- Analyst

All right. Thank you.

Operator

And our next question comes from the line of Bob Brackett with Bernstein Research.

Bob Brackett -- Bernstein Research -- Analyst

Hi, good morning. A number of my questions have been asked already, so I'll just throw one out around Libya. We're seeing the country as a whole, get back to exporting volumes, what do you think about that in terms of the Hess portfolio?

John B. Hess -- Chief Executive Officer

Well, Bob, the Libya is a cash engine when it's producing, given that the NOC has just lifted the force majeure restrictions and the country has agreed to a ceasefire, the Es Sider port has now reopened and initial liftings have started. But it still remains to be seen what a normalized level of production in Libya is going to be given the uncertainties and continued political unrest. So obviously when we get cash from it, we're happy to do that. But at the same time, it's not at the point where it's stabilized where it could be in our numbers on an ongoing basis.

Bob Brackett -- Bernstein Research -- Analyst

Great. Thank you for that.

John B. Hess -- Chief Executive Officer

Sure.

Operator

Your next question comes from the line of Paul Cheng with Scotiabank.

Paul Cheng -- Scotia Howard Weil -- Analyst

Thank you. Good morning.

John B. Hess -- Chief Executive Officer

Good morning.

Paul Cheng -- Scotia Howard Weil -- Analyst

The first question is actually I think either for John or Greg, maybe both. I'm trying to have a better understanding, if I look at Liza-2, if my recollection correct, the total development cost is about $6 billion, that's including the FPSO $1.6 billion. So called it $4.4 billion and total capacity is $2.20 million for the FPSO.

So in Payara, we also looking for $2.20 billion. So one would have thought the cost would be lower than Liza-2, as you get more experience in developing there. So Greg and John, can you help me understand a little bit what -- how the design may have changed and why instead of having a lower cost it's actually become higher?

Gregory P. Hill -- President and Chief Operating Officer

Yeah. Go ahead, John.

John P. Rielly -- Executive Vice President and Chief Financial Officer

Sure. So let me just start with that like each development is unique Paul. So like as I mentioned, the Greater Yellowtail area, we see that with lower development costs and a breakeven that drops between $25 and $32 at that point, with Payara being at $32. So the difference, we are getting synergies like you said from the building of the FPSO, because we do expect that to come in at a lower cost. So with Payara as compared to Liza Phase 2 and I always have to remind everybody, and I know I'm not objective Paul, when I say this. But Liza Phase 2 with the Brent breakeven of $25 is arguably the best project that is out there in the E&P industry. So we are comparing things to this really top project and Payara is world-class. So it does cost more and why -- what happens is Payara has a greater number of distinct reservoirs and therefore also a greater aerial extent. So it was always, as we said, it was back in our December 2018 Investor Presentation, it was always going to have a higher cost than Liza Phase 2. So those costs now came exactly in with what we were expecting, just the aerial extent in the reservoirs caused more wells to be there, some more flow lines to be there. And that's what causes that cost to be there and the Brent breakeven going to $32 versus the $25. Now, again Yellowtail, we expect that to be lower, because I think the reservoirs, the individual reservoir as Greg had mentioned, have a great aerial extent on its own. Therefore, we believe the cost will be lower in the Brent breakeven between $25 and $32.

Paul Cheng -- Scotia Howard Weil -- Analyst

Thank you. And Greg, that when earlier you're talking about the gas injection system as a mechanical issue. You said that the site problem or that what's causing that mechanical problem?

Gregory P. Hill -- President and Chief Operating Officer

Yeah, both. There were two issues Paul. So first was the cooling fan blades on the big gas compressors and that was a design issue for sure. Those were reengineered, new fan blades installed and both of those compressors are currently operating. And that's why our production now is averaged about a 105,000 barrels a day for the last couple of weeks. So things are back on track for the main gas compressor. The last piece is a flash gas compressor. And there was a failure in the lube-oil system, that is a design-related issue and that compressor is back in Germany, being retrofitted as we speak. And the plan is to get it out of the platform or the FPSO during the month of November and then begin to ramp-up to the full mainplate in December, so both were design issues.

I think, as I've said before Paul, that the silver lining in all this to me is in this design one build many strategy. All of the learnings that are coming out of this are being incorporated into future phases. So that will over time just continue to increase the reliability and ability to bring these on -- these vessels on flawlessly.

Paul Cheng -- Scotia Howard Weil -- Analyst

Okay, thank you. And just a quick one. Gulf of Mexico, in the third quarter, how much is the hurricane impact? And also, John Rielly, the the international opex the unit cost, why is so high in the third quarter?

John P. Rielly -- Executive Vice President and Chief Financial Officer

Sure. So let me start with the Gulf of Mexico in the third quarter. So between maintenance shutdowns that we already were undergoing at Llano and Conger, because Shell is working on the Enchilada and auger platforms. So with that maintenance shutdowns and the hurricane downtime, it was approximately 19,000 barrels a day of an impact in the third quarter. And then, you heard from as in Greg's script there that the fourth quarter is going to be about 25,000.

So what's really happening again is Llano and Conger is continuing now with the shutdown due to the hurricane and damage that was incurred. The biggest difference then between the third and fourth quarter though is that Penn State well that Greg mentioned. So that is going to be down for basically most of the quarter, not coming back till the end of December. So that's what takes the 19,000 to 25,000 in Q4.

And then, the international costs that you saw, what you have to do is take out $8 million associated with the severance charge. So of that $27 million special severance charge, $8 million of it was over on the international side.

Paul Cheng -- Scotia Howard Weil -- Analyst

Thank you.

John P. Rielly -- Executive Vice President and Chief Financial Officer

You're welcome.

Operator

And your next question comes from the line of David Heikkinen with Heikkinen Energy.

David Heikkinen -- Heikkinen Energy -- Analyst

Good morning, guys. Thanks for taking the question. Just a couple of quick questions. The first of all, on Kaieteur, what do you expect the dry hole cost to be?

Gregory P. Hill -- President and Chief Operating Officer

John?

John P. Rielly -- Executive Vice President and Chief Financial Officer

So this one -- this well, as Greg has mentioned is going to be more expensive than our typical wells that we've been drilling from an exploration standpoint on Stabroek. So because it is, one, going deeper, we are using managed pressure drilling on this, just to be careful as we drilled all the way down to the deeper sections, as Greg mentioned going Santonian and Turonian. So Exxon is not put out an estimate on this right now, but it will take longer and it's going to generally cost a bit more. And just remember that we do have a lesser the working interest in Kaieteur than we have in Stabroek.

David Heikkinen -- Heikkinen Energy -- Analyst

Okay. And then, given all the recovery of volumes in the Gulf of Mexico, do you have a feel for a run-rate going into 2021, with all the moving pieces, the 19 back plus I guess Penn state gets you back to kind of your earlier this year rate I guess with some of your volumes, yeah.

John P. Rielly -- Executive Vice President and Chief Financial Officer

Yeah, sure. So I mean, basically, when we are in the Gulf of Mexico full-year, we incorporate shutdowns and things like that is approximately we were saying 65,000 barrels a day. I mean it can be higher than that when you don't have shutdowns in quarters. So we will get back on that run-rate except for the Shenzi sale, right. So you had 11,000 barrels being sold. So basically take it down to approximately 55,000 barrels a day then on a run-rate when everything will be coming back starting in January 1st.

David Heikkinen -- Heikkinen Energy -- Analyst

Perfect. And with the design one build many concept, it looks like you've ordered the same basic compressor kit that you'll just put side-by-side on the additional FPSOs. So all of the kinks that you're working out with Phase 1 really do -- hopefully will be avoided at least with the same kit, is that correct or?

Gregory P. Hill -- President and Chief Operating Officer

Yeah. Absolutely David. In fact the -- if you look at the part numbers, and this is getting extreme standardization. If you look at the part numbers, I think it's something like 85% of the part numbers on the top side, are the same in Phase 2 as Phase 1. So that's what I think the real advantage of the standardization is as you can just quickly roll learnings into future phases and really drive very high reliability in these vessels as a result of that.

David Heikkinen -- Heikkinen Energy -- Analyst

Yeah, yeah. So a lot of learnings in this first six months that will stabilize things and less downtime as you move forward. That's helpful of course. Thank you all.

Gregory P. Hill -- President and Chief Operating Officer

Thank you.

David Heikkinen -- Heikkinen Energy -- Analyst

All right.

Operator

Thank you. And your next question comes from the line of Roger Read with Wells Fargo.

Roger Read -- Wells Fargo -- Analyst

Yeah. Thanks, good morning.

John B. Hess -- Chief Executive Officer

Good morning.

Roger Read -- Wells Fargo -- Analyst

I'm just curious kind of your opening comments where you said, you expect to get sub $40 in terms of total development as we get through the middle of the decade. Does that fully rely on what you're going to do in Guyana? Or is that also envisioning some additional asset sales, down the road thinking the opportunity obviously popped up on Shenzi, but if there is anything else planned in there?

John P. Rielly -- Executive Vice President and Chief Financial Officer

No, there is nothing else planned in there with our current portfolio and it really is, as these FPSOs in Guyana come online as we spoke about Phase 2 being a $25 breakeven, Payara $32, Yellowtail being to $25 and $32. As these FPSOs get brought online, it drives down our overall breakeven in the portfolio to below $40.

Roger Read -- Wells Fargo -- Analyst

Okay. The other question, to follow up on, as you think about '21, you talk about running the one rig in the Bakken, you mentioned well costs had gone under $6 million there. Any thoughts on inflation, deflation, as you look at activity in the Bakken in '21 as you're thinking about your capex budget?

John B. Hess -- Chief Executive Officer

Greg?

Gregory P. Hill -- President and Chief Operating Officer

No, I think, we're not really assuming any inflation whatsoever next year in the Bakken. Things are still well over-supplied. We already have contracts locked in with their strategic suppliers for that. Now we do have some market-based adjustments, if the market does improve, but I think the important thing is through technology and innovation we'll still drive that cost lower, no matter what.

Roger Read -- Wells Fargo -- Analyst

Okay, great. Thank you.

Gregory P. Hill -- President and Chief Operating Officer

Yeah.

Operator

Your next question comes from the line of Pavel Molchanov with Raymond James.

Pavel Molchanov -- Raymond James -- Analyst

Thanks for taking the question. Both of my questions are related to COVID. The first one, Malaysia is having a very serious outbreak that just emerged in the last 30 days and you're one of the few international operators there. I thought I would ask what the status is and how we are coping with that sudden outbreak?

John B. Hess -- Chief Executive Officer

Yeah, Greg, you might talk about the field as well as the Office.

Gregory P. Hill -- President and Chief Operating Officer

Sure. Yeah. So remember during the first outbreak of COVID, there were essentially no impacts to the operation side. Logistically, you had to get people quarantined and tests and all that, but we worked all that out. So we really didn't skip a beat on the operating side, and remember, Malaysia is a very active area for us. We have ongoing drilling programs, ongoing projects. So very active and we saw no impact as a result of COVID, based on the protocols that we developed. If you look at the office, again, during the first outbreak everyone was working remotely. We got up to about 80% complement back in our office and now we've taken that back down again. So people would just go back to working remotely. I think in all this, we've seen no impact to the operations or to our ability to work in Malaysia, it has resulted in lower nominations, which is why we kept our guidance for the fourth quarter for Malaysia at 50,000 barrels equivalent just because of those COVID uncertainties in the second outbreak.

Pavel Molchanov -- Raymond James -- Analyst

Okay. Similar question about the Guyana. Originally the timetable for reaching full capacity or plateau was August, now you're -- and Exxon, of course, talking about December, how much have social distancing restrictions or labor availability related to COVID have had with that four months delay?

John B. Hess -- Chief Executive Officer

Yeah. Obviously, it impacted repairs, but go ahead.

Gregory P. Hill -- President and Chief Operating Officer

Yeah. No, I think it's on the margins, I would say, I mean really the design issues that I talked about, were the primary reason. However, as Exxon has very strict protocols, which I think are absolutely appropriate. So anyone, before they go offshore, has to self-quarantine in country for 14 days and be tested. So obviously, any special work that needs to be done, is going to take a little bit longer, but I will compliment ExxonMobil profusely because they've had some 2500 crew change events and so far, touch-wood, they've had no COVID cases offshore. So I think what's going on down there is absolutely remarkable, in terms of how well all that's being executed amid a pandemic.

Pavel Molchanov -- Raymond James -- Analyst

Thanks very much.

Operator

[Operator Closing Remarks].

Duration: 75 minutes

Call participants:

Jay R. Wilson -- Vice President, Investor Relations

John B. Hess -- Chief Executive Officer

Gregory P. Hill -- President and Chief Operating Officer

John P. Rielly -- Executive Vice President and Chief Financial Officer

Doug Leggate -- Bank of America / Merrill Lynch -- Analyst

Arun Jayaram -- JPMorgan Chase -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

Jeanine Wai -- Barclays Capital -- Analyst

Ryan Todd -- Simmons Energy -- Analyst

Bob Brackett -- Bernstein Research -- Analyst

Paul Cheng -- Scotia Howard Weil -- Analyst

David Heikkinen -- Heikkinen Energy -- Analyst

Roger Read -- Wells Fargo -- Analyst

Pavel Molchanov -- Raymond James -- Analyst

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