(Seeking Alpha, 28.Oct.2020) — Hess Corporation announced it 3Q:20 earnings results. The transcript from the earnings conference call on 28 October 2020 with analyst follows.
Company Participants
Jay Wilson – VP, IR
John Hess – CEO
Greg Hill – COO
John Rielly – CFO
Conference Call Participants
Doug Leggate – Bank of America
Arun Jayaram – JPMorgan
Brian Singer – Goldman Sachs
Jeanine Wai – Barclays
Ryan Todd – Simmons Energy
Bob Brackett – Bernstein Research
Paul Cheng – Scotia Bank
David Heikkinen – Heikkinen Energy
Roger Read – Wells Fargo
Pavel Molchanov – Raymond James
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. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes.
I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.
Jay Wilson
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, www.hess.com.
Today’s conference call contains projections and other forward-looking statements within the meaning of the Federal Securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess’ annual and quarterly reports filed with the SEC.
Also, on today’s conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.
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 Hess
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 were 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 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 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 cargos 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 guidance of $1.8 billion, primarily by reducing our Bakken rig count from six to one; 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 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 six rigs at the beginning of the year to maintain the Lean manufacturing capabilities and innovative practices that Greg and his team have built 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 six 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 30th, 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 operator.
Payara is targeted for first oil in 2024, and we expect to have at least five 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 and 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 potential for up to 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 1st, 2020.
This transaction brings value forward in the low price environment and further strengthens our cash and liquidity position until the Liza 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 longstanding 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 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 shareholders.
I will now turn the call over to Greg for an operational update.
Greg Hill
Thanks John. In the third quarter, we once again delivered strong operational performance. Companywide net production averaged 321,000 barrels of oil equivalent 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 costs 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 in 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 first 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 and offloading vessel or FPSO to reach its nameplate capacity of 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 continue to deliver at, or above, expectations. The design one, build many concept for the FPSOs allows 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 to plan with approximately 80% of the overall top side haul 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 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. 10 drill centers are planned with a total of 41 wells, including 20 production wells and 21 injection wells.
Also in December [ph], 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 of 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 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 Turonian.
The next exploration well on the Stabroek Block will be Hassa-1, which will target Campanian aged 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 that it is 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 that contain approximately 9 billion barrels of recoverable oil and gas resources, with multi billion barrels of exploration potential remaining.
Secondly, world-class reservoir quality with exceptional permeability and porosity that results in high flow rate wells 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 a 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, its low cost of 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 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 Rielly
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 of 2020 and the second quarter of 2020 were as follows.
Higher realized selling prices improved results by $134 million. Higher sales volumes improve results by $33 million. Higher exploration expenses reduce 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 reduce 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-sanction 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 being evaluated. Our net share of 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 non-controlling interests, 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 30th, 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 cargos totaling 4.2 million barrels of oil are expected to be received in the first quarter of 2021.
During the fourth 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 1st, 2020.
The proceeds from the Shenzi sale will allow us to fund our Guyana investment program in a $40 oil price environment through the startup 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 $11.00 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 third 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 the lower end of our previous guidance range.
This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.
Question-and-Answer Session
Operator
[Operator Instructions]
Your first question comes from the line of Doug Leggate with Bank of America.
Doug Leggate
Thanks. Good morning everybody. I hope everyone’s doing well out there.
John Hess
Good morning Doug. Yes, thank you. You too.
Doug Leggate
John Rielly probably is my first question. John, I’d like to ask you about the cash burn in the core for 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 you know, continued worsening in oil prices?
John Rielly
Sure Doug thanks for the question. I guess what I want to start with is, 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 this Shenzi sale closing in the fourth quarter. So, let me just use round numbers. If you take that $1.3 billion and yet the Shenzi sale $500 million to it, on a pro forma basis, it gets 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 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, closed 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 its $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 actually act as a hedge here as we move into this next year with this low price environment.
So, starting with that $2 billion, the next thing, as you mentioned, was just a look at our quarter and our cash flow. So, after working capital, we had that reduction from working capital $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 built 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 a reduction of payables. And it’s really just reducing operating activity levels. CapEx is coming down; all their 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 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 get a 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 had $468 million there and on a 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 costs 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 of Brent-base production, coming into and generating cash flow for the corporation.
Doug Leggate
That’s a really thorough explanation, $2 billion number; I think is what I was really looking at. So, thank you for that. My follow-up is John — this John Hess, this is probably a bit of a curveball, really, but one of your competitor companies the other day, when announcing their acquisition, Pioneer, talked about a handful of investable E&P and I’m glad to see that you were cited 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 view of lowering the cost base for the broader industry, I’m just curious what your view is on Hess’ participation in potentially one way or the other in the current consolidation we seem to be onto undergoing right now. I’ll leave it there. Thanks.
John Hess
Yes, 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 decades.
Obviously, we’re giving some guidance now of increasing our resource estimate in Guyana, and Stabroek Blok 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
Great. Thanks again, guys. Appreciate you taking my questions.
Operator
And your next question comes from the line of Arun Jayaram with JPMorgan Chase.
Arun Jayaram
Yes, good morning Arun Jayaram from JPMorgan. My first question really revolves around Payara. Greg, the F&D cost came in a bit higher than buy side expectations. I was wondering if you can 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.
Greg Hill
Yes, in terms of that guidance, I suggest John Riley address that.
John Rielly
Sure. So, Arun, as you know, as I said, the net development costs 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 costs 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 disclose 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-sanction costs 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 was saying 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-sanction costs 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, there will be the third project in Guyana. And we’re looking forward to doing the next project after that, well looks like it’s going to be the greater Yellowtail area and based on early drilling 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 for the greater Yellowtail area.
Arun Jayaram
Great, that’s great color. My follow-up, John is if he 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 the 10-year option. But you do have a purchase option, which I believe lasts 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 the FPSO-related CapEx to be incurred in 2021?
John Rielly
Okay, so at our — at the current date right now, and Exxon on behalf of the of the group is discussing with SBM, the date — the timing of purchasing all the FPSOs and that would be Liza Phase 1, Phase 1 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 — unfortunately, 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 costs in it.
Arun Jayaram
And is it fair to say that the net to Hess that the purchase cost on the destiny would be around $250 million, just net to the Hess?
John Rielly
Okay, so depending on timing, it can vary. The earlier on, it could be somewhere closer to $300 million — still under $300 million and then it will decrease as you move out in time.
Arun Jayaram
Great. Thanks a lot.
John Rielly
You’re welcome.
John Hess
Thank you.
Operator
Thank you. And our next question comes from the line of Brian Singer with Goldman Sachs.
Brian Singer
Thank you. Good morning.
John Hess
Good morning, Brian.
Brian Singer
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 FPSO. So, just a couple of questions there.
Number one, given that there’s 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 any of the past discoveries within approximately 9 billion Boe number?
And then as it relates to the — 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 nine, or when you expect some FPSOs to be in decline when later developments are brought online?
John Hess
Fair enough. Greg, do you want to tackle the resource number and what really was behind that?
Greg Hill
Sure. Yeah, so the upgrade from the greater to eight — greater than eight to nine 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 Rielly
And obviously, Greg gave great context 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
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 Rielly
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, its uniqueness 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.
Sorry, I think you did — you had one other question about hedging, 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, 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
Great. Thank you for that detail.
Operator
Thank you. And our next question comes from the line of Jeanine Wai with Barclays.
Jeanine Wai
Hi, good morning everyone. Thanks for taking my questions. This is Jeanine Wai.
John Rielly
Morning Jeanine.
Jeanine Wai
Good morning.
Greg Hill
Hi, Jeanine.
Jeanine Wai
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 Rielly
Yes, 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.
Greg Hill
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
Okay, great. Thank you very much and I hope everyone is doing well out there.
Greg Hill
Thank you. You too.
Operator
Your next question comes from the line of Ryan Todd with Simmons Energy.
Ryan Todd
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 Rielly
Yes, Greg?
Greg Hill
Yes, 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
Maybe. With that, do you still have DUC to work down? Or will till then wells drilled be at a similar level next year?
Greg Hill
No, 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 Hess
Yes. 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.
Greg Hill
Sure. Yes.
John Hess
Even though we’re working on final guidance for a quarter from now.
Greg Hill
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
Thanks. John 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?
Greg Hill
Yes. John any —
Ryan Todd
Or has — any change, I guess, in how you think about the use of that asset, going forward?
John Hess
No, 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.
John Rielly
Sure. So just to reiterate, our Gulf of Mexico strategy has not changed with the Shenzi sale. John said, it’s a 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, you know, as oil prices recover. So again, you know, it really does remain unchanged.
With this Shenzi sale with BHP being the operator, we’re 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, you know, the proceeds there add to our kind of $1.3 billion dollars. So 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
Okay. Thank you.
Operator
Our next question comes from the line of Bob Brackett with Bernstein Research.
Bob Brackett
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 export in volumes. What do you think about that in terms of the Hess portfolio?
John Hess
Well, Bob, you know, 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 SE report 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, you know, 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 what it can be in our numbers on an ongoing basis.
Bob Brackett
Great. Thank you for that.
John Hess
Sure.
Operator
Your next question comes from the line of Paul Cheng with Scotia Bank.
Paul Cheng
Thank you. Good morning.
John Hess
Good morning.
Paul Cheng
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. So call it $4.4 billion, and the total capacity is 220 for FPSO.
So, in Payara, we also looking for 220. So one would have thought the costs will be lower than Liza 2, as you get more experience in developing this. 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 is actually become higher?
Greg Hill
Yes. Go ahead, John.
John Hess
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
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?
Greg Hill
Yes, 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 re-engineered, new fan blades installed, and both of those compressors are currently operating. And that’s why our production now is averaged about 105,000 barrels a day for the last couple weeks. So things are things are back on track for the main gas compressors.
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 to the platform or the FPSO during the month of November, and then begin to ramp-up to the full nameplate in December. So both were design issues.
I think, you know, as I’ve said before, Paul, the silver lining and all this to me is in this design, one build many strategy. All of the learning’s 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
Okay. Thank you. And that’s just a quick one. Gulf of Mexico in the third quarter, how much is the hurricane impact and also John the international OpEx, the unit cost why is so high in the third quarter?
John Rielly
Sure. So let me start with the Gulf of Mexico in the — in the third quarter. So between maintenance shutdowns that we already had were undergoing at Llano and Conger, 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 script there that, the fourth quarter is going to be about 25,000. So, what’s really happening again is Llano and Conger 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 to 25 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
Thank you.
John Rielly
You’re welcome.
Operator
And your next question comes from the line of David Heikkinen with Heikkinen Energy.
David Heikkinen
Good morning, guys. Thanks for taking the question. Just a couple of quick questions. First of all, Kaieteur, what do you expect the dry hole costs to be?
John Hess
John?
John Rielly
So this one — this well, as Greg has mentioned, is — is going to be more expensive than our typical wells that we’ve been drilling from an exploration stain standpoint on Stabroek. So because it is one going deeper, we are using managed pressure drilling on this just to be you know, careful as we drill all the way down to the deeper section.
As Greg mentioned, going Santonian and Turonian. So Exxon has 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 though working interest in Kaieteur than we do in Stabroek.
David Heikkinen
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? It’s your back to your earlier this year, right? Well, I guess your volumes up?
John Rielly
Yes. Sure. So I mean, basically what we 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 and 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, you know, basically take it down to approximately 55,000 barrels a day, then, on a run rate when everything we coming back starting in January 1.
David Heikkinen
Perfect. And with the design one build many concepts; it looks like you’ve ordered the same, basic compressor kit that you’ll just put side by side on the additional FPSO, all the chinks that you’re working out with Phase 1 really do, hopefully will be avoided, at least with the same kit. Is that is that correct or –?
Greg Hill
Yes, absolutely, David, in fact, if you look at the part numbers and this is extreme standardization, if you look at the part numbers, I think it 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, is you can just quickly roll learnings, into future phases and really, really drive very high reliability in these vessels as a result of that.
David Heikkinen
Yes. So a lot of learnings in this first six months that’ll stabilize things and less downtime as you move forward. That’s helpful. Cool.
Greg Hill
Exactly.
David Heikkinen
Thank you.
Greg Hill
Thank you.
Operator
Thank you. Your next question comes from the line of Roger Read with Wells Fargo.
Roger Read
Yes. Thanks. Good morning.
John Hess
Good morning.
Roger Read
I’m just curious kind of your opening comments where you said, you expect to get to sub $40 in terms of total development as you get to the middle of the decade. Does that solely 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’s anything else planned in there?
John Hess
No. There’s nothing else planned in there with our current portfolio. And it really is, is these FPSO in Guyana, come online as we spoke about, phase 2 being a $25, breakeven Payara 32, Yellowtail being 25 and 32. As these FPSOs get brought online, it drives down our overall breakeven in the portfolio to below $40.
Roger Read
Okay. The other question to follow-up on as you think about 2021, you talk about running the one rig in the Bakken you mentioned well costs have gone under 6 million there. Any thoughts on inflation, deflation, as you look at activity in the pocket in 2021, as you’re thinking about your CapEx budget?
John Hess
Greg?
Greg Hill
No, I think we’re not really assuming any — any inflation whatsoever next year at the Bakken, things are still well over supplied. We already have contracts locked in with their strategic suppliers for that. Now, they do have some market based adjustments, if the market doesn’t prove, but I think the important thing is through technology and innovation will still drive that costs lower no matter what.
Roger Read
Okay. Great. Thank you.
Operator
Your next question comes from the light of Pavel Molchanov with Raymond James.
Pavel Molchanov
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 since you’re one of the few international operators there. I thought, I would ask what the — what the statuses and how you’re coping with that sudden, outbreak?
John Hess
Yes, Greg, you might talk about the field as well as the offshore.
Greg Hill
Yes. 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 tested 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 the 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 it always — 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 50,000 barrels equivalent just because of those COVID uncertainties in the second outbreak.
Pavel Molchanov
Okay. Similar question about Guyana originally that timetable for reaching full capacity or plateau was August now you’re an Exxon, of course, talking about December, how much have kind of social distancing restrictions or labor availability related to COVID have had with that four month delay?
John Hess
Obviously, it impacted repairs, but go ahead.
Greg Hill
Yes. 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, it’s going to take a little bit longer, but I will compliment Exxon Mobil profusely because they’ve had some 2,500 crew change events. And so far touchwood 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 amidst a pandemic.
Pavel Molchanov
Thanks very much.
Operator
Thank you very much. This concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.
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