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Hess Corp
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Good day ladies and gentlemen, and welcome to the Second Quarter 2020 Hess Corporation Conference Call. My name is Latif and I will be your operator for today. At this time, all participants are in a listen-only. Later, we will conduct a question-and-answer session [Operator Instructions] As a reminder, this conference is being recorded for replay purposes.
I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.
Thank you, Latif. Good morning, everyone, and thank you for participating in our second 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.
On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. As we did last quarter, in case there are any audio issues, we will be posting transcripts of each speakers prepared remarks on www.hess.com following the presentation.
I’ll now turn the call over to John Hess.
Thank you, Jay. Good morning everyone. Welcome to our second quarter conference call. We hope you and your families are all staying well during these challenging times. Today, I will discuss the steps we are taking to manage through a sustained period of low oil prices. Then Greg Hill will discuss our operations, and John Rielly will review our financial results.
In response to the pandemic’s severe impact on oil prices, our priorities 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 maximize the value of our production, in March and April, when U.S. oil storage was at tank tops, we used our marketing capabilities, our Hess Midstream infrastructure, and our firm transportation arrangements to the U.S. Gulf Coast to charter 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 million barrels has been sold at a premium to Brent for delivery in China in September. The other two VLCC cargos are expected to be sold in Asia in the fourth quarter. We further strengthened the company’s cash position and liquidity through a $1 billion three year term loan underwritten by JPMorgan Chase. This loan was successfully syndicated during the second quarter.
At the end of June, we had $1.6 billion of cash, a $3.5 billion undrawn revolving credit facility and no debt maturities until the term loan comes due in 2023. We made major reductions in our capital and exploratory budget for 2020, reducing it 37% from our original budget of $3 billion, down to $1.9 billion. The majority of this reduction comes from dropping from a six rig program to one rig in the Bakken, which we completed in May.
We also made significant cuts in our 2020 companywide cash costs. On our first quarter call, we announced a reduction of $225 million. During the second quarter, we identified an additional $40 million with further reductions anticipated. A key for us to preserve capability is continuing to operate one rig in the Bakken. Greg Hill and our Bakken team have made tremendous progress over the years in Lean manufacturing, which has delivered significant cost efficiencies and productivity improvements that we want to preserve for the future.
In terms of preserving the long term value of our assets, our top priority is Guyana, an extraordinary, world class asset. On the Stabroek Block, where Hess has a 30% interest and ExxonMobil is operator, we have made 16 significant discoveries on the block since 2015. The current estimate of gross discovered recoverable resources for the block stands at more than 8 billion barrels of oil equivalent, with multi billion barrels of exploration potential remaining. In June, we resumed a four rig drilling operation, with two of the rigs focused on development wells and two on exploration and appraisal activities. The Liza Phase one development, which has an estimated breakeven price of $35 per barrel Brent, achieved first production in December and is now expected to reach its full capacity of 120,000 gross barrels of oil per day in August.
The Liza Phase two development with an estimated breakeven price of $25 per barrel Brent and production capacity of 220,000 gross barrels of oil per day, remains on track for an early 2022 start-up. The development of the Payara field with a production capacity of 220,000 gross barrels of oil per day has potentially been deferred six to 12 months, pending government approval to proceed. Planning for the fourth and fifth FPSOs is underway, which will be further optimized by this year's exploration and appraisal drilling results.
Our strategy is guided by our company's long-standing commitment to sustainability, which creates value for all our stakeholders. Earlier this month, we announced publication of our 23rd Annual Sustainability Report, which details our environmental, social and governance or ESG strategy and performance.
In terms of safety, since 2014, we have reduced our severe safety incident rate by 36% and achieved a 67% reduction in process safety incidents. In the critical area of climate change, we have reduced scope one and scope two equity greenhouse gas emissions by approximately 60% over the past 12 years. We also are contributing to groundbreaking work by the Salk Institute to develop plants with larger root systems that are capable of absorbing and storing potentially billions of tons of carbon per year from the atmosphere.
We continue to be recognized as an industry leader for the quality of our ESG performance and disclosure. And in May we're named to the 100 Best Corporate Citizens list for the 12th consecutive year, earning the number one ranking for an oil and gas company and ranking number nine on the list overall.
In summary, our long-term strategy has enabled us to build a high-quality and diversified portfolio that is resilient in a low price environment and puts us in a strong position to prosper when oil prices recover. Our portfolio provides long-term resource growth with multiple phases of low-cost Guyana oil developments that are expected to drive industry-leading cash flow growth over the course of the decade. As our portfolio generates increasing free cash flow, we will prioritize debt reduction and increasing cash returns to shareholders.
Finally, we want to thank our employees for their continued commitment to operating safely and reliably during this pandemic. The safety of our workforce and the communities where we operate will remain our top priority.
I will now turn the call over to Greg for an operational update.
Thanks, John. In the second quarter, we continued to deliver strong operational performance across our portfolio. Company-wide net production averaged 334,000 barrels of oil equivalent per day, excluding Libya, which was above the top end of our guidance of 310,000 to 315,000 barrels of oil equivalent per day.
This was driven both by strong results in the Bakken, where advantaged infrastructure position enabled us to avoid shedding in production and by higher nominations in Southeast Asia, where demand is increasing as the economy recovers.
In the third quarter, we expect company-wide net production to be in the range of 320,000 to 325,000 barrels of oil equivalent per day excluding Libya. This reduction from the second quarter reflects planned downtime in the Gulf of Mexico. Our production guidance for full year 2020 is now approximately 330,000 net barrels of oil equivalent per day excluding Libya, up from our previous guidance of approximately 320,000 barrels of oil equivalent per day.
In the Bakken, we've been operating one rig since May, down from six rigs earlier in the year. Operating one rig allows us to maintain key operating capabilities that we have worked hard to build over the years both within Hess and among our primary drilling and completion contractors.
In the second quarter, our Bakken team once again delivered strong results, capitalizing on the success of our plug and perf completion design and mild weather conditions. Second quarter Bakken net production averaged 194,000 barrels of oil equivalent per day, an increase of 39% from the year ago quarter and above our guidance of approximately 185,000 barrels of oil equivalent per day.
Following our successful transition to plug and perf completions, further efficiency gains combined with cost reductions across our supply chain allowed us to achieve an average drilling and completion cost per well of approximately $6 million in the second quarter. We believe that through the application of technology and lean manufacturing techniques that we can continue to push our D&C costs even lower.
For the third quarter, our guidance for Bakken net production is approximately 185,000 barrels of oil equivalent per day. As announced by Hess Midstream earlier this month, the planned maintenance turnaround at Tioga Gas Plant originally scheduled for the third quarter of 2020 will now be deferred until 2021 to ensure safe and timely execution in light of the COVID-19 pandemic. The Tioga Gas Plant expansion project is well advanced and is expected to be completed by the end of 2020.
The resulting incremental gas processing capacity will be available in 2021 upon completion of the turnaround. For the full year 2020, our guidance for Bakken net production is approximately 185,000 barrels of oil equivalent per day, up from our previous guidance of 175,000 barrels of oil equivalent per day.
Moving to the offshore. In the deepwater Gulf of Mexico, second quarter net production averaged 68,000 barrels of oil equivalent per day. The Esox-1 well, which came online in February is expected to reach its 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 in the third quarter, and to average approximately 5,000 barrels of oil equivalent per day net to Hess in 2020.
No other production wells are planned to be drilled in 2020 in the Gulf of Mexico. However, we are participating in the BP-operated Galapagos deep exploration well with a 25% working interest in this hub-class cretaceous-aged opportunity in the Mississippi Canyon area, the well spud in May and is still drilling.
In the third quarter, our guidance for Gulf of Mexico net production is expected to be between 50,000 and 55,000 barrels of oil equivalent per day reflecting planned maintenance of third-party-operated facilities that will shut in Conger and Llano for approximately 40 days beginning August 1 as well as a planned nine-day maintenance shutdown at the Shenzi field.
For the full year 2020, our guidance for Gulf of Mexico net production is approximately 65,000 barrels of oil equivalent per day. In the Gulf of Thailand, production in the second quarter was 44,000 barrels of oil equivalent per day above our guidance of approximately 35,000 barrels of oil equivalent per day.
During April, natural gas nominations reflected slower economic activity associated with COVID-19, but nominations began to rebound in the second half of the quarter as the restrictions on movement were lifted and economy began to recover. Our guidance for our third quarter and full year 2020 net production is between 50,000 and 55,000 barrels of oil equivalent per day.
Now turning to Guyana. Production from Liza Phase 1 commenced in December 2019 and in the second quarter averaged 86,000 gross barrels of oil per day or 22,000 barrels of oil per day net to Hess. Further work to commission water injection and increased gas injection is underway that should enable Liza Destiny FPSO to reach its full capacity of 120,000 gross barrels of oil per day in August. The Liza Phase 2 development will utilize the Liza Unity FPSO with a capacity to produce 220,000 gross barrels of oil per day.
The project is progressing to plan with approximately 75% of the overall work completed and first oil remains on track for early 2022. As previously announced, some activities for the planned Payara development have been deferred pending government approval, creating a potential delay in production start-up of six to 12 months.
The Stena Carron and the Noble Tom Madden drillships resumed work in late May and early June respectively. The Stena Carron rig recently completed appraisal drilling at Yellowtail-2 located one mile southeast of Yellowtail-1. The well identified two additional high quality reservoirs, one adjacent to and the other below the Yellowtail field further demonstrating the world-class quality of this basin. This additional resource is currently being evaluated and will help form the basis for a potential future development.
The Stena Carron will next move to the Kaieteur Block in which Hess holds a 15% working interest to spud the Tanager-1 well, which is located 46 miles northwest of Liza. The Noble Don Taylor spudded the Redtail exploration well located approximately 1.4 mile northwest of Yellowtail-1 on July 13. The well will target similar stratigraphic intervals as Yellowtail and will consist of an original hole and side track and will include an option to conduct the drill stem test in the future. Results of Redtail-1 and Yellowtail-2 will be incorporated into our evaluation of the Yellowtail area.
In closing we continue to focus on strong execution across our portfolio while ensuring the safety of our workforce and the communities where we operate in the midst of the COVID-19 pandemic. We have taken significant steps in response to the low oil price environment that positioned us to successfully navigate these challenging times and to prosper when oil prices recover. I will now turn the call over to John Rielly.
Thanks Greg. In my remarks today, I will compare results from the second quarter of 2020 to the first quarter. We incurred a net loss of $320 million in the second quarter of 2020 compared to an adjusted net loss of $182 million in the first quarter. For E&P, E&P incurred a net loss of $249 million in the second quarter of 2020 compared to an adjusted net loss of $120 million in the previous quarter.
The changes in the after-tax components of adjusted E&P results between the second quarter of 2020 and the first quarter of 2020 were as follows: lower realized selling prices reduced results by $115 million. Lower sales volumes reduced results by $128 million. Lower DD&A expense improved results by $53 million. Lower cash costs improved results by $38 million. Lower midstream tariffs improved results by $16 million. All other items improved results by $7 million for an overall decrease in second quarter results of $129 million.
For the second quarter, sales volumes were underlifted compared with production by approximately 3.9 million barrels of oil of which 3.7 million barrels of oil was associated with our previously announced VLCC strategy which was implemented to enhance 2020 cash flow and the value of our Bakken production.
As part of this strategy an additional 2.3 million barrels of Bakken crude will be loaded on VLCC tankers in the third quarter. At June 30 the VLCC volumes had total cost of $113 million included in inventory on the balance sheet and a corresponding reduction to marketing expenses on the income statement.
In addition at June 30, we deferred $85 million of realized gains on derivative contracts associated with these volumes. The first VLCC cargo of approximately 2 million barrels of oil has been sold for delivery in China in September at a premium to Brent prices.
As a result income from the sale will be reflected in the third quarter and cash proceeds will be received in the fourth quarter. The remaining 2 VLCC cargoes containing approximately 4 million barrels of oil are expected to be sold in Asia in the fourth quarter.
Now turning to Midstream. The Midstream segment had net income of $51 million in the second quarter of 2020 compared to $61 million in the previous quarter reflecting lower throughput volumes. Midstream EBITDA on an adjusted basis and before non-controlling interest amounted to $172 million in the second quarter of 2020 compared to $193 million in the previous quarter. Turning to corporate, after-tax corporate and interest expenses were $122 million in the second quarter of 2020 compared to $123 million in the previous quarter.
Now turning to our financial position, at quarter end excluding Midstream cash and cash equivalents were $1.64 billion and our total liquidity was $5.3 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.
During the second quarter we successfully syndicated our $1 billion term loan with a maturity date in March 2023. We have no near-term debt maturities aside from the new term loan. We have hedged over 80% of our remaining crude oil production for 2020. At June 30, the fair value of open hedge contracts was approximately $450 million while realized settlements on closed contracts during the first six months of the year were approximately $500 million.
Now turning to guidance, our E&P cash costs were $8.81 per barrel of oil equivalent including Libya and $8.64 per barrel of oil equivalent excluding Libya in the second quarter. We project E&P cash costs excluding Libya to be in the -- to be in the range of $10 to $10.50 per barrel of oil equivalent for the third quarter which reflects the impact of planned maintenance shutdowns in the Gulf of Mexico and higher production taxes in North Dakota on increasing oil prices.
Full year guidance is expected to be in the range of $9.50 to $10 per barrel of oil equivalent which is down from previous guidance of $10 to $10.50 per barrel of oil equivalent reflecting the increased production guidance and further reductions to cost. This brings total cost savings to approximately $265 million for 2020 and we continue to look for further cost reduction opportunities.
DD&A expense was $15.45 per barrel of oil equivalent including and excluding Libya in the second quarter. DD&A expense excluding Libya is forecast to be in the range of $16 to $17 per barrel of oil equivalent for the third quarter due to a combination of planned maintenance shutdowns in the Gulf of Mexico, higher third quarter production from North Malay Basin and additional Bakken production related to the deferral of the turnaround at the Tioga Gas Plant to next year.
For the full year, DD&A expense is projected to be in the range of $16 to $17 per barrel of oil equivalent, which is up from prior full year guidance of $15 to $16 per barrel of oil equivalent. This results in projected total E&P unit operating costs excluding Libya to be in the range of $26 to $27.50 per barrel of oil equivalent for the third quarter and $25.50 to $27 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 third quarter and $140 million to $150 million for the full year, which is down from previous guidance of $145 million to $155 million. The midstream tariff is projected to be in the range of $220 million to $230 million in the third quarter and $905 million to $930 million for the full year, which is unchanged from previous guidance.
E&P income tax expense, excluding Libya, is expected to be in the range of $10 million to $15 million for the third quarter and $20 million to $30 million for the full year, which is unchanged from previous guidance.
Our crude oil hedge positions remain unchanged. We expect option premium amortization will be approximately $70 million for the third quarter and approximately $280 million for the full year which is unchanged from previous guidance.
For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be in the range of $40 million to $50 million in the third quarter and $195 million to $205 million for the full year, which is up from previous guidance of $185 million to $195 million due to the deferral of planned third quarter maintenance turnaround at the Tioga Gas Plant to 2021.
For corporate. Corporate expenses are estimated to be in the range of $25 million to $30 million for the third quarter and unchanged for the full year in the range of $115 million to $125 million. Interest expense is estimated to be in the range of $95 million to $100 million for the third quarter and $375 million to $380 million for the full year, which is at the lower end of our previous guidance of $375 million to $385 million.
This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.
[Operator Instructions] Our first question comes from the line of Doug Leggate of Bank of America. Your question, please.
Thank you. Good morning, everybody. I hope everybody is doing well out there. I guess, my first question is on the Bakken, my second one on Guyana. So Greg, first on the Bakken. Can you give us -- with the revised guidance, give us an update on how you see the exit rate and the decline on a 1-rig program going into 2021?
Yes. Doug, this is Greg. So the exit rate is going to be somewhere in the range of 170 to 175. And the reason is because we're projecting a little bit lower POP volumes in the fourth quarter with seasonal NGL prices coming up. So 170 to 175. As far as 2021, we're still in the throes of developing our plans for next year. So we'll give you guidance on that in January as always. What I will say though is we believe that we can hold production relatively flat if -- with a 2-rig program we could hold it relatively flat. So there will be some decline on a one year -- with a 1-rig program but we will give you that guidance in January.
Okay. That's really helpful. Thank you. My follow-up if I may is on Guyana and I've just got a couple of things related I guess. First of all, Greg obviously the election hasn't been resolved yet. I don't know if John wants to handle this one. But my understanding was that ISS-ESG was still not done with their evaluation the Payara FPSO is already -- the hull is already complete. I think it's 14 months for the top side installation.
In other words it was already running ahead of schedule. So I'm just wondering if you can put some context around the 6 month to 12 month delay? Because there seems to be some speculation out there that Payara has been pushed out much later, which was not my understanding. That's I guess is part one. And if I may squeeze a part two, it's really just if you could speak to the plateau implications of the deeper resource exploration success you've had on the early, let's say the first two, three, four FPSOs because it seems to me those plateaus are going to be a bit longer than perhaps you originally had planned for? And I'll leave it there. Thank you.
Doug, great questions. Hope you and your family are well as well. Look, the Court of Appeal in Guyana is expected to issue a ruling tomorrow, and we hope the ruling will provide further clarity on the election outcome. Ultimately, we expect the will of the Guyanese people will be expressed in this final results. I think, it's really important to know. The leadership of both major political parties has stated support for the Stabroek production sharing contract.
And in terms of Payara and moving the development forward, the joint venture is ready to move forward as expeditiously as possible as soon as the government is ready to do so. So I think that's the clarity there. And what the potential impact is on the ultimate development timing and production timing of Payara will be a function of us working forward with the government. So I wouldn't want to speculate more than that, but we're ready to move forward as soon as the government is ready to move forward.
In terms of the exploration success that we've had, the 16 discoveries, six of which these exploration wells were spud in 2019 most recently. They have – actually during this time some of the drilling delays have enabled us to optimize the resource to be developed for ships four and ships five, and ultimately lowering the cost per barrel and increasing the NPV of these discoveries. So just these six recent exploration discoveries that were spud in 2019 were – is going to bring value forward.
You're making a good point, which is I think a second point which is a number of these appraisals that we're drilling will be tiebacks, which will be value enhancers and extend the plateau. You're absolutely right on that. So I think it's both points optimizing ship four and five, just because of our recent exploration and appraisal activities, but also building our inventory of tiebacks will also bring value forward.
And then the third point, I'd say is that, we have a really exciting world-class inventory of feasible drillable prospects both in the Campanian where most of our discoveries have been made where the developments are currently moving forward, but also deeper horizons. Greg talked about one in Yellowtail and also the deeper Santonian. And this will really underpin low-cost barrel developments for many years to come, sustaining our trajectory of industry-leading cash flow growth from Guyana through the decade. So I think, hopefully, that provides some context for you in terms of how we think about the exploration potential, development potential, production potential of the world-class asset that we have in Guyana.
That's terrific. Thanks for the detail answer guys. Appreciate it.
Thank you. Our next question comes from the line of Arun Jayaram of JPMorgan. Your question please.
Good morning. Thus far you have three penetrations in the early cretaceous at Liza Deep, Tripletail deep and now Yellowtail deep. Gregory, I was wondering, if you could discuss some of the key conclusions thus far in the Santonian and just broader thoughts on Yellowtail moving into the development queue and perhaps you could also just kind of set the stage for Redtail?
Yeah. Greg, why don't you go ahead on the early returns on some of the deeper opportunities on how we feel about the prospectivity overall as Arun is asking?
Yeah, you bet. So Arun as you mentioned, we have several penetrations in the Stabroek Block, and then of course on the neighboring block in Suriname with Apache, we have penetrations there as well. So, we obviously remain – are very excited about the potential of the Santonian. As I've mentioned previously, it's just an older river system that looks very similar on seismic to the Liza-type deltaic environment.
Now obviously, it's early days. So we've got to get a lot more penetrations in the Santonian to understand it. And that will be the big – will be a big part of the exploration and appraisal program going forward in the next couple of years, but we remain very excited.
Now, if we turn to Yellowtail and kind of the Redtail areas, I mentioned in my remarks that Redtail is going to target basically the same stratigraphic intervals as Yellowtail. And the combination of Yellowtail-1 Yellowtail-2 and Redtail is really going to form the basis of another FPSO development. The partnership is looking at all the cadence and the development of – which is going to be Phase 4, and which is going to be Phase 5 Yellowtail is looking very promising. And of course, it's got some higher value than Hammerhead, because it's got a higher quality oil. So the potential for it jumping the queue and being much earlier in the queue is certainly a lot higher given what we've seen in Yellowtail-2 and what we expect to see in Redtail as well?
Could it support the larger ship size call it 220? …
Yeah.
Or is it too early to say?
Yes, it could.
Okay. Great and just my follow-up is just on Liza 1, you guys talked about getting to call it that 120, sometime in August. Could you discuss the potential of the facility to run above nameplate? And I also wanted to bring John Rielly in the discussion if he could discuss. We did observe a weaker realization in the quarter for the Liza crude. And just thoughts on how do you expect oil pricing in Guyana to trend relative to Brent?
Yeah. Greg, why don't you take the first one? And John Rielly will take the second one. …
Sure.
Thanks Arun.
Yeah. Thanks, Arun. So currently the focus remains on the commissioning work that I talked about in my opening remarks. So that's getting further in gas injection capacity and also water injection capacity. That work is ongoing. And we expect that we can ramp to full capacity, during the month of August of the 120,000 barrels a day or so.
Beyond that, the operator is evaluating de-bottlenecking options. We don't know exactly how much additional capacity that's going to add yet, because the studies are ongoing. But what I will say is that that de-bottlenecking work will most likely occur in the first half of 2021. So we hope that, in the first half that we'll be able to get more capacity out of Liza Phase 1. But we'll quantify that amount in the future once, we've chosen an option.
Great.
And then, Arun on pricing for Liza crude, Liza crude was pricing at Brent. And we continue to guide that it will be pricing at parity to Brent. So what you saw in the second quarter was that, we had two liftings, but both of those priced and delivered early in the quarter when Brent prices were very low. So when you're going to see our third quarter realizations, we'll reflect the quarter-on-quarter improvement in Brent prices.
Great. Thank you, John.
Sure.
Thank you. Our next question comes from the line of Paul Cheng of Scotiabank. Your line is open.
Thank you. Good morning guys.
Good morning.
I know this is a bit early. Maybe that -- John can you maybe at least from a direction standpoint on 2021 CapEx versus 2020, we expect to be up, down or roughly the same?
Sure, Paul. I mean, as you said it is early, and we will discuss our guidance as usual, in January. But where we are right now, we expect our 2021 capital spend to be flat to down, compared to 2020. And the big moving parts is we'll have lower spend in the Bakken, continuing with the one rig and then that will be offset by higher spend in Guyana.
Okay. And secondly that, on the VLCC, can you tell us that what is the storage shipping and interest expense costs related to that six million barrel? I mean, we know that you get a better price realization, when you sold it in Asia. But what is the incremental cost to get there?
So for -- as you said, so we have the first cargo and it was sold in China, as I mentioned at a premium to November, Brent prices. And I think I mentioned this last quarter, but we locked in the contango in the Brent market by obviously capturing the difference between the near month prices and prices at the expected sales date.
And then now as I mentioned, plus we are receiving an uplift in price differential of selling at a premium to Brent in the Asian market versus a significant discount that we would have had to WTI in the second quarter. So basically the combination of those two benefits more than offsets the cost of storing and transporting those volumes to the Asian market.
So again, we're not being specific. Each VLCC is different but, the way we locked it in and the contango. And then obviously picking up the better differential is making it a very profitable trade for our Bakken crude.
John you -- maybe that you don't want to share because of commercial reasons, what's the actual cost? Can you tell us that what is the net improvement you expect, from those six million barrel, comparing to you sell it down in the Gulf Coast?
Yeah. So, let me put it this way, because it gets to a hypothetical calculation. Because as you know Paul trying to move and sell barrels in the second quarter especially in May, we don't even know if we could have sold those barrels. And if we did sell those barrels would it have been even more than a discount we were seeing in the market.
So I think the best way to look at it, is as I said the move from WTI to Brent and locking in that Brent contango took care of all of the cost. You probably saw in May the differentials on WTI down at Gulf Coast say, $14 to $15 under WTI. And now we're picking up a premium to Brent.
So you can apply the difference in that discount plus the premium to all those barrels. So you can see for us it if one, -- as we talked about, we didn't want to shut in production. This allows us to sell these barrels in the same year versus if you shut in production you never would have gotten those barrels sold and got that cash flow plus it allowed us to enhance the value of the Bakken crude.
Okay. And on the gas plant turnaround, I'm actually a little bit surprised that you guys decided to delay it given the demand is relatively weak this year and hopefully next year will be better and the prices still hopefully next year will be better. Other than say maybe a cash flow issue, is there any reason that we really want to delay the Tioga plant turnaround?
Greg will answer this, but it's all about safety and the welfare of our employees and contractors of the community where we do business. So it was a safety decision a precaution and we absolutely know we did the right thing there.
But Greg do you want to elaborate at all? And then John can talk about any other financial impacts.
No. I think John you pretty much answered it. I mean, we saw a spike in Tioga that was not only some local workers, but also some of the people that we were going to bring in from the Gulf Coast for the turnaround. There were spikes going on in that part of Texas as well. So we just made a conscious decision that for the safety of our employees and for the safety of our community up there in Tioga that we did not want to introduce the potential for additional COVID cases. So again it was purely a safety based decision.
And then from a financial standpoint, obviously, we're picking up on an annual basis about 5,000 barrels a day of added production from it mostly natural gas and NGLs, actually all of the natural gas and NGLs from that. And then we'll have, obviously, less cost in the third quarter associated with the maintenance. So all that is moved to next year. But again Paul as Gregory said this was related to COVID and the safety of the employer’s, employees, contractors in the local community.
Thank you.
Thank you. Our next question comes from the line of Brian Singer of Goldman Sachs. Please go ahead.
I wanted to go back to Guyana if I can and go back to the Yellowtail reservoirs. Can you add any additional color on what's defining the high quality reservoirs from a thickness oil quality perspective? And you added some takeaways on more of the deeper reservoirs given multiple penetrations from industry and yourselves. Can you add any more color on the implications of the adjacent reservoirs?
And then in earlier question you mentioned -- earlier response you mentioned that you're optimizing the resource development for ships four and five lowering the cost per barrel and increasing the present value, is that a function of the better quality reservoirs that you're seeing, or is there something that you're doing with regards to the underlying cost structure for future development? Thank you.
Yeah. Greg will pick up on this. Great question Brian. Drilling and evaluation is still underway in Yellowtail. So some of the specificity you're asking for we can just talk contextually not specifically, but happy to do that and Greg will also shed some light in terms of the prospectivity that it's a higher quality oil more like Liza and the aerial extent and connectivity looks very encouraging for a bigger ship.
So Greg do you want to elaborate?
Yeah sure. So Brian I mean pretty much what we saw was the same quality of reservoirs that were in Yellowtail-1. And as John mentioned, those reservoirs are very much Liza like, so very high quality oil, very high quality reservoir. And then as we went over to Yellowtail-2 as I mentioned in my opening remarks, we saw continuity with an existing very large aerial extent in Yellowtail, and then also a lower lobe if you will, but also had very high quality pay and very high quality oil in it.
So the result of that is the Yellowtail complex is just getting much bigger. And given the quality of the oil and the quality of the reservoir, it makes a lot of sense to move that development forward, a, because it's higher capacity. And again it's got a much higher quality both crude oil and reservoir than say hammerhead, right.
And, of course, Redtail moving over again it's 1.25 miles away, we expect that that would further extend the aerial extent of those reservoirs. And so far looks like good continuity between everything. So that just bodes well for an extremely good development again at that higher capacity.
Great. Thank you. And then my follow-up John. You started the call talking about positioning the company to perform well in a sustained low oil price environment. And I wondered whether the free cash flow as future phases of Guyana ramp up if that is sufficient to meet your cash preservation goals, or if you see the need for asset sales or equity-linked issuance to reduce leverage?
Thanks Brian. No what we are planning -- the plan first of all that we put in place as John said that preserve cash, preserve capability and preserve long-term value is in this low price environment we wanted to get all the way through to Phase 2 in Guyana and be in a position then picking up, I'm just going to say approximately 60,000 barrels a day of Brent-based production coming into the portfolio. So once we can get to that Phase 2 and then obviously Payara comes on in Phase 4, we believe we can fund our way through that cycle and fund our investments in Guyana with our current positions that we have. Now obviously, we have tremendous liquidity as I mentioned earlier, but what we are looking at right now that even with the low oil price environment that we're not going to add debt to our balance sheet during this period. And again, we think we put a plan in place that gets us through to that Phase 2.
Yes. And specifically, we have no plans to issue equity Brian. And we're always looking to optimize our portfolio. And if there are some noncore assets that we can monetize to bring some of that cash forward, you can assume that we'll do that as we've done in the past.
Great. Thank you.
Thank you. Our next question comes from the line of Jeanine Wai of Barclays. Your question please.
Hi, good morning, everyone.
Good morning.
Good morning.
My questions are kind of regulatory and policy related. I guess the first one, in terms of federal exposure a potential risk with the November election in the coast of Mexico, can you discuss what optionality you have with permits? For example, how many do you have in hand? And what optionality you might have with leases? I know there wasn't any wells planned anyway for next year in the region, but we're just trying to understand what potential you have there as some kind of chance next year?
Yes. No fair question, Jeanine. I think two points I'd like to make there. First, we have less than 2.5% of our acreage in North Dakota on federal lands and with significantly reduced Gulf of Mexico activity through 2021. We don't anticipate any significant near impacts to Hess from any potential regulatory changes from a new administration. But I think the second point which is a very important one is that 23% of U.S. productions on -- of oil is on federal lands about two-thirds of that oil production is offshore Gulf of Mexico. And any proposals that would restrict our country's ability to explore, develop and produce that oil is going to be very bad for U.S. jobs, very bad for the U.S. economy and very bad for our national security. So we hope when people are thinking about future policy, when it comes to federal lands reason prevails, which would be in the interest of all U.S. taxpayers and consumers.
Okay. Great. Thank you very much for that answer. Also I guess my second question would be on DAPL sticking to North Dakota there. On the potential shutdown of the pipeline. Can you discuss how much capacity you have to move DAPL barrels by other transport means? And I know Hess is advantaged with the fact that you have several railcars that you own and optionality there. But can you address your capacity to move per DAPL barrels by other means? And if there are any specific logistical issues associated with getting that production to rail or whatever other options you have?
Yes, sure. Excellent question. Look the status of DAPL, we continue to transport volumes on DAPL while we wait for a decision on the stay from the District Court of Appeals. We have 55,000 barrels a day from transportation on DAPL. If DAPL is shut in, we have the capacity to move all of our Bakken production because of the flexibility provided by our marketing capability, our Hess Midstream infrastructure and our long-term commitments to multiple markets. And specifically, if DAPL were interrupted, rail would feature plus other pipeline systems that we move oil on currently would feature. So it would not have a major impact on moving all of our production, if DAPL were shut in and the cost to us would be a few dollars per barrel.
Okay. Great. Thank you very much.
Thank you.
Thank you. Our next question comes from Roger Read of Wells Fargo. Please go ahead.
Yeah. Thank you. Good morning.
Good morning.
Good morning.
I guess a couple of questions get into one kind of tying back to maybe Brian's question earlier about leverage and all that. How do you think about the hedging, which is obviously a big success this year as you look into 2021? Would you want to hedge again -- I can't get quite the prices we had this year. So on the forward curve, maybe it's not attractive enough right now. But I'm just curious how you're thinking about that and the overall managing of cash flow and CapEx?
Yes, Roger. That's clearly part of our plan to hedge in 2021. Because as we were talking about earlier, we know we are bridging to that Phase 2 in Guyana. And obviously, we've done the reduction in our capital spend. We've got the term loan. We did as you said have a strong position -- hedge position here for 2020. So as we move through the year, we like to keep with our strategy of using put options. So you can expect us to put options in the fourth quarter. Like you said, right now, from just the volatility and the time value of the put options, putting them on right now would be too expensive. However, as we get into the fourth quarter and get closer to 2021, you should expect us to put on hedges and to put on a significant hedge position, similar to what we did in 2020.
Okay. Thanks. And then my other question, more operational. We know about the issues that you had on the surface equipment at Liza. And I was just curious, how the wells have been performing or what you can give us there? I mean, obviously, talk about how good Yellowtail is from a reservoir standpoint, similar to Liza. And I was just curious, have you seen enough at this point where you would say, the expectations are being met by reality here?
Yes. Greg….
Yes.
Yellowtail performance, Liza.
Absolutely. I mean, the wells are -- these are amazing wells, or awesome wells and they're meeting or beating all of our expectations. So, great wells, no issue with wells whatsoever.
Okay. Thank you.
Thank you. Our next question comes from Bob Brackett of Bernstein Research. Your question, please.
Good morning. I had a question around Guyana and I'm curious about where the Hoss-1 [ph] prospect has fallen out. It looks to be the largest, at least, area under closure prospect remaining in the inventory. But I thought it was going to be drilled at some point this year. Could I get an update on that?
Yes, Greg?
Yes, Bob. So the plan is that we do hope to spud that well before the end of the year. It's the next in queue on the exploration order. So, hopefully, the Noble Don Taylor will be able to spud that well before the end of the year. It's working right -- it's going -- obviously, even Redtail and it's going to do some phase two producers and then we'll go to Hoss [ph] after that. So depending on how long all that takes, we should get it spud by the end of the year.
Okay. Thanks for that.
Thank you.
Thank you. Our next question comes from David Deckelbaum of Cowen. Your line is open.
Good morning. Thanks for the time today.
Thank you.
Just a question. You talked about before, requiring two rigs to hold the Bakken flat. I know the intention is to spend less next year overall assuming a one-rig program. Is there a move in commodities that would cause you to look at maintaining Bakken volumes, or is the strategy now to just accrete that cash to the balance sheet to maximize liquidity?
Yes. No, we would want WTI to be in the range of $50 for us to consider to bring that rig back. And our focus is to maximize cash flow generation for sure and that's going to be a dynamic between price -- the outlook for prices and keeping our liquidity strong. So again when we get to the end of the year, we'll be able to give more clarity on what our plans for the Bakken are. Right now, it's one rig. And as we go into next year, we'll make the decision according to where the market outlook is.
I appreciate that. And then, just the last one for me. Just -- I know, just kind of trying to put a bow around Payara. When you originally guided the six to 12-month potential deferral, I guess, how is the political process lining up with your expectations? And, I guess, what do we need to see happen in order to be able to adhere to that same guidance?
Yes. Newly elected government needs to be put in place. And as soon as it is, our joint venture will work closely with the government to move the development forward. Just for conservatism, we're talking about a six to 12-month delay. As a function of how it works out with this newly elected government, we'll be able to be more specific on the exact timing once we get the development approved, which we anticipate getting eventually.
I appreciate that as well. Thank you, guys.
Our next question from Jeffrey Campbell of Tuohy Brothers. Your line is open.
Thank you and good morning. First, I want to ask why you chose to invest in the BP Gulf of Mexico well rather than exploring your own tie-in targets of which Esox-1 was such a great success?
Greg you want to talk about our exploration strategy. And we have a position in the cretaceous and joint venturing and sharing risk with BP was the appropriate thing to do. It's not just that it's BP, it's also Hess. But anyway, Greg, why don't you provide some perspective on our activities in the Gulf?
Yes, you bet. So, again, the Gulf of Mexico is a key part land for us, great cash engine, plus we have the proven capability, not only on the exploration side, but also on the project delivery, which includes drilling and development of topside. So obviously, it remains a key for us. And in the last five years, we've acquired 60 leases in the Gulf of Mexico for a grand total of $120 million. So very good price for all those leases. And it's really composed of three things: a ILX kind of near infrastructure opportunities; b Miocene greenfield hub opportunities; and then thirdly, the cretaceous play which really get derisked by the Norphlet, right? Because everyone thought the Norphlet was going to be tombstone and of course Shell and Chevron found not only very high-quality sands, but very thick sands and the cretaceous sandwich between the Miocene and the Norphlet.
So obviously in order for crude to make it from the source rock all the way to Miocene that had to pass through both Norphlet and cretaceous. So the prospects that are in the cretaceous which we got a good position as John said, we also have a position that has partners. So we derisk it. But these are very large hub-class opportunities. So BP had Galapagos in the queue in 2020 given it's a large prospect. Again sandwiched between the Norphlet and the Miocene and the Mississippi Canyon area we said we will go ahead and drill it. So it's purely just a matter of where it came in the queue because again, we like all three opportunity sets that we have ILX, Miocene and this cretaceous play. Obviously as crude prices move up, we'll want to get back to work in the Gulf of Mexico on our own things. And first in the queue is going to be some of those ILX opportunities like a second well at Esox. But again, we need to see a little bit higher crude price before we do that so we did Galapagos because the opportunity was now.
Yes, on the BP Galapagos prospect it was purely a time issue. And when we say preserve cash preserve capability, preserve long-term value of assets obviously Galapagos fits in that latter category but there was a time constraint there. At the same time in this pricing environment, we're going to focus on preserving the cash. And our activity levels in the Gulf of Mexico are not anticipated to be very high until we get more visibility on oil prices and the oil markets stabilizing and strengthening.
Okay. Great. That was a very helpful explanation. I appreciate it. And then my other question was just on the subject of asset sales. With Yellowtail expanding and seemingly exceeding expectations and jumping ahead of Hammerhead in the queue could this support selling down an interest in lower quality Guyana assets if the price is right, or is there no such thing as a Guyana asset that's going to be for sale?
Well our company is always looking to optimize the value of our portfolio, but one of the lowest cost highest return investments in the industry is our position in Guyana. We see a lot more running room there and it's actually something if we could get more of it, we'd like more of it. So no, we don't have any interest in selling down. So high returns and low cost. Nothing competes with it in the industry.
Great. Thank you. Appreciated.
Thank you. Our next question comes from Ryan Todd of Simmons Energy. Your question, please?
Good. Thanks. Maybe just a couple of quick numbers related to ones. Firstly, on CapEx. Second quarter CapEx is a little bit lower versus guidance despite a pretty solid number of well completions in the Bakken. What are you seeing on leading edge during the completion costs in the Bakken versus what you anticipated in your full year budget?
Greg, do you want me to take that?
Yes. Sure, John. Yes.
Okay. So from a well cost standpoint if you saw we did -- the D&C, we did drop our D&C cost to $6 million in the quarter. That was our goal to get there by the end of the year. So we did achieve that a bit earlier. So we are getting some nice reductions there in the Bakken from that standpoint. Outside of that, I think it's just the normal efficiencies. Greg and his team are continuing to drive that down. Yes, Bakken from within our original $1.9 billion and what we guided from the last quarter is down a bit more from the last quarter because of the efficiencies there. But overall with the portfolio of $1.9 billion we're seeing a little bit more now with the rigs back operating in Guyana just a little bit more in the Guyana. So it's a nice offset and keeps a set our $1.9 billion capital spend.
And then maybe just a quick one on -- I mean you mentioned and you provided guidance on cash OpEx really strong in the quarter. Is this -- is this primarily just a mix or a volume beat issue, or are there some -- is there some underlying downward pressure that you're seeing on cash costs?
Well so for the Q2, I mean production did come in approximately 20,000 barrels a day above guidance, so we had a really good performance across the portfolio from a production standpoint. And our cost on an absolute basis came in 10% lower than guidance and that was across the portfolio. So nothing in particular, but look in this environment day in and day out, we're looking to take more and more costs out. And like we said earlier, we're continuing to look for further cost reductions and look to add to that $265 million that I mentioned earlier.
Great. Thank you.
Thank you. Our next question comes from Devin McDermott of Morgan Stanley. Your question, please.
Hey, good morning. Thanks for squeezing me in.
No, Devin, thanks a lot.
I just had a quick one to follow-up actually on the last point. It relates to some of the Bakken well cost reductions and looking at the $6 million that you achieved the quarter-over-quarter change is more on the completion side. But the question specifically is when you look at the driver of that reduction and meeting your year-end target early. Is that more supply chain deflation driven based on what's going on in the industry, or are there true structural improvements and efficiencies that you're finding and driving into the cost structure earlier than expected? I'm trying to get to what's structural change in the cost versus what might be?
Yes Greg?
Yes sure. So getting down to that $6 million, two-thirds of that was supply chain and one-third is efficiencies -- further efficiencies. Now as we look forward, there's probably going to be minimal supply chain concession. So, most of that we've already realized. But as we look forward through further lean manufacturing applications and also technology we think we can get that cost down lower. So we think next year there will be a five and in the number versus a six.
Great. I’ll leave it there. I just want to thanks so much. Hope you all well.
Thanks a lot.
Thank you. Our next question comes from Pavel Molchanov of Raymond James. Your line is open.
Thanks for taking the question. Just one question for me a bit high level though. You talked about kind of avoiding moving some personnel from Texas to North Dakota as a precautionary measure. More broadly though, can you just paint the visual picture of what you've been doing to enforce social distancing at your Bakken assets as well as in the Gulf of Mexico, obviously, two different facets of the portfolio?
Yes. There's significant protocols that are in place and we're very proud of our team to be operating safely and reliably during the COVID outbreak. But Greg, you want to talk about the steps we've taken?
Yes sure. So certainly in the -- Bakken has the advantage of being very spread out, right? But certainly we limit the size that people are allowed to gather in the same room. And then when we're doing work so for example on the Tioga expansion, when we're doing work we're confining the work to pods of workers that are typically anywhere from six to 10 people, and those people stay together. And so we keep social distance between pods and organize the work such that you don't expose large numbers of the people right to each other.
So that's the way that we've approached the work. That's worked very effectively and very well. And the one little spike that we did see in Tioga was one pod and it was confined completely to that pod, because of the practices that we used.
On the Gulf of Mexico, we require testing, and then of course, extended hitches offshore again to minimize exposure, and also our crew changes are kind of blitz, they used to be staggered, but now there's one single crew change. So that way you minimize exposure as well. So as a result of the measures we've taken, I mean, all of our field operations are continuing to produce with the appropriate safeguards. So, so far so good.
Thanks very much.
Thank you.
Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.