Hess Corporation

Good day, ladies and gentlemen, and welcome to the second quarter 2020 HECS Corporation conference call. My name is Lateef, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. If at any time you require operator assistance, please press star followed by zero, and we will be happy to assist you. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Thank you, Lateef. 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 HESA's annual and quarterly reports filed with the SEC. Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplement information provided on our website. On the line with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Riley, Chief Financial Officer. As we did last quarter, in case there are any audio issues, we will be posting transcripts of each speaker's prepared remarks on www.hess.com following the presentations. 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 Riley 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 cargoes 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 loan, 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 company-wide cash costs. On our first quarter call, we announced the 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 Saybrook block, where Hess has a 30% interest in ExxonMobil as the operator, we have made 16 significant discoveries on the block since 2015. The current estimate of gross discovered recoverable resources for the block stand 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 lease of Phase I development which has an estimated break-even 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 Leesa Phase II development, with an estimated break-even 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 startup. The development of the PIAR 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 longstanding 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 1 and Scope 2 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 were 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 wanna 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 our 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 BACA 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 the 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 tidal 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 1st, as well as a planned nine-day maintenance shutdown at the Shemzee 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 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 LEASA Phase I 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 half. Further work to commission water injection and increase gas injection is underway. That should enable the Leesa Destiny FPSO to reach its full capacity of 120,000 gross barrels of oil per day in August. The Leesa Phase II development will utilize the Leesa Unity FPSO with a capacity to produce 220,000 gross barrels of oil per day. The project is progressing as planned, 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 PIAR development have been deferred pending government approval, creating a potential delay in production startup of 6 to 12 months. The Stenicarin and the Noble Tom Madden drill ships resumed work in late May and early June, respectively. The Santa Karen 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 Stanekaren will next move to the Kytur block, in which Hess holds a 15% working interest, to spud the Tanager 1 well, which is located 46 miles northwest of Leesa. The noble Don Taylor spudded the Redtail exploration well located approximately a mile and a quarter northwest of Yellowtail 1 on July 13. The well will target similar stratigraphic intervals as Yellowtail and will consist of an original hole and sidetrack and will include an option to conduct a 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 position us to successfully navigate these challenging times and to prosper when oil prices recover. I will now turn the call over to John Reilly.

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 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 30th, the VLCC volumes had total costs 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 30th, 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 two 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 $1,640,000,000, 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 30th, 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 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 costs. 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 to $40 million in the third quarter, and $140 to $150 million for the full year, which is down from previous guidance of $145 to $155 million. The midstream tariff is projected to be in the range of $220 to $230 million in the third quarter, and $905 to $930 million for the full year, which is unchanged from previous guidance. E&P income tax expense, excluding LIBIA, is expected to be in the range of $10 to $15 million for the third quarter and $20 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 to $50 million in the third quarter and $195 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 investments, Corporate expenses are estimated to be in the range of $25 to $30 million for the third quarter and unchanged for the full year in the range of $115 to $125 million. Interest expense is estimated to be in the range of $95 to $100 million for the third quarter and $375 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.

Ladies and gentlemen, if you have a question, please press star followed by 1 on your phone. If your question has been answered or you would like to withdraw your question, press the pound key. Questions will be taken in the order received. Please press star 1 to begin. Our first question comes from the line of Doug Leggett of Bank of America. Your question, please.

Thank you. Good morning, everybody. I hope everybody's 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 decline on a one-rig program going into 2021?

Yeah, 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. You know, with a two-rig program, we can hold it relatively flat. So there will be some decline on a one-year with a one-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 Baychase was still not done with their evaluation. The Tayara FPSO is already, you know, the hull is already complete. I think it's 14 months for the topside installation. In other words, it was already running ahead of schedule. So I'm just wondering if you can put some context around that, the six to twelve month delay because there seems to be some speculation out there that Payar has been pushed out much later, which was not my understanding. I guess it's 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. 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 result. I think it's really important to know the leadership of both major political parties has stated support for the state book 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, you know, what the potential impact is on the ultimate development timing and production timing of PIAR will be a function of, you know, 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's 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 of some of the drilling delays, have enabled us to optimize the resource to be developed for Shifts 4 and Shifts 5, 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 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 4 and 5 just because of our recent exploration and appraisal activities, but also building our inventory of tiebacks will also bring value forward. And then, you know, the third point I'd say is that, you know, we have a really exciting world-class inventory of future 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 decades. 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 full answer, guys. Appreciate it.

Thank you. Our next question comes from the line of Arun Jayaram of J.P. Morgan. Your question, please.

Yeah, good morning. Thus far, you have three penetrations in the early Cretaceous at Lisa Deep, Triple Tail Deep, and now Yellowtail Deep. Gregor, I was wondering if you could discuss some of the key conclusions thus far in this Antonio, and just broader thoughts on Yellowtail moving into the development queue, and perhaps you could also just kind of set the stage for Redtail.

Greg, why don't you go ahead on the early returns on some of the deeper opportunities for 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 Statebrook block. And then, of course, on the neighboring block in Suriname with Apache, we have penetrations there as well. So we obviously remain or are very excited about the potential of, you know, the San Antonio. As I've mentioned, you know, previously, it's just an older river system that looks very similar on seismic, you know, to the LESA type deltaic environment. Now, obviously, it's early days. So we've got to get a lot more penetrations in the San Antonio to understand it. And that will be the big, you know, will be a big part of the exploration and appraisal program going forward in the next couple years. But we remain very excited. Now, if we turn to yellowtail and kind of the redtail areas, I mentioned in my remarks that the redtail is going to target basically the same stratigraphic intervals as yellowtail. And the combination of yellowtail one, yellowtail two, and Red Tail is really going to form the basis of another FDSO development. You know, the partnership is looking at all, you know, the cadence and the development of, you know, which is going to be phase four and which is going to be phase five. Yellow Tail 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, you know, jumping the queue and being much earlier in the queue is certainly, you know, 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 called 220 or is it too early to say? Yes, it could. Okay. Okay. Great. And just my follow-up is just on LESA 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 Riley into the discussion, if he could discuss. We did observe a weaker realization in the quarter for the LESA crew. And just thoughts on how do you expect LESA oil pricing in Guyana to trend relative to Brent.

Yes. Greg, why don't you take the first one and John Riley will take the second one.

Sure.

Thanks, Arun.

Yes. Thanks, Arun. Currently, the focus remains on the commissioning work that I talked about in my opening remarks. 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 deep bottlenecking options. You know, we don't know exactly, you know, how much additional capacity that's going to add yet because the studies are ongoing. But what I will say is that that deep bottlenecking work will most likely occur in the first half of 2021. So we hope that you know, in the first half that we'll be able to get more capacity out of lease of phase one. But we'll quantify that amount in the future once we've chosen an option. Great.

And then, Arun, on the pricing for lease accrued, lease accrued 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 and quarter improvement in Brent prices.

Great. Thanks, John.

Sure.

Thank you. Our next question comes from the line of Paul Chang of Scotiabank. Your line is open.

Thank you. Good morning, guys. Morning. I know you're supposed 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. 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, you know, continuing with the one rig, and then that will be offset by higher spend in Guyana.

Okay. And secondly, that on the VFCC, can you tell us that what is the storage, shipping, and interest expense cost related to that six million debt? I mean, we know that you get a better price minimization 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. 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 differentials 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, maybe that you don't want to share because of commercial reasons, What's the actual cost? Can you tell us what is the net improvement you expect from those six million barrels compared to if you sell it down in the Gulf Coast?

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, it 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 the 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 entangled took care of all the costs. 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, 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. Okay. And on the gas plan 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 price is 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 TOCA plan turned around?

Greg will answer this, but it's all about safety and the welfare of our employees and contractors in the community where we do business. So it was a safety decision, a precaution, when 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. You know, there was spikes going on in that part of Texas as well. So we just made a conscious decision that, you know, 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 costs in the third quarter associated with the maintenance. So all that is moved to next year. But again, Paul, as everybody said, this was related to COVID and the safety of the employers, employees, contractors, and the local community.

Thank you.

Thank you. Our next question comes from the line of Brian Singer of Goldman Sachs. Please go ahead.

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 an earlier question you mentioned, earlier response you mentioned that you're optimizing the resource development for shifts 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. You know, 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 Lisa's, And the aerial extent and connectivity looks very encouraging for a bigger ship. So, Greg, you want to elaborate?

Yeah, sure. So, you know, Brian, I mean, pretty much what we saw was the same quality of reservoirs that were in Yellowtail 1. And as John mentioned, you know, those reservoirs are very much leaves alike. So very high-quality oil, very high-quality reservoirs. And then as we went over to Yellowtail 2, you know, as I mentioned by opening remarks, you know, we saw continuity with an existing very large, you know, aerial extent in Yellowtail. And then also a lower lobe, if you will, that also had very high quality hay and very high quality oil in it. So, you know, the result of that is, you know, the Yellowtail complex is just getting much bigger. And given the quality of the oil and the quality of the reservoir, you know, 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 a mile and a quarter away. we expect that that would further extend the aerial extent of those reservoirs. And so far, it 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 at future phases of the 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. Now, 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 Piara 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 two.

Yeah, and specifically, we have no plans to issue equity, Brian, and we're always looking to optimize our portfolio, and if there are some non-core 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 Janine Barclay. Your question, please.

Hi. Good morning, everyone.

Morning.

Morning.

Morning. My questions are kind of regulatory and policy related. I guess the first one, in terms of HESA's federal exposure and potential risk with the November election in the Gulf 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 well planned anyways for next year in the region, but we're just trying to understand, you know, what potential you have if there is some kind of ban next year.

Yeah, no, fair question, Janine. I think two points I'd like to make there. First, you know, we have less than 2.5% of our acreage in North Dakota on federal lands, and... would significantly reduce the Gulf of Mexico activity through 2021. You know, 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, you know, 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 that I know touches advantage with the fact that you have several rail parts that you own and optionality there. But can you address the capacity to move current dappled barrels by other means? And is there any specific logistical issues associated with getting that production to rail or whatever other options you have?

Sure. Excellent question. Look, the status of DAPL, you know, we continue to transport volumes on DAPL while we wait for a decision on the state. From the District Court of Appeals, we have 55,000 barrels a day of firm 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 HES 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 Reed of Wells Fargo. Please go ahead.

Yeah, thank you. Good morning.

Morning. Morning.

Just a couple questions to 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 21? Would you want to hedge again? You know, you can't get quite the prices we had this year. So, you know, on the forward curve, 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 two 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 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'm just curious, you know, have you seen enough at this point where you would say the expectations are being met by reality here?

Yeah, great, good. Reservoir performance, LIZA.

Absolutely. I mean, the wells are, these are amazing wells, they're 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 HASA 1 prospect has fallen out. It looks to be the largest, at least, area under closure prospect remaining in the inventory, and I thought it was going to be drilled at some point this year. Could I get an update on that?

Yeah, Greg? Yeah, Bob. So the plan is that we do hope to spot that well before the end of the year. It's the next in queue on the expiration order, so... you know, hopefully the noble Don Taylor will be able to spud that well before the end of the year. It's working. It's going, obviously, from bread tail, and it's going to do some phase two, you know, producers, and then we'll go to HOSA after that. So depending on, you know, 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 Duckelbaum of Cohen. Your line is open.

Good morning, guys. Thanks for your time today.

Thank you.

Just a question. You talked about before requiring two rigs to hold the buck and 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 buck and volume, or is the strategy now to just accrete that cash to the balance sheet to maximize liquidity?

Yeah, no. You know, we would want WTI to be in the range of $50 for us to consider to bring a 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 – you know, 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, I know just kind of trying to put a – a bow around Piara. When you originally guided the six to 12 month potential deferral, I guess, how was 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?

Yeah, a 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 6- 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 comes from Jeffrey Kimball of Toy Brothers. Your line is open. Thank you, and good morning.

First, I'd like 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? 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. Anyway, Greg, why don't you provide some perspective on our activities in the Gulf?

Yeah, you bet. Again, the Gulf of Mexico is a key heartland 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. Obviously, it remains a key for us. In the last five years, we've acquired 60 leases in the Gulf of Mexico for a grand total of $120 million. very good price, you know, for all those leases. And, you know, it's really composed of three things. A, ILX kind of near infrastructure opportunities. B, Miocene greenfield hub opportunities. And then thirdly, you know, the Cretaceous play, which really got de-risked by the Norfolk, right? Everyone thought the Norflot was going to be tombstone, and of course, you know, Shell and Chevron found not only very high-quality sands, but very thick sands. And the Cretaceous, you know, is sandwiched between the Miocene and the Norflot. So obviously, in order for crude to make it from the source, you know, rock all the way to the Miocene, it had to pass through both the Norflot 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, you know, partners, so we de-risk it. But these are very large, you know, hub class opportunities. So, you know, BD had Galapagos in the queue in 2020, given it's a large prospect. Again, sandwiched between the Norfolk 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, you know, Miocene, and this Cretaceous play. Obviously, as crude prices move up, we'll want to get back to work. you know, in the Gulf of Mexico on our own things. And, you know, first in the queue is going to be some of those ILX opportunities like, you know, a second well at ESOX. But again, we need to see a little bit higher crude price before we do that. But we did Galapagos because the opportunity was now.

Yeah, on the BP Galapagos prospect, it was purely, you know, 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, you know, 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 market stabilizing and strengthening. Okay.

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 and McHugh, could this support selling down any 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, you know, our company is always looking to optimize the value of our portfolio, but, you know, 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. It's a high return and low cost. Nothing competes with it in the industry.

Great. Thank you. I appreciate it. Thank you. Our next question comes from Ryan Todd of Simmons Energy. Your question, please.

Good, thanks. Maybe just a couple quick numbers related ones. First, on CapEx, the second quarter CapEx is a little bit lower versus guidance, despite a pretty solid number of well completions in the bottom end. What are you seeing on leading-edge joint and completion costs in the Bakken versus what you anticipated in your full-year budget?

Greg, do you want me to take that?

Yeah, sure, John.

Oh, okay. So from a well-cost standpoint, if you saw, we did the DNC. We did drop our DNC costs 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, you know, I think it's just the normal efficiencies. Greg and his team are continuing to drive that down. Yes, Bakken from within our original billion nine and what we guided from the last quarter is down a bit more from last from the last quarter because of the efficiencies there. But overall, with the portfolio, $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 us at our $1.9 billion capital spend.

Thanks. And then maybe just a quick one. I mean, you mentioned when you provided guidance on cash artifacts, really strong on the quarter. Is this primarily just a mix or a volume beat issue, or 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 really good performance across the portfolio from a production standpoint. And our costs on an absolute basis came in 10% lower than guidance, and that was across the portfolio. So nothing... in particular, but 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.

Good. 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 in relation 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 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 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 typical.

Yeah, sure. So, you know, getting down to that $6 million, two-thirds of that was supply chain and one-third is, you know, efficiencies, further efficiencies. Now, as we look forward, you know, there's probably going to be minimal supply chain concessions. So, most of that we've already realized, but as we look forward, through further manufacturing applications and also technology, you know, we think we can get that cost down lower. So, we think next year there will be a five-handle in the number versus a six.

Great. I'll leave it there with one, but thanks so much. I hope you all are well.

Thanks a lot.

Thank you. Our next question comes from Pavel Makhanov of Raymond James. Your line is open.

Thanks for taking that 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.

Yeah, there are 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, do you want to talk about the steps we've taken? Sure.

Yeah, sure. So, you know, certainly in the, you know, Bakken has the advantage of, you know, 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 ten people. And those people stay together. And so we keep social distance between pods and organize the work such that you don't expose, you know, large numbers of 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, you know, we require testing and then, of course, you know, extended hitches offshore, again, to minimize, you know, 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, you know, exposure as well. So, you know, as a result of the measures we've taken, I mean, all of our field operations are continuing to produce, you know, 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.