赫斯 (HES) 2021 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Second Quarter 2021 Hess Corporation Conference Call. My name is Liz, and I will be your operator for today. (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, Liz. 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. In case there are any audio issues, we will be posting transcripts of each speaker's 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. Today, I will review our continued progress in executing our strategy and our long-standing commitment to sustainability. Greg Hill will then discuss our operations, and John Rielly will cover our financial results.

Our strategy is to grow our resource base, have a low cost of supply and sustain cash flow growth. Executing this strategy has positioned our company to deliver industry-leading cash flow growth over the next decade and has made our portfolio increasingly resilient in a low oil price environment. Our strategy aligns with the world's growing need for affordable, reliable and cleaner energy that is necessary for human prosperity and global economic development. We recognize that climate change is the greatest scientific challenge of the 21st century and support the aim of the Paris Agreement and a global ambition to achieve net 0 emissions by 2050. The world faces a dual challenge of needing 20% more energy by 2040 and reaching net 0 carbon emissions by 2050.

In the International Energy Agency's rigorous sustainable development scenario, which assumes that all pledges of the Paris Agreement are met, oil and gas will be 46% of the energy mix in 2040 compared with approximately 53% today. In the IEA's newest net 0 scenario, oil and gas will still be 29% of the energy mix in 2040. In either scenario, oil and gas will be needed for decades to come and will require significantly more global investment over the next 10 years on an annual basis than the $300 billion spent last year. The key for our company is to have a low cost of supply by investing only in high-return, low-cost opportunities; the best rocks for the best returns.

We have built a differentiated and focused portfolio that is balanced between short-cycle and long-cycle assets. Guyana is our growth engine and the Bakken, Gulf of Mexico and Southeast Asia are our cash engines. Guyana is positioned to become a significant cash engine in the coming years as multiple phases of low-cost oil developments come online, which we expect will drive our portfolio breakeven Brent oil price below $40 per barrel by the middle of the decade.

Based on the most recent third-party estimates, our cash flow is estimated to grow at a compound annual growth rate of 42% between 2020 and 2023, which is 75% above our peers and puts us in the top 5% of the S&P 500, with a line of sight for up to 10 FPSOs to develop the discovered resources in Guyana. This industry-leading cash flow growth rate is expected to continue through the end of the decade. Investors want durability and growth in cash flow. We have both.

We are pleased to announce today that in July, we paid down $500 million of our $1 billion term loan maturing in March 2023. Depending upon market conditions, we plan to repay the remaining $500 million in 2022. This debt reduction, combined with the start-up of Liza Phase 2 early next year, is expected to drive our debt to EBITDAX ratio under 2 next year. Once this debt is paid off and our portfolio generates increasing free cash flow, we plan to return the majority to our shareholders, first, through dividend increases and then opportunistic share repurchases.

In addition, we announced this morning that Hess Midstream will buy back $750 million of its Class B units from its sponsors, Hess Corporation and Global Infrastructure Partners to be completed in the third quarter. We expect to receive approximately $375 million in proceeds, and our ownership in Hess Midstream on a consolidated basis will be approximately 45% compared with 46% prior to the transaction.

On April 30, we completed the sale of our Little Knife and Murphy Creek nonstrategic acreage interest in the Bakken for a total consideration of $312 million, effective March 1, 2021. This acreage, most of which we were not planning to drill before 2026, was located in the southernmost portion of our Bakken position and was not connected to Hess Midstream infrastructure. The midstream transaction and the sale of the Little Knife and Murphy Creek acreage bring material value forward and further strengthen our cash and liquidity position.

The Bakken remains a core part of our portfolio and our largest operated asset. We have a large inventory of future drilling locations that generate attractive financial returns at $50 per barrel WTI. In February, when WTI oil prices moved above $50 per barrel, we added a second rig. Given the continued strength in oil prices, we are now planning to add a third rig in the Bakken in September, which is expected to strengthen free cash flow generation in the years ahead.

Key to our long-term strategy is Guyana, with its low cost of supply and industry-leading financial returns. We have an active exploration and appraisal program this year on the Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator. We see the potential for at least 6 FPSOs on the block by 2027, and up to 10 FPSOs to develop the discovered resources on the block. And we continue to see multibillion barrels of future exploration potential remaining.

Earlier today, we announced a significant new oil discovery at Whiptail. The Whiptail #1 well encountered 246 feet of net pay. And the Whiptail #2 well, which is located 3 miles northeast of Whiptail-1 encountered 167 feet of net pay in high-quality oil-bearing sandstone reservoirs. Drilling continues at both wells to test deeper targets. The Whiptail discovery could form the basis for our future oil development in the southeast area of the Stabroek Block and will add to the previous recoverable resource estimate of approximately 9 billion barrels of oil equivalent.

In June, we also announced a discovery at the Longtail-3 well, which encountered approximately 230 feet of net pay, including newly identified high-quality hydrocarbon-bearing reservoirs below the original Longtail-1 discovery intervals. In addition, the successful Mako-2 well, together with the Uaru-2 well, which encountered approximately 120 feet of high-quality oil-bearing sandstone reservoir will potentially underpin a fifth oil development in the area east of the Liza complex.

In terms of Guyana developments, the Liza Unity FPSO with a gross capacity of 220,000 barrels of oil per day, is expected to sail from Singapore to Guyana in late August, and the Liza-2 development is on track to achieve first oil in early 2022. Our third oil development on the Stabroek Block at the Payara Field is expected to achieve first oil in 2024, also with a gross capacity of 220,000 barrels of oil per day.

Engineering work for our fourth development on the Stabroek Block at Yellowtail is underway with preliminary plans for our gross capacity in the range of 220,000 to 250,000 barrels of oil per day and anticipated start-up in 2025, pending government approvals and project sanctioning. Our 3 sanctioned oil developments have a breakeven Brent oil price of between $25 and $35 per barrel. And according to a recent data from Wood Mackenzie, our Guyana developments are the highest margin, lowest carbon intensity oil and gas assets globally.

Last week, we announced publication of our 24th Annual Sustainability Report, which details our environmental, social and governance, or ESG strategy and performance. In 2020, we significantly surpassed our 5-year emission reduction targets, reducing Scope 1 and 2 operated greenhouse gas emissions intensity by 46% and flaring intensity by 59% compared to 2014 levels.

Our 5-year operated emission reduction targets for 2025, which are detailed in the sustainability report, exceed the 22% reduction in carbon intensity by 2030 in the International Energy Agency's sustainable development scenario, which is consistent with the Paris Agreement's ambition to hold the rise in global average temperature to well below 2 degrees centigrade. We are also contributing to groundbreaking research being done 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. In May, Hess was named to the 100 Best Corporate Citizens list for the 14th consecutive year based upon an independent assessment by ISS-ESG. And we were the only oil and gas company to earn a place on the 2021 list.

In summary, oil and gas are going to be needed for decades to come. By continuing to successfully execute our strategy and achieve strong operational performance, our company is uniquely positioned to deliver industry-leading cash flow growth over the next decade. As our term loan is paid off and our portfolio generates increasing free cash flow, the majority will be returned to our shareholders, first, through dividend and increases and then opportunistic share repurchases.

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

Thanks, John. In the second quarter, we continued to deliver strong operational performance. Companywide net production averaged 307,000 barrels of oil equivalent per day, excluding Libya, above our guidance of 290,000 to 295,000 barrels of oil equivalent per day, driven by good performance across the portfolio.

In the third quarter, we expect companywide net production to average approximately 265,000 barrels of oil equivalent per day, excluding Libya, which reflects the Tioga gas plant turnaround in the Bakken and planned maintenance in the Gulf of Mexico and Southeast Asia. For full year 2021, we now forecast net production to average approximately 295,000 barrels of oil equivalent per day, excluding Libya, compared to our previous forecast of between 290,000 and 295,000 barrels of oil equivalent per day. So we're now forecasting to be at the top of the range.

Turning to the Bakken. Second quarter net production averaged 159,000 barrels of oil equivalent per day. This was above our guidance of approximately 155,000 barrels of oil equivalent per day, primarily reflecting increased gas capture, which has allowed us to drive flaring to under 5%, well below the state's 9% limit.

For the third quarter, we expect Bakken net production to average approximately 145,000 barrels of oil equivalent per day, which reflects the planned 45-day maintenance turnaround and expansion tie-in at the Tioga gas plant. For the full year 2021, we maintain our Bakken net production forecast of 155,000 to 160,000 barrels of oil equivalent per day.

In the second quarter, we drilled 17 wells and brought 9 new wells online. In the third quarter, we expect to drill approximately 15 wells and to bring approximately 20 new wells online. And for the full year 2021, we now expect to drill approximately 65 wells and to bring approximately 50 new wells online.

In terms of drilling and completion costs, although we have experienced some cost inflation, we are confident that we can offset the increases through technology and lean manufacturing efficiency gains and are therefore maintaining our full year average forecast of $5.8 million per well in 2021.

We've been operating 2 rigs since February, but given the improvement in oil prices and our robust inventory of high-return drilling locations, we plan to add a third rig in September. Moving to a 3-rig program will allow us to grow cash flow and production, better optimize our in-basin infrastructure and drive further reductions in our unit cash costs.

Now moving to the offshore. In the deepwater Gulf of Mexico, second quarter net production averaged 52,000 barrels of oil equivalent per day compared to our guidance of approximately 50,000 barrels of oil equivalent per day. In the third quarter, we forecast Gulf of Mexico net production to average between 35,000 and 40,000 barrels of oil equivalent per day, reflecting planned maintenance downtime as well as some hurricane contingency. For the full year 2021, our forecast for Gulf of Mexico net production remains approximately 45,000 barrels of oil equivalent per day.

In Southeast Asia, net production in the second quarter was 66,000 barrels of oil equivalent per day, above our guidance of approximately 60,000 barrels of oil equivalent per day. Third quarter net production is forecast to average between 50,000 and 55,000 barrels of oil equivalent per day, reflecting planned maintenance at North Malay Basin and the JDA as well as Phase 3 installation work at North Malay Basin. Full year 2021 net production is forecast to average approximately 60,000 barrels of oil equivalent per day.

Now turning to Guyana. In the second quarter, gross production from Liza Phase 1 averaged 101,000 barrels of oil per day or 26,000 barrels of oil per day net to Hess. The repaired flash gas compression system has been installed on the Liza Destiny FPSO and is under test. The operator is evaluating the test data to optimize performance and is safely managing production in the range of 120,000 to 125,000 barrels of oil per day. Replacement of the flash gas compression system with a modified design and production optimization work are planned for the fourth quarter, which will result in higher production capacity and reliability.

Net production from Liza Phase 1 is forecast to average approximately 30,000 barrels of oil per day in the third quarter and for the full year 2021. The Liza Phase 2 development will utilize the 220,000 barrels of oil per day Unity FPSO, which is scheduled to sail away from Singapore at the end of August and first oil remains on track for early 2022.

Turning to our third development, Payara. The Prosperity FPSO hull is complete and will enter the Keppel yard in Singapore following sail away of the Liza Unity. Topsides fabrication has commenced at Dyna-Mac and development drilling began in June. The overall project is approximately 45% completed. The Prosperity will have a gross production capacity of 220,000 barrels of oil per day and is on track to achieve first oil in 2024.

As for our fourth development at Yellowtail, the joint venture anticipates submitting the plan of development to the government of Guyana in the fourth quarter with first oil targeted for 2025, pending government approvals and project sanctioning.

During the second quarter, the Mako-2 appraisal well on the Stabroek Block confirmed the quality, thickness and aerial extent of the reservoir. When integrated with the previously announced discovery at Uaru-2, the data supports a potential fifth development in the area east of the Liza Complex. As John mentioned, this morning, we announced a discovery at Whiptail, located approximately 4 miles southeast of Uaru-1. Drilling continues at both wells to test deeper targets.

In terms of other drilling activity in the second half of 2021, after Whiptail-2, the Noble Don Taylor will drill the Pinktail-1 exploration well, which is located 5 miles southeast of Yellowtail-1, followed by the Tripletail-2 appraisal well located 5 miles south of Tripletail-1. The Noble Tom Madden will spud the Cataback-1 exploration well located 4.5 miles southeast of the Turbot-1 discovery in early August. Then in the fourth quarter, we will drill our first dedicated test of the deep potential at the Fangtooth prospect located 9 miles northwest of Liza-1.

In the third quarter, the Noble Sam Croft will drill the Turbot-2 appraisal well, then transition to development drilling operations for the remainder of the year. The Stena Carron will conduct a series of appraisal drill stem tests at Uaru-1, then Mako-2 and then Longtail-2.

In closing, we continue to deliver strong operational performance across our portfolio. Our offshore assets are generating strong free cash flow, the Bakken is on a capital-efficient growth trajectory, and Guyana keeps getting bigger and better, all of which positions us to deliver industry-leading returns, material cash flow generation and significant shareholder value.

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 2021 to the first quarter of 2021. Adjusted net income was $74 million in the second quarter of 2021 compared to net income of $252 million in the first quarter of 2021.

Turning to E&P. E&P adjusted net income was $122 million in the second quarter of 2021 compared to net income of $308 million in the previous quarter. The changes in the after-tax components of adjusted E&P results between the second quarter and first quarter of 2021 were as follows: Lower sales volumes reduced earnings by $126 million, higher cash costs reduced earnings by $48 million, higher exploration expenses reduced earnings by $10 million, all other items reduced earnings by $2 million for an overall decrease in second quarter earnings of $186 million.

Second quarter sales volumes were lower, primarily due to Guyana having two 1 million-barrel liftings of oil compared with three 1 million-barrel liftings in the first quarter, and first quarter sales volumes included nonrecurring sales of 2 VLCC cargos totaling 4.2 million barrels of Bakken crude oil, which contributed approximately $70 million of net income. In the second quarter, our E&P sales volumes were underlifted compared with production by approximately 785,000 barrels, which reduced our after-tax results by approximately $18 million.

Cash costs for the second quarter came in at the lower end of guidance and reflect higher planned maintenance and workover activity in the first quarter. In June, the U.S. Bankruptcy Court approved the bankruptcy plan for Fieldwood Energy, which includes transferring abandonment obligations of Fieldwood to predecessors entitled of certain of its assets who are jointly and severally liable for the obligations. As a result of the bankruptcy, Hess as one of the predecessors entitled in 7 shallow-water West Delta 79/86 leases held by Fieldwood is responsible for the abandonment of the facilities on the leases.

Second quarter E&P results include an after-tax charge of $147 million, representing the estimated gross abandonment obligation for West Delta 79/86 without taking into account potential recoveries from other previous owners. Within the next 9 months, we expect to receive an order from the regulator requiring us along with other predecessors entitled to decommission the facilities. The timing of these decommissioning activities will be discussed and agreed upon with the regulator, and we anticipate the cost will be incurred over the next several years.

Turning to Midstream. The Midstream segment had net income of $76 million in the second quarter of 2021 compared to $75 million in the prior quarter. Midstream EBITDA, before noncontrolling interest, amounted to $229 million in the second quarter of 2021 compared to $225 million in the previous quarter.

Now turning to our financial position. At quarter end, excluding Midstream, cash and cash equivalents were $2.42 billion, which includes receipt of net proceeds of $297 million from the sale of our Little Knife and Murphy Creek acreage in the Bakken. Total liquidity was $6.1 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 2024, and we have no material near-term debt maturities aside from the $1 billion term loan which matures in March 2023. In July, we repaid $500 million of the term loan. Earlier today, Hess Midstream announced an agreement to repurchase approximately 31 million Class B units of Hess Midstream held by GIP and us for approximately $750 million. We expect to receive net proceeds of approximately $375 million from the sale in the third quarter. In addition, we expect to receive proceeds in the third quarter from the sale of our interest in Denmark for a total consideration of $150 million with an effective date of January 1, 2021.

In the second quarter of 2021, net cash provided by operating activities before changes in working capital was $659 million compared with $815 million in the first quarter, primarily due to lower sales volumes. In the second quarter, net cash provided by operating activities after changes in working capital was $785 million compared with $591 million in the first quarter. Changes in operating assets and liabilities during the second quarter of 2021 increased cash flow from operating activities by $126 million, primarily driven by an increase in payables that we expect to reverse in the third quarter.

Now turning to guidance. First, for E&P. Our E&P cash costs were $11.63 per barrel of oil equivalent, including Libya, and $12.16 per barrel of oil equivalent, excluding Libya, in the second quarter of 2021. We project E&P cash costs, excluding Libya, to be in the range of $13 to $14 per barrel of oil equivalent for the third quarter, which reflects the impact of lower production volumes resulting from the Tioga gas plant turnaround. Full year cash cost guidance of $11 to $12 per barrel of oil equivalent remains unchanged.

DD&A expense was $11.55 per barrel of oil equivalent, including Libya, and $12.13 per barrel of oil equivalent, excluding Libya, in the second quarter. DD&A expense, excluding Libya, is forecast to be in the range of $12 to $13 per barrel of oil equivalent for the third quarter and full year guidance of $12 to $13 per barrel of oil equivalent remains unchanged. This results in projected total E&P unit operating costs, excluding Libya, to be in the range of $25 to $27 per barrel of oil equivalent for the third quarter and $23 to $25 per barrel of oil equivalent for the full year of 2021.

Exploration expenses, excluding dry hole costs, are expected to be in the range of $40 million to $45 million in the third quarter and full year guidance is expected to be in the range of $160 million to $170 million, which is down from previous guidance of $170 million to $180 million.

The midstream tariff is projected to be in the range of $265 million to $275 million for the third quarter and full year guidance is projected to be in the range of $1.080 billion to $1.100 billion, which is down from the previous guidance of $1.090 billion to $1.115 billion. E&P income tax expense, excluding Libya, is expected to be in the range of $35 million to $40 million for the third quarter and full year guidance is expected to be in the range of $125 million to $135 million, which is updated from the previous guidance of $105 million to $115 million, reflecting higher commodity prices. We expect noncash option premium amortization will be approximately $65 million for the third quarter and full year guidance of approximately $245 million remains unchanged.

During the third quarter, we expect to sell three 1 million-barrel cargoes of oil from Guyana. Our E&P capital and exploratory expenditures are expected to be approximately $575 million in the third quarter. Full year guidance, which now includes increasing drilling rigs in the Bakken to 3 from 2 in September, remains unchanged from prior guidance at approximately $1.9 billion.

Turning to Midstream. We anticipate net income attributable to Hess from the Midstream segment to be in the range of $50 million to $60 million for the third quarter and full year guidance is projected to be in the range of $275 million to $285 million, which is down from the previous guidance of $280 million to $290 million.

Turning to corporate. Corporate expenses are estimated to be in the range of $30 million to $35 million for the third quarter and full year guidance of $130 million to $140 million remains unchanged. Interest expense is estimated to be in the range of $95 million to $100 million for the third quarter and approximately $380 million for the full year which is at the lower end of our previous guidance of $380 million to $390 million, reflecting the $500 million reduction in the term loan.

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

(Operator Instructions) Your first question comes from the line of Ryan Todd with Piper Sandler.

Maybe starting off on Whiptail. Congratulations on the great results of both Whiptail 1 and 2. How do you think -- maybe it's a little early to say, but how do you think about ultimate potential resource size, reservoir and oil quality? And how it maybe stacks up against other future resources to be developed and where it could land in the queue?

Yes. Great question, Ryan, and thank you. Look, Whiptail drilling activities are still underway. We're going to be drilling in both wells to some deeper targets. Whiptail adds to our queue of high-value potential oil developments in Guyana, Uaru and Mako, as Greg talked about, have the potential to be our fifth FPSO. Whiptail has the potential to be another oil development. And since evaluations work is still going underway, it's a little premature to talk about resource size. But definitely, what we're seeing is a foundation for potentially another oil development with Whiptail.

And then to remind everybody, we still have a very active exploration and appraisal program on the Stabroek Block the remainder of this year, which should provide even more definition for future development investment opportunities. So the queue of high-value potential oil developments is growing, and we're going to optimize it as we continue to get more data and well results to further get clarity on what the queue will be.

And Ryan, the quality of the reservoirs in Whiptail are outstanding.

All right, John and Greg. Maybe a follow-up on CapEx. Prior year guidance for 2021 Bakken CapEx is $450 million. Is that still the same with the addition of the third rig in September? Or was the possibility of a third rig already built in there? And you've been running low on CapEx, obviously, in the first half of the year, but activity is accelerating in the second half. Is there a potential for maybe downward pressure on CapEx on a full year basis? Or is the kind of the trend upward in the second half likely to -- or I guess, have things trended in line with where you would have expected?

John?

Yes. So from the Bakken standpoint, no, we did not have the third rig in our initial guidance of the $450 million for the year. So that third rig is adding to the Bakken capital, so will go up from that $450 million. But like you've been saying, we have been running under for the first half and where it is primarily right now, we're underspending in Guyana, so that pretty much the add from September to December for the 1 rig in the Bakken is being offset by a little lower spend in Guyana.

As for the $1.9 billion, we do, as you said, expect to ramp up. It's normal for us in the Bakken, when you get into the summer season, building infrastructure pads, things like that. So we do get a pickup on capital there. Same thing for our work in Southeast Asia, is more ramping up. Greg had mentioned the Phase 3 installation that's going on. So I do expect to be spending right around that $1.9 billion, and we'll get that pick up. But again, we have been a little bit lower, and that's why we can add that Bakken rig and stay at $1.9 billion.

Our next question comes from Arun Jayaram with JPMorgan.

My first question is on Liza Phase 2. I know the design is a 220 kbd, but I was wondering if the Hess-Exxon consortium is applying some of the learnings from the Liza Phase 1 debottlenecking project on this ship. And where could initial predictive capacity be, as well as I wanted to get your time line to maybe first oil if the boat is sailing from Singapore at the end of August.

Thanks, Arun. Greg?

Yes. Sure, Arun. So we are on track for first oil in early 2022. So no change to that first oil date that we talked about before. In regards to debottlenecking, look, my experience with these FPSOs is, yes, there will be some additional capacity that can be rung out of the vessel. The sequence is important, though. So the first thing you do is you get it out there, spin it up, run it at full operating conditions, then and only then after you get that dynamic data can you understand where your potential pinch points or bottlenecks are. And so that's why typically these optimization projects don't come until, I'll say, the first year of operation. But I think 15% to 20% is not atypical. It will vary boat by boat depending on the dynamic conditions, but I would think that you could get some additional upside from Phase II and Phase III and beyond.

Great. My follow-up is for John Hess. John, I wanted to see if you could help us think about the order of operations here regarding additional cash return to shareholders. And maybe outline paying off the term loan, maybe the timing of step 2 if the strip holds and when we could see Hess and the Board kind of move on the dividend.

Yes. Look, once we pay the $500 million off, which we're intending to do next year from the term loan, thereafter, as a function of oil price and we get visibility on free cash flow generation, the next priority is going to be returning the majority of that free cash flow to our shareholders. And the first priority in that will be to increase our base dividend. So this is something we've talked about with our Board. We're very watchful about it, but we got to take it a step at a time. But that will be the sequence of events; pay the other $500 million off, we're estimating to do that next year depending upon market conditions. And then once after that, once we start to have visibility on free cash flow and the market conditions for oil and the financial markets are supportive, the next step will be strengthening our base dividend.

Your next question comes from David Deckelbaum with Cowen.

I just wanted to just touch on the Bakken again. With the addition of the third rig, could you perhaps revisit guidance for where an exit rate should be at the end of this year? And then should we be thinking about the addition of a fourth rig? I just wanted that in the context of what the current in-house view is of the truly optimized program there in terms of activity.

John, you want to take the exit rate? And then, Greg, any color you'd like to provide as well?

Sure. So from the Bakken exit rate standpoint, the addition of the third rig when we're starting in September really is not going to add any wells in for production this year. And what we had said in the prior quarter was that we were exiting somewhere at the 170,000 to 175,000 type level as we ended the year. Now what we are seeing is higher propane prices than we saw back in April, so -- which we like, right, that the -- what we see from the NGL price is actually to increase our cash flow in the third quarter maybe $35 million to $40 million based on these higher propane prices. But with those higher propane prices, if you remember, that means we get less volumes under our percentage of proceeds contracts or our POP contracts. So right now, based on what we're seeing on the propane prices, I'd say the exit rate overall will be in the 165,000 to 170,000 range. I think, Greg, I'll hand it over to you for the fourth rig.

Yes. So I think just 1 -- couple of more comments on the third rig. So with that third rig, we'll drill 10 more wells. So that's why we increased our drilling well count from 55 to 65. And then we'll also bring 5 more wells online with that third rig. So that's why we raised the wells online count from 45 to 50. But as John said, those wells come on right at the end of the year. So the impact of that will be seen in 2022's volumes.

The fourth rig, as we've always talked about, the primary role of the Bakken in our portfolio is to be a cash engine. So that's its #1 role. So any decision to add any rigs in the Bakken is going to be driven by returns and corporate cash flow needs. Now having said that, assuming oil prices stay high into next year, then we'd consider adding a fourth rig at the end of next year. Why is it at the end? Because you build all your locations in the summertime. And then by doing so, that would allow us to take Bakken production up to around 200,000 barrels a day. And that level really optimizes our in-basin infrastructure.

But again, that's going to be a function of oil price, a function of corporate cash flow needs, how much cash do we need the Bakken to deliver for the corporation. That's going to be the primary driver of whether or not we add that fourth rig or not. I will say, the fourth rig would be the last rig. So the highest we would go is 4 rigs, and we could maintain that 200,000 barrels a day with 4 rigs for nearly a decade given the extensive inventory of high-return wells that we have.

You seem well prepared for that question. Appreciate the color. My follow-up is just going quickly on Libya. You've seen, obviously, the end of the force majeure, you've seen production kind of pick up there. I know you guys guide ex Libya. But can you kind of revisit the productive capacity of that asset and your view kind of the rest of the year? And then just broadly speaking, where that sits in your portfolio?

Yes. Libya, obviously, it generates some cash for us. It has been running at fairly stable levels, and we would estimate those levels would continue at the current rate. And it really is a function of political security, stability in the country, which has increased. And so we would intend that Libya would continue at the pace of cash generation that it's at now in the future.

Your next question comes from Roger Read with Wells Fargo.

Just one question to follow up on just from the comments earlier about well cost staying flat in the Bakken. But as you step back and look at cost inflation, almost anywhere, I know you're relatively silent in the Gulf of Mexico today, but there will be expectations for next year. And then as we think about building the FPSOs or any sort of, I guess, supply chain issues that may be affecting anything as we think about the next, like FPSO -- FPSO 2 and FPSO 3 as we think about the timing in Guyana.

Yes, Greg, why don't you please handle it, the cost inflation question that he's asking, one, maybe we covered the onshore focusing on the Bakken and to the offshore?

Yes, sure. So let's talk about the onshore first because it's the easiest. Yes, as I said in my opening remarks, we are seeing some minor inflation in the Bakken. At the first half of the year, it was all tubulars. However, recall we prebought all of our tubulars for the program this year. So we're covered on that. Commodity-based chemicals, obviously, have gone up. But it really doesn't matter because we're able to cover that through technology and lean manufacturing gains. And that's why we held our well cost forecast for the year still at $5.8 million, even though we're feeling some single-digit kind of levels of inflation.

Now if I turn to the offshore, yes, industry is seeing cost increases there as well. Day rates on deepwater rigs are up modestly. They're nowhere near what they were in the halcyon days of, say, 5 years ago. But remember, almost all of our offshore investment is in Guyana. And we operate under EPC contracts there, so that largely insulates us from cost increases after the contract is signed. And then I've got to say ExxonMobil is doing an extraordinary job of utilizing this "design one, build many" strategy to deliver a large amount of efficiencies from that project. So certainly, now and in the very near term, I wouldn't expect any cost issues there. And of course, because of PSC, if your costs do creep up, that's all covered under cost recovery.

That's helpful. And then congratulations on the discovery certainly that had been announced today and recently. I was just curious, some of the other exploration opportunities you have out there as we think about other blocks inside of Guyana, but also over in Suriname. Any updates there?

Well, the majority of our drilling is going to be on the Stabroek Block. And I think Greg gave pretty good road map for what our drilling the rest of the year is going to be. It's going to be a comment of exploration and appraisal. I think, Greg, the only other thing to talk about is Suriname, probably Block 42 because we do have some drilling plan there next year.

Yes, we do. So planning is underway on Block 42 for a second exploration well in the first half of 2022. Obviously, the Apache wells are encouraging for our acreage there that's adjacent to 42, and we see the acreage as a potential play extension also from the Stabroek Block. So we're the ones that have access to not only the Stabroek data, but also the data in Suriname. So we can couple those 2 together and really understand how the geology lays out there, and that's what makes us excited about Block 42.

We also have an interest in Block 59, as you know, just outboard at 42. ExxonMobil has completed a 2D seismic survey on the block there. The data has been analyzed and assessed, and so the joint venture is now planning a very targeted 3D survey over some interesting prospects we see on that as well. But drilling there would not begin to occur until probably '23 at the earliest.

Your next question comes from Paul Cheng with Scotiabank.

John, you guys are going to generate a fair amount of the free cash and you're going to pay down the term debt next year. But longer term, do you have a net debt target, how much debt you really want to be sitting on your balance sheet at all?

Thanks, Paul. So our target and what I always say it's a maximum target is a 2x debt-to-EBITDAX target. So as you said, when we pay off this term loan next year and we have Phase 2 coming online, we're going to drive under that 2x. So there's -- and what I expect here because I think as we mentioned earlier, we really don't have any material near-term debt maturity. So what we'll do is we'll pay off that term loan, we have small amounts in 2024, and it's not until 2027 that we have our next big maturity. So we'll just pay off the small maturities as we have, and we'll continue to let our EBITDAX grow. Basically, you're going to get Phase 2, then Payara, then Yellowtail, then Uaru-2. So we're going to have significant growth in EBITDA and our balance sheet is just going to get stronger and stronger from that standpoint.

So what I would say is we'd hold that absolute debt level flat and decrease it for the maturities that come about. And then as John mentioned, we're going to start driving significant free cash flow generation. And once that term loan is paid off, we'll start with dividend increases, and then we'll move on to the opportunistic share repurchases.

John, some of your peers that when they're talking about, say, 2x EBITDA or that 1x or less than 1x, they also identify or that with the parameter that what -- under what commodity price they are using, not necessarily using the current price. So do you guys just look at what is at the current price to your EBITDA or you also target at a lower price, the maximum 2x?

No, we look at even lower prices. What I would say is that target is there for us no matter what the commodity price is. And look, we always say this, as the additional FPSOs come on, as John said, these very low-cost developments come on, our margins and our cash flow just continues to improve. So even at lower commodity prices, when we start getting Payara, Yellowtail, Uaru, Mako online, we're going to have significant free cash flow and the balance sheet is going to be very strong. So our target doesn't vary based on commodity prices. And we'd like to say that with these FPSOs coming on, we can win in any commodity price environment.

And John -- I think John Hess has said that the first priority of the excess free cash after the term loan payoff is increasing the dividend. Is there any kind of parameters you can share in terms of you will set the dividend longer term based on, say, 10% of a certain cash flow from operation based on certain oil price or any kind of parameters that you can share or metrics you can share, so we can have some better understanding of what is the trajectory?

Sure. What we've been saying right now -- and look, we'll give guidance as we get into this free cash flow generation is that we want to have a dividend that's better than the S&P 500, right, yield? And why? Because obviously, the oil and gas business is a little riskier and more volatile due to commodity prices. So we want to set that at a level that gives us a better yield. And we're going to be in a position, again, as I mentioned with these FPSOs coming on that we can set that, have a better yield and withstand lower commodity prices. So we'll test it at lower commodity prices. But again, due to the uniqueness of the Guyana cash flows that will be coming in, we can do that. So that's the initial guidance I would look at is that we're going to have our yield better than that S&P 500.

Final question. I think this is for Greg. Greg, when we look at your full year production guidance, which implied the second half of about 280,000 and you say the third quarter is about 265,000. So that means that the fourth quarter is about 300,000. Is that a bit conservative that -- on that number?

Well, first of all, Paul, it's still early in the year. So we've got a lot of activity going on. We've got Tioga turnaround, maintenance in the Gulf of Mexico, maintenance in Southeast Asia, and also some shutdowns for Phase 3 in North Malay Basin, plus we did dial in a fair amount of hurricane contingency this year in the Gulf just based upon last year's experience, but also what the weather forecasters are saying this year. So we'll be able to update that on the quarterly call next time. I hope you're right. I hope it is conservative. But again, we have a fair amount of contingency in there for the work that we are doing and the hurricanes that are anticipated in the Gulf. So let's just see how it plays out.

Maybe let me ask it in this way, Greg. In the fourth quarter, do you have any meaningful turnaround or maintenance shutdown activities?

We do have some in the fourth quarter, yes, and some of those are in Southeast Asia, and we also have a turnaround in Baldpate in the Gulf of Mexico during the fourth quarter as well. But the hurricane contingency really rolls through both quarters, so.

Your next question comes from Doug Leggate with Bank of America.

I'll just speak to 2 questions, if that's okay. But let me see if I can get them both in. Greg, I'm going to try have another go at Whiptail. I seem to recall in our prior conversations that you had built up quite a picture of how large this prospect could be. Now you've got 2 of the biggest sands, 3 miles apart. Am I out of turns saying that this could be more than 1 development phase on Whiptail?

Go ahead, Greg.

No, I -- look, I think it's early days to be saying that, Doug. One of the reasons we drilled the wells concurrently is because we did have good seismic response, as you intimated, on Whiptail. We were well calibrated with that because, of course, it was a sandwich between Yellowtail and Uaru. And so by drilling both of these wells concurrently, obviously, we accelerated the evaluation and appraisal of this highly prospective area. We've got more appraisal work to do and some deepening to do in and around these areas. But we're very pleased with the results, but I think it's just too early to speculate on. Is this big enough stand-alone by itself or what? So just give us some time to evaluate our well results.

Yes, Doug. Great question. We're still drilling, still evaluating the results, but certainly, we're very encouraged that this could underpin on its own future oil development. The foundation is there. More work needs to be done to get that definition, but it certainly has the potential to provide a foundation for future oil development. And you also got to remember on Yellowtail as we got more evaluation work in, that obviously turned out to be a much bigger resource, which is why the ship for Yellowtail is being sized between 220,000 and 250,000 barrels a day, which is bigger than the 2 ships that proceeded at 220,000 barrels a day. So let's get more drilling, let's get more evaluation, but obviously, initial results are very encouraging.

Greg, maybe I will do a part 1a before I go on to John. Just when you think about these hub sizes, what are you thinking about the plateau levels of production nowadays? Are we thinking about one on top of the other or early phases declining? How are you thinking about that given the scale of the resource you have right now? Just so we can calibrate everybody, results and expectations over time.

No. Again, Doug, you and I have talked about this before. I think these hubs -- all hubs, frankly, will have a long plateau and longer than would be typical in a deepwater environment, and that's simply because of the resource density of how much is in the Guyana Basin in and around these existing hubs. So not only is there additional tieback opportunity in the Campanian, i.e., is Liza class reservoirs, but as we go deeper in the Santonian, let's say that works out as a technical commercial success, then you could see where you could tie back Santonian into some existing Campanian hubs. So if you step back and look at all the prospectivity in the Campanian, all the prospectivity in the Santonian, it's pretty easy to see that these hubs will be full for a long time.

My follow-up, hopefully, is a quick one. John Rielly, I don't want to press too much on this debt issue, but 2 things, EBITDA is a different number at $50 million than it is at $70 million. So I just wonder if I could ask you what your thinking is on the absolute level of debt that you want to get to because if Guyana is self-funding from next year, which I believe it is with Phase 2, the potential to generate a ton of free cash flow is obviously there, and I'm -- given you're unhedged on the upside. So just give us an idea of where you want the absolute balance sheet to be, and I'll leave it there.

Really, as John has said it earlier, once we pay off the $500 million on the term loan, we have the debt at the level we want it to be. As I said, there's a small maturity out in 2024 and no really big maturities out until 2027. So the debt is at that level, and we wouldn't be looking to reduce it any further at that point. And again, as we add the EBITDA from each FPSO, we will quickly drive under 2x, and then quite frankly, go below 1 as we continue to add these FPSOs.

Right. And Guyana is self-funding next year?

Guyana is -- so once Phase 2 comes on, Guyana is self-funding.

Your next question comes from Neil Mehta with Goldman Sachs.

I'll be quick here. But 2 related questions. The first, for you, John, which is, you always have a great perspective on the oil macro and there's a lot of uncertainty as we go into 2022. Less so maybe on the demand side, although we can debate that, but more on supply in terms of OPEC behavior and as barrels come back into the market, will the market get oversupplied or will inventory stay in deficit? So I'd love your perspective, especially given that you spend a lot of time with market participants there.

And then the related question is just on Hess' hedging strategy for 2022. Is it -- does it make sense to cost average in to the forward curve here? Or would you like to stay more open to participate in potential upside? So 2 related questions.

Thanks for the questions. The oil market is definitely rebalancing. It's 3 factors: demand, supply, inventories. We think demand is running right now at about 98 million barrels a day. Remember, pre-COVID, globally, it was running 100 million barrels a day. I think demand is well supported with people getting back to work, mobility data in the United States. Certainly, jet fuel is almost at pre-COVID levels of demand. Obviously, international travel is still down. Gasoline in the United States demand as well as gas oil demand is back at pre-COVID levels. So demand is pretty strong. I think the financial stimulus programs of the U.S. government and other governments across the world as well as accommodative monetary policies with the central banks are really turbocharging the consumer, turbocharging the economy and supporting oil demand. So we see demand growth continuing into next year. We think we will get by the end of the year, about 100 million barrels a day of global oil demand. We see that being stronger going into next year.

So I think that's a key part that you have to get grounded in to answer your question, what's the demand assumption and where -- we take it over that demand is going to continue to be strong going into next year through the year. Supply, you look at shale. Shale is no longer the swing supplier. It's gone from a business that's focused on production growth to one that's focused on return of capital, financial discipline, appropriately so. So if you can grow a little bit, but generally free cash according to the oil environment, that's what the investor discipline wants. That's what the company discipline wants.

So we see the rig count, maybe it gets up to 500 in the United States, but shale will not be growing at the level that it was growing at the last 5 years for what it's going to be growing in the next 3 or 4 years. I think U.S. production in the range of crude for, let's say, 11 million barrels a day, it's going to be hard to get into pre-COVID levels of 13 million barrels a day, probably for the next 3 or 4 years. So shale will play a role, but it's going to have a back seat in terms of being the swing supplier. The swing supplier going forward and really the Federal Reserve of oil prices is going to be OPEC led by -- or OPEC+ led by Saudi Arabia, Russia and the other members.

And I think they've been very disciplined, very wise and being very tempered about bringing their spare capacity back. They just made, I think, a very historic agreement that says we'll bring on 400,000 barrels a day month by month. We'll look at it if something happens in the variant, something happens with Iran coming on, we may curtail that. But basically, that 5.8 million barrels a day of excess capacity will be whittled down 400,000 a day each month as it goes out. They'll meet every month to check on that. But basically, that will be sort of that cushion that you need to keep supply up with demand. But in that scenario, the market is in deficit. So that should keep prices well supported.

And the other key point is I'd say, we're at pre-COVID inventory levels now where the glut of 1.2 billion barrels of oil excess supply a year ago April now has been whittled down to where the market is really back in balance at pre-COVID level. So looking forward, the macro, I think, is very supportive, demand growing faster than supply, inventory of pre-COVID levels and the oil price should be well supported in that environment.

And can you just tie that back into -- and that might be a question for John Rielly tie it into the hedging strategy.

Right. So Neil, our strategy is going to continue to be to use put options, right? We want to get the full insurance on the downside and leave the upside for investors. So obviously, we've been watching the market and the front has been performing very well and you know it is a bit backward dated as you go into 2022. And so with the put options, we typically put them on September to December, towards the end of the year. Time value gets the cost fee options a little bit lower. We'll see where volatility is as we move, getting closer to 2022. Now you should expect us to put on a significant hedge position, again, like we had this year, and you should expect to see it as we move into the fourth quarter, us begin to add those hedges.

To be clear, it will be a put-based strategy.

Your next question comes from Paul Sankey with Sankey Research.

A lot of my questions have been answered around the balance sheet. But I was just wondering if we could get a sense for the potential for acceleration on any of the moving parts here. The first would be, would debt pay down potentially be accelerated even faster than what you've talked about the term loan? If not, would we potentially see faster cash return to shareholders, so a quicker decision to raise the dividend? Is that a potential? Or I guess the alternative would be that you just increase cash on the balance sheet?

And then operationally, I guess, it's a little bit longer term, but could the pace of Guyana development be accelerated, do you think? Or is it a fairly set and predictable path here? And what I'm really wondering is, as you mentioned, the ExxonMobil buy one -- build one -- "design one, build many" strategy, I wonder if that has the potential to accelerate if we look forward 2 to 3 to 5 to 7 years. And finally, whether or not you would increase spending in a very strong story that you have here, in the Bakken or the deepwater Gulf of Mexico or anywhere else, if that was another potential outlet for the success you're enjoying?

Yes. Paul, good to hear your voice. Look, we've laid out our plan. We're going to be very disciplined about executing the plan. There are always, always potential to accelerate. It's a function of market conditions, obviously. But I think the key thing is we do want to keep a strong cash position as a cushion for downturns in the oil market. It certainly served us well last year, and it's serving us well this year. Obviously, very different markets between last year and this year.

And in terms of what our assumptions are going forward, we want to keep that strong cash position. And with current prices where they are, we think it's prudent to go into next year with a strong cash position so we can fund the high-value projects that we have in Guyana, in the Bakken and obviously, in our other 2 asset areas. So I think it's good planning assumption to assume that it will be -- given market conditions, we would pay that $500 million off next year. Always have the flexibility to move it forward. But we want to keep the strong cash position, and we just think that's a financial prudent strategy.

In terms of Guyana, Exxon is doing, as Greg said, a great job, managing a world-class project, both in terms of cost and in terms of timing. And this idea of "design one, build many" and pretty much getting in a cadence of one of these major FPSOs being built one a year, come on one a year, that cadence is probably as aggressive as any ever done in the industry. And ExxonMobil often talks about leakage. Leakage meaning capital inefficiency. This pace of bringing on 1 ship a year is probably as accelerated as you want to get, and it's a pretty darn good one.

Got it. And then the potential for greater spending, more growth? Is that -- would it be -- I assume you'd be more focused on cash return ultimately because the…

Yes. We're going to stay very financially disciplined. John talks about adding a third rig, and then Greg will talk potentially a fourth rig. Those can certainly be folded in. And actually, that increases our free cash flow generation in the years ahead. So it actually strengthens our free cash flow even though in the year of the investment, you go up a notch. But the Bakken is becoming a major free cash flow generator and on its way, let's say, to 200,000 barrels a day equivalent and plateauing. So there'll be, obviously, increase with rigs. John talks about it in the range of about $200 million per rig. And then you have the different developments that we have. But we're going to stay very focused on keeping a tight string on our capital investments, so we can grow the free cash flow wedge and really compound that free cash flow wedge over the next 5 to 6 years.

Brilliant. Could you -- can I just ask a color question on the Midstream? What was the strategic -- could you add any strategic color about the moves you made in the Midstream? And I'll leave it there.

Yes. Sure. Just at a high-level strategic standpoint, the Midstream continues to add differentiated value to our E&P assets. So it allows us to maintain operational and marketing control. It provides the takeaway optionality to multiple high-value markets. And also, it's driving our ability to increase our gas capture and drive down our greenhouse gas intensity. So just starting, Paul, at the high level, both GIP and us remain committed to the long-term value.

And so with this transaction, like pro forma for the transaction, Hess Midstream maintains a strong credit position. It's at 3x debt-to-EBITDA. And then it has continuing free cash flow after distributions as it moves forward. So that debt-to-EBITDA will come back down from 3. So it's going to have sustained low leverage and ample balance sheet capacity. So they really did this to optimize its capital structure. And then with this ample balance sheet capacity, it can support future growth or incremental return to shareholders, including Hess. And that can be this type of buyback or increased distribution.

So in another way of saying it, Hess Midstream becomes a free cash flow engine for Hess as well.

Your next question comes from Bob Brackett with Bernstein Research.

I had a question about Fangtooth. If I heard Greg right, he said it was 9 miles northwest of Liza-1. If I look at a seismic section that the operator ExxonMobil had in their Investor Day, they show a very large deep seismic signature that seems to correspond to where you're drilling Fangtooth. Am I over reading that? Or is this a fairly large structure that you're going to drill?

Greg, go ahead.

Yes, it is a very large structure that will be dedicated to the deeper stratigraphy, call it, lower Campanian and Santonian. So that will be our first stand-alone well targeting those deeper intervals. Bob, as you know, the rest have all been deep tails, but this will be a stand-alone. And yes, it is a very large structure.

Your next question comes from Noel Parks with Tuohy Brothers.

Just to sort of continue on from that last question. Could you just sort of maybe walk us through where things stand as far as main targets in Guyana versus deeper potential targets? Sort of -- so just kind of what you pretty much have established beyond the primary targets and sort of what's still to come.

Yes. Go ahead, Greg.

Sure. You bet. So when I talk about deeper plays, I'm really talking about the bottom of the Campanian, the lower Campanian and then down into the Santonian. And as I said before, these have the potential to be a very large addition to the recoverable resource base in Guyana. And if successful, as I mentioned previously, they could be exploited through a combination of tiebacks to existing hubs and/or stand-alone developments, if they're big enough. So we've had 8 penetrations to date in the deeper plays. And then if you couple that with the success in Suriname, which is we understand the better part over there, again, don't have the data, but this is just what we're hearing from others in the industry, appears to be kind of the lower Campanian-Santonian interval as well. So there's been a number of penetrations. So that's why we're encouraged.

Now we've got a lot more drilling to do to fully understand the potential of this play. So in the second half, we've got several more deep targets that are planned. Three will be what I call deepening. So there'll be deep tails on Campanian targets, 2 of which John mentioned in his script, which are Whiptail. So both Whiptail-1 and Whiptail-2 will be deepened down into the Santonian. The next one after that is Cataback and then also Pinktail will have a deep tail on it as well. And then as I just discussed with Mr. Brackett, there will be a deep stand-alone called Fangtooth. So just on the Stabroek Block, by the end of the year, we'll have 13 total penetrations in the deeper stratigraphy. So we'll begin to now understand better how it's all put together, where we think the hydrocarbons are, et cetera, et cetera. So keep watching this space, evolving story, but -- very exciting, but again, we need more drilling to figure out where and what we have.

Great. And just to sort of extend in the other dimension. I seem to remember that the report you had last quarter, 3 months ago, had some implications for aerial extent. And in this -- in the wells on the horizon, second half of the year, are there any of those that will be particularly informative about the sort of the aerial extent of the deeper zones?

Well, yes, it's a mosaic. It's a picture that we're trying to put together. So yes, I mean, we mentioned Fangtooth, for example, being a very large structure -- stratigraphic feature, I should say. Obviously, if that -- if the results of that are very positive, then we will probably want to follow up with an appraisal well or a second well in that given that the structure is quite large, right? But some of these tails will also inform the size of some of these as well because, of course, you're going after seismic features that you see on seismic that are of various sizes. Some are big and some are smaller. So by definition, we'll get a better understanding of that.

And Greg, that's a great perspective on some of the exploration potential, some of the appraisal potential, but you also might point out that we have a pretty active testing program between now and the end of the year to address the aerial extent and productivity of potential developments, you might talk about that.

Absolutely. So remember, we'll be doing drill stem tests at Uaru, at Mako and then also Longtail before the end of the year. So that will give us really key data to understand the size of those reservoirs in particular, so.

And ultimately, that helps us define the value of our -- and upgrade the value of our development queue for projects going forward. So a very active program for the rest of the year, new targets, appraising current targets and also testing them so we can upgrade the development queue of future oil projects.

And I would anticipate on those lines that eventually we'll do a DST at Whiptail as well.

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