(Seeking Alpha, 28.Jul.2021) — The earnings call transcript from Hess Corporation’s (NYSE:HES) second quarter 2021 earnings conference call on 28 July 2021.
Jay Wilson – VP, Investor Relations
John Hess – Chief Executive Officer
Greg Hill – Chief Operating Officer
John Rielly – Chief Financial Officer
Conference Call Participants
Ryan Todd – Piper Sandler
Arun Jayaram – JPMorgan
David Deckelbaum – Cowen
Roger Read – Wells Fargo
Paul Cheng – Scotiabank
Doug Leggate – Bank of America
Neil Mehta – Goldman Sachs
Paul Sankey – Sankey Research
Bob Brackett – Bernstein Research
Noel Parks – Touhy Brothers
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. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes.
I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.
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 of any audio issues, we will be posting transcripts of each speakers prepared remarks on www.hess.com following the presentation.
I’ll now turn the call over to John Hess.
Thank you, Jay. Good morning everyone. Welcome to our second quarter conference call. Today, I will review our continued progress in executing our strategy and our longstanding 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 sustained 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 zero emissions by 2050.
The world faces a dual challenge of needing 20% more energy by 2040 and reaching net zero 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 Zero 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 30th, we completed the sale of our Little Knife and Murphy Creek non-strategic acreage interests 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 six 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 3 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 a future oil development in the southeast area of 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 a fourth development on the Stabroek Block at Yellowtail is underway with preliminary plans for gross capacity in the range of 220,000 to 250,000 barrels of oil per day and anticipated startup in 2025, pending government approvals and project sanctioning.
Our three sanctioned oil developments have a Brent breakeven 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 five-year emissions reduction targets reducing Scope 1 and 2 operated greenhouse gas emissions intensity by 46% and flaring intensity by 59%, compared to 2014 levels.
Our five-year operated emissions 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 the global average temperature to well below 2°C. 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 up on 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 increases and then opportunistic share repurchases.
I will now turn the call over to Greg Hill for an operational update.
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 are now forecasting 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 have been operating two 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 three 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 were 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 thousand 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 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 at Payara, the Prosperity FPSO hull is complete and will enter the Keppel Yard in Singapore following the 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 thousand 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 areal 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 Tripletail2 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 free 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 one-million barrel liftings of oil compared with three one-million barrel liftings in the first quarter and first quarter sales volumes included non-recurring sales of two 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 than the first quarter.
In June 2021, the U.S. Bankruptcy Court approved the bankruptcy plan for Fieldwood Energy which includes transferring abandonment obligations of Fieldwood to predecessors in title 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 in title in seven 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 nine months, we expect to receive an order from the regulator requiring us, along with other predecessors in title, to decommission the facilities. The timing of these decommissioning activities will be discussed and agreed upon with the regulator and we anticipate the costs 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 interests, 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 $1.0 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 interests in Denmark for 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 $13.00 to $14.00 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 costs guidance of $11.00 to $12.00 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 $12.00 to $13.00 per barrel of oil equivalent for the third quarter and full year guidance of $12.00 to $13.00 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 $25.00 to $27.00 per barrel of oil equivalent for the third quarter and $23.00 to $25.00 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 million to $1,100 million, which is down from the previous guidance of $1,090 million to $1,115 million.
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 non-cash 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 one-million barrel cargos 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 three from two 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 resource to be developed and where it can land in the queue?
Yes, it’s a 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 a 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 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, thanks. Thanks, John and Greg. Maybe a follow up on CapEx, prior guidance for 2021 Balkan CapEx is $450 million. Is that still the same with the addition of a 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 activities accelerated 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 things trending line with where you would have expected?
Yes. So from the Bakken standpoint, no, we did not have third rig in our initial guidance of the 450 million for the year. So that third rig is adding to the Bakken capital, so we’ll go up from that 450. But like you’ve been saying we have been running under for the first half and where it is primarily right now, we’re under spending in Ghana. So that pretty much the add from September to December for the one rig in the Bakken is being offset by a little lower spend in Ghana. As for the 1.9 billion we do as you said expect the 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 mentioned the phase three installation that’s going on.
So I do expect to be spending right around that 1.9 billion, and we’ll get that pickup. 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.
Yes. Good morning. My first question is on Liza Phase 2. I know the design is 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 timeline to maybe a 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 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 wrung out of the vessel. The sequence is important, though. So the first thing you do is, you get it out there, spin it out, run it at full operating conditions, then and only then after you get that dynamic data, can you understand where your potential pinch points are 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 a typical, it will vary boat by boat, depending on the dynamic conditions. But I would think that you could get some additional upside from Phase 2 and Phase 3 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 two of the strip holds and when we could see it in the board kind of move on the dividend.
Yes. Look once we pay the $500 million off, which we’re intending to do a 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, and 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 have visibility on free cash flow and market conditions for oil and the financial markets are supportive. The next step will be strengthening our base dividends.
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 to 175 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 — what we see from the NGL price is actually increase our cash flow in that 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 to 170 range. And then, Greg, I’ll hand it over to you for the fourth rig.
Yes. So I think just one couple 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 five 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 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 number one role. So any decision they 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, in the 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, the 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 have that fourth rig or not. I will say, the fourth rig would be the last rig. So the highest we would go is four rigs. And we could maintain that 200,000 barrels a day with four rigs for nearly a decade, given the extensive inventory of high return wells that we have.
Thank you, guys, you seem well prepared for that question. Appreciate the color. My follow up is just on — 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 is 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 costing 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 the 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, it’s FPSO and FPSO 2 and FPSO 3, as we think about the timing in Indiana.
Yes, Greg, why don’t you please handle it, the cost inflation question that he’s asking one, maybe we cover the onshore focusing on the Bakken and two the offshore?
Yes, sure. So, let’s talk about the onshore first because it’s easiest. Yes, as I said in my opening remarks, we are seeing some minor inflation in the Bakken. The first half of the year was all tubulars. However, we recall, we pre-bought all of our tubulars for the program this year. So we’re covered on that. Commodity base 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 five eight, even though we’re feeling some, single-digit kind of levels of inflation.
Now, if I turn to the offshore, yes, industry seeing cost increases there as well. Day rates on deepwater rigs are out modestly. They’re nowhere near what they were in the halcyon day say five 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 sign. And then I’ve got to say, Exxon Mobil is doing an extraordinary job of utilizing this design one build many strategy to deliver 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 the PSC, if your costs do creep up, that’s all covered under cost recovery.
That’s helpful. Thanks. And then congratulations on the discovery, certainly that have 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 Surinam, any updates there?
Well, the majority of our drilling is going to be on this Stabroek Block. And I think Greg gave pretty good roadmap 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 his Surinam probably Block 42 because we do have some drilling planned 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 42. And we see the acreage is 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 Surinam. And so we can couple those two 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 out] [ph]of Block 42, Exxon Mobil is completed the 2D seismic survey on the block there, the data has been analyzed. And it’s fast. 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 Scotia Bank.
John, you guys are going to generate a fair amount of free cash, and you’re going to pay down the term debt next year, but long-term, do you have a net debt target? How much debt you really want to be sitting on your budget at all?
So our target and what I always say it’s a maximum target is a two times debt to EBITDAX targets. So as you said is, when we pay off this term loan next year, and we have phase two coming online, we’re going to drive under that two times. And what I expect here, because I think, 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 till 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 to 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 hold that absolute debt level, flat and decrease it for the maturities that that come about. And then, as John mentioned, we’re going to start driving, significant free cash flow generation and once that term loans paid off, we’ll start with dividend increases, and then we’ll move on to the opportunistic share repurchases.
Hey, John, some of your peers that when they are talking about say, two times, yes, EBITDA or that one time or less than one time, they also identify or that was the parameter that what — under what commodity price they are using, not necessarily using the current price. So do you guys just looked at the — what is the current price, your EBITDA or you also target at a lower price, the maximum two times.
No. We look at even lower prices, what I would say 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, chance of 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 episodes 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 parameter you can share in terms of — you will set dividend longer term based on say, 10% of a certain cash flow from operation based on certain advice or any kind of parameters that you can share matrix, 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 like 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, 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 imply the second half is about 280 and you say the third quarter is about 265. So that means that the fourth quarter is about 300. Is that a bit conservative 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 good turnaround, maintenance in the Gulf of Mexico, maintenance in Southeast Asia and also some shutdowns for Phase 3 in North Malay Basin. And plus, we did dial in 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. Yes, 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 stick to two questions if that’s okay. But let me see if I can get them both in. Greg, I’m going to try another go at Whiptail. I seem to recall in our prior conversations that, build up quite a picture of how to launch this prospect could be, now you’ve got two of the biggest sands three miles apart. I’m out of trying to saying that this could be more than one development phase on Whiptail.
Go ahead, Greg.
Look, I think it’s early days to be 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 perspective area. We’ve got more appraisal work to do and some deepening to do in and around this area. But we’re very pleased with the results. But I think it’s just too early to speculate on, is this big enough standalone by itself? Or what? So just give us some time to evaluate the 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 foundations 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 in 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 two ships that preceded it at 220,000 barrels a day. So, let’s get more drilling. Let’s get more evaluation. But obviously, initial results are very encouraging.
Yes, very pleased.
Thank you for that note. Greg, maybe I will do a Part 1a of the third one to John, just when you think about these hub sizes, what are you thinking about the platform levels of production nowadays? Are we thinking about one on top of the other or early phases declining? How are you thinking of that I’ve given the scale of the resource you have right now, just so we can calibrate everybody’s adoption expectations over time?
No, again, Doug. You and I’ve 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 space, in and around these existing hubs. So not only is there additional tie back opportunity in the Campanian, i.e., Liza, Liza, class reservoirs. But as we go deeper in the Santonian, let’s say that works out is a technical commercial success, then you can 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. And it’s pretty easy to see that these hubs will be full for a long time.
Thank you. My follow up hopefully is a quick one, John Rielly, I don’t want to press too much on this debt issue. But two things, EBITDA is different number of 50 than it is 70. 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, these two, the potential to generate a ton of free cash flows, obviously, they are giving their unhedged on the upside. So just give us an idea where you want the absolute balance sheet to be and I’ll leave it there. Thanks.
Really, as John has said earlier, once we pay off the 500 million on the term loan, we have to debt at the level we want it to be, as I said, there’s a small maturity of 2024. And no really big maturities out until 2027. So that 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 two times. And then, quite frankly, go below one as we continue to add these FPSOs.
All 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 two related questions. The first is 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. Let’s so maybe on the demand side, although we can debate that more on supply in terms of OPEC behavior, and as barrels come back into the market will the market get over supplied or will inventory stay in deficit? So I loved your perspective, especially given that you spend a lot of time with market participants there. And then, the related question is just on Hesse’s hedging strategy for 2022. It doesn’t 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 two related questions?
Neil, good morning. Thanks for the questions. The oil market is definitely rebalancing. Three 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 the 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, 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 where we take the over the 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 business that’s focused on production growth to one that’s focused on return of capital, financial discipline appropriately. So if you can grow a little bit, but generate 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 five years for what it’s going to be growing in the next three or four 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 getting to pre-COVID levels of 13 million barrels a day, probably for the next three or four years.
So shale will play a role, but it’s going to have a backseat 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 our OPEC plus 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 very end, 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 a day, each month as it goes out, though, need 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 markets 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 markets really back in balance at pre-COVID levels.
So looking forward, the macro, I think is very supportive, demand growing faster than supply, inventory at pre-COVID levels, and the oil price should be well supported in that environment.
Tie that back into — that might be a question for John Rielly tied into hedging strategy.
Right. So Neil, what 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 in the front has been performing very well and 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, that will be put base strategy.
Makes a ton of sense. Thanks, guys.
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 with the term loan? If not, would we potentially see faster cash return to shareholders? So the 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 Exxon Mobil buy one — build one, design many — design one, build many strategy, I wonder if that has the potential to accelerate, if we look forward, two to three to five to seven 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? Thanks.
Yes, Paul. Hi, good to hear your voice. Look, we’ve laid out our plan, we’re going to be very disciplined about executing the plan. There is 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 as 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 two 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 costs 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 is being built one a year, come on one a year, that cadence is probably as aggressive as any ever done in the industry. And Exxon Mobil often talks about leakage meaning capital inefficiency, this pace of bringing on one 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 of 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 I had. So it actually strengthens our free cash flow, even though in the year of the investment, you go up a notch. But the Bakken’s becoming a major free cash flow generator 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 five to six years.
Thank you. Could 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. Thank you.
Sure, 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, has midstream maintains a strong credit position, it’s 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 three. 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 can support future growth or incremental return to shareholders, including Hess and that can be this type of buyback or increased distribution.
So another way of saying, 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. You said it was nine miles northwest of Liza-1. If I look at a seismic section that the operator Exxon Mobil had in their Investor Day, they show us 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?
Yes, it is a very large structure that will be dedicated to the deeper stratigraphy, call it lower Campanian, Santonian. So that will be our first standalone well, targeting those deeper intervals, Bob as you know, the rest have all been deep tails. But this will be a standalone and yes, it is a very large structure.
Your next question comes from Noel Parks with Touhy Brothers.
Just a different sort of continue on from that last question. Could you just sort of maybe walk us through where things stand on as far as main targets in Guyana versus deeper potential targets? Sort of the just kind of what you pretty much have established beyond the primary targets? And sort of what’s still to come?
You bet. So when I talk about deeper plays, I’m really talking about the bottom of the Campanian and lower Campanian and then down into the Santonian. And then, 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 to a combination of tie backs to existing hubs, and or stand standalone developments if they’re big enough. So we’ve had eight penetrations to-date in the deeper plays. And then, if you couple that with the success in Surinam, 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 intervals 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 that 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 deepenings. So there’ll be deep tails on Campanian targets, two of which John mentioned in his script, which are Whiptail. So both Whiptail-1 and Whiptail-2 will be deep and 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 standalone 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, 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, three months ago, has some implications for areal extent. And in this — in the wells on the horizon, your second half of the year, are there any of those that will be particularly informative about the sort of areal 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. 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 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. And to address the areal 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’ll give us really key data that understand the size of those reservoirs in particular so —
And ultimately, that helps us define the value of our — upgrade the value of our development queue for projects going forward. So 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 [BSP] [ph] 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.