Hess - Q2 2021
July 27, 2021
Transcript
Speaker 0
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. 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.
Speaker 1
Thank you, Liz. Good morning, everyone, and thank you for participating in our Q2 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 Reilly, 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.
Speaker 2
Thank you, Jay. Good morning, everyone. Welcome to our Q2 conference call. Today, I will review our continued progress Our strategy and our long standing commitment to sustainability. Greg Hill will then discuss our operations, and John Reilly will cover our financial results.
Our strategy is to grow our resource base, Have a low cost to supply and sustained cash flow growth. Executing this strategy has positioned our company to deliver industry leading cash flow growth 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 2,050. The world faces the dual challenge of needing 20% more energy by 2,040 and reaching net 0 carbon emissions by 2,050. 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 2,040 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 2,040. 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 $300,000,000,000 spent last year. The key for our company is to have a low cost to 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 2023, Which is 75% above our peers and puts us in the top 5% of the S and 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 $500,000,000 of our $1,000,000,000 Term loan maturing in March 2023.
Depending upon market conditions, we plan to repay the remaining $500,000,000 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 $750,000,000 of its Class B units from its sponsors, Hess Corporation and Global Infrastructure Partners to be completed in the Q3. We expect to receive approximately $375,000,000 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 Non strategic acreage interest in the Bakken for a total consideration of $312,000,000 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 3rd 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 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 of Whiptail.
The Whiptail number 1 well encountered 246 And the Whiptail No. 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 Woodtail 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 9,000,000,000 barrels of oil equivalent. In June, We also announced the discovery at the Long Tail three well, which encountered approximately 230 feet of net pay, In addition, the successful Mako-two well together with the Waru-two well, which encountered approximately 120 feet of high quality oil bearing In terms of Guyana developments, the ULEESA Unity FPSO with a gross capacity of 220,000 barrels of oil per day It's expected to sail from Singapore to Guyana in late August, and the Liza II development is on track to achieve first oil in early 2022.
Our 3rd oil development on the Stabroek Block at the Payara field Is expected to achieve 1st oil in 2024, also with a gross capacity of 220,000 barrels of oil per day. Engineering work for our 4th development on the Stabroek Block at Yellowtail is underway with preliminary plans for a gross capacity in the range of Pending government approvals and project sanctioning. Our 3 sanctioned oil developments have a breakeven Brent oil price of between $25 $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 2,030 In the International Energy Agency's sustainable development scenario, which is consistent with the Paris Agreement's ambition 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 ISSESG, 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 At 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.
Speaker 3
Thanks, John. In the Q2, we continued to deliver strong operational performance. Company wide 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, 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 290,000,295,000 barrels of oil equivalent per day, so we're now forecasting to be at Turning to the Bakken. 2nd quarter net production averaged 159,000 barrels below 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 Q3, 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 Q3, 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 $5,800,000 per well in 2021. We've been operating 2 rigs since February, Given the improvement in oil prices and our robust inventory of high return drilling locations, we plan to add a 3rd 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, 2nd 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 Q3, we forecast Gulf of Mexico net production to average We will now begin the call to questions. We will now begin the call to questions. Thank you, operator. Thank you, operator. Thank you, operator.
Thank you, operator. Thank you, operator. Thank you, operator. 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 as well as Phase 3 installation work at North Malay Basin.
Full year 2021 net production It is forecast to average approximately 60,000 barrels of oil equivalent per day. Now turning to Guyana. In the Q2, gross production from Liza Phase 1 averaged 101,000 barrels of oil per day We're 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 Our plan for the Q4, 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 Q3 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 3rd development at Payara. The Prosperity FPSO hull is complete We'll enter the Keppel yard in Singapore following sail away of the Liza Unity.
Topside's fabrication is commenced at Dynamac 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 As for our 4th development at Yellowtail, The joint venture anticipates submitting the plan of development to the government of Guyana in the 4th quarter with first oil targeted for 2025, Pending government approvals and project sanctioning. During the Q2, the Mako II appraisal well On the Stabroek Block confirmed the quality, thickness and the areal extent of the reservoir. When integrated with the previously announced discovery at Waaru 2, The data supports a potential 5th development in the area east of the Liza complex.
As John mentioned, this morning we announced Discovery at Whiptail, located approximately 4 miles southeast of Wahru-1. Drilling continues at both wells to test deeper targets. In terms of other drilling activity in the second half of twenty twenty one, 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 II appraisal well located 5 miles south of Tripletail I. The Noble Tom Madden We'll spud the Catibac 1 exploration well located 4.5 miles southeast of the Turbot 1 discovery in early August. Then in the Q4, we will drill our 1st dedicated test of the deep potential at the Fang Tooth Prospect, located 9 miles northwest of Liza 1.
In the 3rd quarter, The Noble Sam Croft will drill the Turbot II appraisal well, then transition to development drilling operations for the remainder of the year. The Stena Caron will conduct a series of appraisal drill stem tests at Walguru 1, then Mako 2 And then Long Tail 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 Envionna 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 Reilly.
Speaker 4
Thanks, Greg. In my remarks today, I will compare results from the Q2 of 2021 to the Q1 of 2021. Adjusted net income was $74,000,000 in the Q2 of 2021 compared to net income of $252,000,000 in the Q1 of 2021. Turning to E and P. E and P adjusted net income was $122,000,000 in the Quarter of 2021 compared to net income of $308,000,000 in the previous quarter.
The changes in the after tax components Of adjusted E and P results between the Q2 and Q1 of 2021 were as follows. Lower sales volumes reduced earnings by $126,000,000 Higher cash costs reduced earnings by $48,000,000 Higher exploration expenses reduced earnings by $10,000,000 All other items reduced earnings by $2,000,000 for an overall decrease in 2nd quarter earnings of $186,000,000 2nd quarter sales volumes were lower, Primarily due to Guyana having 2 1,000,000 barrel liftings of oil compared with 3 1,000,000 barrel liftings in the 1st quarter And 1st quarter sales volumes included non recurring sales of 2 VLCC cargoes totaling 4,200,000 barrels of Bakken crude oil, which contributed approximately $70,000,000 of net income. In the second quarter, our E and P sales volumes were underlifted Cash costs for the Q2 came in at the lower end of guidance and reflect higher planned maintenance and workover activity than the Q1. In June, 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 7 Shallow Water West Delta 7,986 leases held by Fieldwood, is responsible for the abandonment of the facilities on the leases. 2nd quarter E and P results include an after tax charge of $147,000,000 Representing the estimated gross abandonment obligation for West Delta 7,986 without taking into account potential recoveries 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, quarter of 2021 compared to $75,000,000 in the prior quarter. Midstream EBITDA before non controlling interest amounted to $229,000,000 in the Q2 of 2021 compared to $225,000,000 in the previous quarter.
Now turning to our financial position. At quarter end, excluding Midstream, cash and cash equivalents were $2,420,000,000 which includes receipt of net proceeds of $297,000,000 from the sale of our Little Knife and Murphy Creek acreage in the Bakken. Total liquidity was $6,100,000,000 including available committed credit facilities, while debt and finance lease obligations totaled 6 $600,000,000 Our fully undrawn $3,500,000,000 revolving credit facility It's committed through May 2024 and we have no material near term debt maturities aside from the $1,000,000,000 term loan, which matures in March 2023. In July, we repaid $500,000,000 of the term loan. Earlier today, Hess Midstream announced an agreement to repurchase approximately 31,000,000 Class B units of Hess Midstream held by GIP and us for approximately $750,000,000 We expect to receive net proceeds of approximately $375,000,000 from the sale in the 3rd quarter.
In addition, we expect to receive proceeds in the Q3 from the sale of our interest in Denmark for total consideration of $150,000,000 with an effective date of January 1, 2021. In the Q2 of 2021, Net cash provided by operating activities before changes in working capital was $659,000,000 compared with $815,000,000 in the 1st quarter, primarily due to lower sales volumes. In the 2nd quarter, Net cash provided by operating activities after changes in working capital was $785,000,000 compared with $591,000,000 In the Q1, changes in operating assets and liabilities during the Q2 of 2021 Increased cash flow from operating activities by $126,000,000 primarily driven by an increase in payables that we expect to reverse in the Q3. Now turning to guidance. First for E and P.
Our E and P cash costs were $11.63 per barrel of oil equivalent, including Libya and $12.16 per barrel of oil equivalent, We project E and P cash costs excluding Libya to be in the range of 13 to $14 per barrel of oil equivalent for the Q3, 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 and A expense It was $11.55 per barrel of oil equivalent, including Libya and $12.13 per barrel of oil equivalent, excluding Libya in the 2nd quarter. DD and A expense excluding Libya is forecast to be in the range of $12 to $13 per barrel of oil equivalent for the 3rd quarter And full year guidance of $12 to $13 per barrel of oil equivalent remains unchanged. This results in projected total E and P unit operating costs, Excluding Libya to be in the range of $25 to $27 per barrel of oil equivalent for the Q3 $0.23 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 to $45,000,000 in the 3rd quarter and full year guidance is expected to be in the range of $160,000,000 to $170,000,000 which is down from previous guidance of $170,000,000 to $180,000,000 The midstream tariff is projected to be in the range of 265 to $275,000,000 for the Q3 and full year guidance is projected to be in the range of 1,080,000,000 to $1,100,000,000 which is down from the previous guidance of $1,090,000,000 to $1,115,000,000 E and P income tax expense, excluding Libya, is expected to be in the range of 35 $40,000,000 for the Q3 and full year guidance is expected to be in the range of $125,000,000 to $135,000,000 which is updated from the previous guidance of $105,000,000 to $115,000,000 reflecting higher commodity prices. We expect non cash option premium amortization will be approximately $65,000,000 for the 3rd quarter Full year guidance of approximately $245,000,000 remains unchanged. During the Q3, we expect to sell 3 1,000,000 barrel cargoes of oil from Guyana. Our E and P capital and exploratory expenditures are expected to be approximately $575,000,000 in the 3rd 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 $1,900,000,000 Turning to Midstream, we anticipate net income attributable to Hess from the Midstream segment to be in the range of $50,000,000 to $60,000,000 for the Q3 and full year guidance is projected to be in the range of $275,000,000 to $285,000,000 which is down from the previous guidance of $280,000,000 to $290,000,000 Turning to corporate.
Corporate expenses are estimated to be in the range of $30,000,000 to $35,000,000 for the Q3 and full year guidance of $130,000,000 to $140,000,000 remains unchanged. Interest expense is estimated to be in the range of $95,000,000 to $100,000,000 for the 3rd quarter Approximately $380,000,000 for the full year, which is at the lower end of our previous guidance of $380,000,000 to $390,000,000 reflecting the $500,000,000 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.
Speaker 0
Your first question comes from the line of Ryan Todd with Piper Sandler.
Speaker 5
Good morning. Maybe Starting off on Wiptel, congratulations on the great results of both Wiptel 1 and 2.
Speaker 2
Thank you. I mean,
Speaker 5
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 could land in the queue?
Speaker 2
Yes. Great question, Ryan, and thank you. Look, Whiptail drilling activity is still underway. We're going to be drilling in both wells to some deeper targets. Whiptail adds to our queue of high value Oil developments in Guyana, Waru and Mako, as Greg talked about, have the potential to be our 5th FPSO.
Whitdale has the potential to be another oil development and since evaluations work is still going underway, it's a little premature 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 Q of high value potential oil is growing and we're going to optimize it as we continue to get more data and well results to further get
Speaker 3
And Ryan, the quality of the reservoirs in Whittendale are outstanding.
Speaker 6
All right.
Speaker 5
Thanks, John and Greg. Maybe a follow-up on CapEx. Prior guidance for 2021 Bakken CapEx is $450,000,000 Is that still the same with the addition of the 3rd rig in December or was the possibility of a 3rd 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 I guess, are things trending in line with where you would have expected?
Speaker 2
Yes, John?
Speaker 4
Yes. So from the Bakken standpoint, no, we did not have the 3rd rig in our guidance of the $450,000,000 for the year. So that 3rd rig is adding to the Bakken capital, so we'll go up from that $450,000,000 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 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 $1,900,000,000 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 Structure 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 $1,900,000,000 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 $1,900,000,000
Speaker 2
Great. Thank you. Thank you.
Speaker 0
Our next question comes from Arun Jayaram with JPMorgan.
Speaker 7
Yes, good morning. My first question is on Liza Phase I know the design is 220 kilobytes D, 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 productive capacity be as well as I wanted to get your timeline to maybe first oil if the boat It's a sailing from Singapore at the end of August.
Speaker 2
Thanks, Arun. Greg?
Speaker 3
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 wrung 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 1st year of operation. But I think 15% to 20% is
Speaker 7
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?
Speaker 2
Yes. Look, once we pay The $500,000,000 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 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 $500,000,000 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 market conditions for oil and the financial markets are supportive, The next step will be strengthening our base dividend.
Speaker 7
All right. Thanks, John.
Speaker 0
Your next question comes from David Deckelbaum with Cowen.
Speaker 8
Good morning, guys, and thanks for taking the questions today.
Speaker 2
Thank you.
Speaker 8
I just wanted to just Touch on the Bakken again. With the addition of the 3rd 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 4th rig? I just wanted that in the context of what the current in house view is of the truly optimized
Speaker 2
John, you want to take the exit rate and then Greg, any color you'd like to provide as well?
Speaker 4
Sure. So from the Bakken exit rate standpoint, the addition of the 3rd 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.
What we see from the NGL prices actually to increase our cash flow in the Q3, maybe $35,000,000 to $40,000,000 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 $165,000,000 to $170,000,000 range. And then Greg, I'll hand it over to you for the 4th rig.
Speaker 3
Yes. So I think just one couple more comments on the 3rd rig. So with that 3rd 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 3rd rig. So that's why we raised the wells on line 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 Primary role of the Bakken in our portfolio is to be a cash engine. So that's its number one role. So any decision to add any rigs in 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 4th 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 optimize 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 The corporation that's going to be the primary driver of whether or not we add that 4th rig or not. I will say the 4th 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.
Speaker 8
Thank you, guys. You seem well prepared for that question. I appreciate the color. My follow-up is just on Quickly on Libya, you've seen obviously the end of the forest majority, 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 The rest of the year and then just broadly speaking, where that sits in your portfolio?
Speaker 2
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 Libbey would continue at the pace of cash generation that it's at now in the future.
Speaker 8
Thank you, guys.
Speaker 0
Your next question comes from Roger Read with Wells Fargo.
Speaker 9
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 the expectations 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 FPSO and FPSO2 and FPSO3
Speaker 2
As we
Speaker 9
think about the timing in Guyana.
Speaker 2
Yes. Greg, why don't you please handle the cost inflation question that he's asking. 1, maybe we cover the onshore focusing on the Bakken and then 2, the offshore.
Speaker 3
Yes, sure. So let's talk about the onshore first 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, recall, we pre bought 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 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 And then I've got to say ExxonMobil is doing an extraordinary job of utilizing This design 1, 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 of the PSC, If your costs do creep up, that's all covered under cost recovery.
Speaker 9
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 Suriname, any updates there?
Speaker 2
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 planned there next year.
Speaker 3
Yes, we do. So planning is underway on Block 42 For a second exploration well in the first half of twenty twenty two, obviously, the Apache wells Our encouraging for our acreage there, that's adjacent 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 of 42, ExxonMobil has completed the 2 d seismic survey on the block there. The data has been analyzed And assessed.
And so the joint venture is now planning a very targeted 3 d survey over some interesting prospects But drilling there would not begin to occur until probably 'twenty three at the earliest.
Speaker 9
Thank you.
Speaker 0
Your next question comes from Paul Cheng with Scotiabank.
Speaker 6
Hey, guys. Good morning.
Speaker 2
Good morning, Paul.
Speaker 6
Good morning, Paul. 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 Beth, you didn't want to be sitting on your balance sheet at all?
Speaker 4
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 is 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 it was we mentioned earlier, we really don't have any material Near term debt maturities. 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 Waratoo. So we're going to have significant growth in EBITDA and our balance sheet is just going It gets 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 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
Speaker 6
John, some of your peers That when they're talking about, say, 2 times EBITDA or that one time or less than one time, they also Identify all that with the parameter that what under what commodity price they are using, not necessarily using the current price. Do you guys just look at what is the current price of your EBITDA or you also target at a lower price, the maximum two times?
Speaker 4
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 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, The Warumaco 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 Barry, based on commodity prices, and we like to say that with these FPSOs coming on, we can win at any commodity price environment.
Speaker 6
And John, I think John Hess has said that the first priority of the excess free cash after the term loan payoff Yes, increasing the dividend. Is there any kind of parameter 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 or any Kind of a parameter that you can share or matrix you can share so we can have some better understanding What is the trajectory?
Speaker 4
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 and 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 that 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 and P 500.
Speaker 6
Final question, I think this is for Greg. Greg, when you look at your full year production guidance, Which implies the second half is about 280 and you say the 3rd quarter is about 265. So that means that the Q4 is about $300,000,000 Is that a bit conservative on that number?
Speaker 3
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 and Lake 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.
Speaker 6
Maybe let me ask in this way, Greg. In the 4th quarter, Do you have any meaningful turnaround or maintenance shutdown activities?
Speaker 3
We do have some in the Q4, yes. And Some of those are in Southeast Asia, and we also have a turnaround in Baldpate in the Gulf of Mexico during the Q4 as well. But the hurricane contingency really rolls through both quarters.
Speaker 0
Your next question comes from Doug Leggate with Bank of America.
Speaker 10
Thanks. Good morning, everyone. 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 have another go up, but Tayo, 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. I'm out of turn saying that this could be more than one development phase on Brookfield?
Speaker 2
Go ahead,
Speaker 3
Craig. 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 sandwiched between Yellowtail and Walru. And so by drilling both of these wells concurrently, obviously, we accelerated the evaluation and appraisal of this highly prospective area. We've got
Speaker 2
more appraisal work
Speaker 3
to do and some deepening to do in and around these areas, but we're very pleased with the results. I think it's just too early to speculate on, is this big enough standalone by itself or what? So just
Speaker 2
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 Sure. 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 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 220,250,000 barrels a day, which is bigger Then the 2 ships have proceeded it at 220,000 barrels a day. So let's get more drilling, let's get more evaluation, but The initial results are very encouraging.
Yes.
Speaker 10
Very clear. Thank you for that, Alex. Greg, maybe I will do a part 1a before I go on to John. When you think about these hub sizes, what are you thinking about the plateau levels of production nowadays? Are we thinking about 1 on top of the other are 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, we've touched on expectations over time.
Speaker 3
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's base In and around these existing hubs, so not only is there additional tieback opportunity In the Campanian, I. E, Liza Claes 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 Companion hubs. So if you step back and look at all the prospectivity in the Companion, all the prospectivity in the Santonian, It's pretty easy to see that these hubs will be full for a long time.
Speaker 10
Thank you. My follow-up hopefully is a quick one. John Reilly, I don't want to press too much on this debt issue, but 2 times EBITDA is a different number at 50 than it is at 70. So I just wonder if I could ask you what your Thinking is
Speaker 7
on the absolute level of debt that you want
Speaker 10
to get to because if Guyana is self funding from next year, which I believe it is at Phase 2, The potential to generate a ton of free cash flow is obviously there and I'm giving you're unhedged on the upside. So just give us an idea where you want the absolute balance sheet to be and
Speaker 4
Really as John Hess said it earlier, once we pay off the $500,000,000 on the term loan, we have the debt at the level We wanted 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 2 times And then quite frankly go below 1 as we continue to add these FPSOs. All
Speaker 10
right. And Guyana is self funding next year?
Speaker 4
Once Phase 2 comes on, Guyana is self funding.
Speaker 10
Excellent. Thank you.
Speaker 2
Thank you.
Speaker 0
Your next question comes from Neil Mehta with Goldman Sachs.
Speaker 11
Hey, good morning, guys. I'll be quick But it's 2 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 20 'twenty two. Less 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 oversupplied or will inventory So I'd love your perspective, especially given that
Speaker 6
you spend a lot of
Speaker 11
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
Speaker 2
would you
Speaker 8
like to stay more open to participate in potential So, 2 related questions.
Speaker 2
Good morning. Thanks for the questions. The oil market is definitely rebalancing. It's Three factors, demand, supply, inventories. We think demand is running right now at about 98,000,000 barrels a day.
Remember pre COVID globally, it was running 100,000,000 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 So demand is pretty strong. I think the financial stimulus programs of the U. S.
Government and other governments across the world So we see demand growth continuing into next year. We think we will get, By the end of the year, about 100,000,000 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 We take the over, the demand is going to continue to be strong going into next year through the year. Supply, It'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.
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 is 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 11,000,000 barrels a day, it's going to be hard to getting to pre COVID levels of 13,000,000 barrels a day probably for the next 3 or 4 years. 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 price This 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 a, 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 The variance, something happens with Iran coming on. We may curtail that, but basically that 5,800,000 barrels a day of excess capacity I'll be whittled down $400 a day each month as it goes out. I'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 1,200,000,000 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. 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.
Speaker 8
And Jeff, can
Speaker 11
you tie that back into and that might be a question for John Reilly tied into the hedging strategy.
Speaker 4
Right. So Neil, you know 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 lead 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 backwardated as you go into 2022. And so with the put options, we typically put them on September to December towards End of the year, time value gets the cost of the 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
Speaker 12
But to be clear, it
Speaker 2
will be a put based strategy.
Speaker 11
Makes a
Speaker 8
ton of sense. Thanks guys.
Speaker 6
Thank you.
Speaker 0
Your next question comes from Paul Sankey with Sankey Research.
Speaker 12
Hi, everybody. Thanks. 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 a quicker decision to raise the dividend. Is that a potential? Or I guess the alternate would be that you just Increased 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, you think or is it a fairly set and predictable path here? And what I'm really wondering is, as you mentioned, the ExxonMobil Build 1, design many design 1, 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 The 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.
Speaker 2
Yes. Hi, 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 us well this year. Obviously, very different markets between last year and this year.
On 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. I think it's good planning assumption to assume that it will be given market conditions, we would pay that $500,000,000 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 1, build many and pretty much getting in a cadence of 1 of these Major FPSOs being built 1 a year, come on 1 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.
Speaker 12
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
Speaker 2
Yes, we're going to stay very financially disciplined. John talks about adding a 3rd rig and then Greg will talk potentially a 4th rig. Those It 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, 200,000 barrels a day equivalent and plateauing.
So there'll be obviously increase with the rigs. John 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.
Speaker 12
Good. Thank 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.
Thank you.
Speaker 4
Yes, sure. Just at a high level strategic standpoint, the midstream continues to add differentiated value to our E and 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 And so with this transaction like pro form a for the transaction Hess Midstream maintains a strong credit position. It's at 3 times 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.
Speaker 2
So in another way of saying it, the Hess Midstream becomes a free cash flow engine for Hess as well.
Speaker 10
Understood. Thank you, everyone.
Speaker 0
Your next question comes from Bob Brackett with Bernstein Research.
Speaker 2
Good morning all. I had
Speaker 13
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 us a very large deep Seismic signature that seems to correspond to where you're drilling, Fanthuth. Am I over reading that? Or is this a fairly large structure that you're going to drill.
Greg, go ahead.
Speaker 3
Yes. It is a very large structure that will be dedicated The deeper stratigraphy, call it Lower Campanian, Santonian. So that will be our 1st standalone well Targeting those deeper intervals, Bob, as you know, the rest have all been details, but this will be a standalone and yes, it is a very large structure.
Speaker 10
Great. Thanks for that.
Speaker 2
Thank you.
Speaker 0
Your next question comes from Noel Parks with Tuohy Brothers.
Speaker 14
Hi, good morning. Good morning. Just to 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 Sure. And sort of what's still to come.
Speaker 2
Yes. Go ahead, Greg.
Speaker 3
You bet. So when I talk about deeper I'm really talking about the bottom of the Campanian and 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. If successful, as I mentioned previously, they could be exploited through a combination of tiebacks to existing hubs and or Sand 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 To fully understand the potential of this play, so in the second half, we've got several more deep targets that are planned. 3 will be what I call deepening, so there will be deep tails on companion targets, 2 of which John mentioned in his script, which are Whiptail.
So both Whiptail I and Whiptail II will be deepened down into the Santonian. The next one after that is Catibac and then also Pinktail. We'll have a deep tail on it as well. And then as I just discussed with Mr. Brackett, there will be a deep standalone called FANG2.
So Just on the Stabroek Block, by the end of the year, we'll have 13 total penetrations in the deeper So we'll begin to now understand better how it's all put together, where we think the hydrocarbons are, etcetera, etcetera. So keep watching this space, evolving story, but very exciting, but again, need more drilling to figure out where and what we have.
Speaker 14
Great. And just to sort of extend in the other dimension, I seem to remember that The report you had last quarter or 3 months ago had some implications for aerial extent And in the wells on the horizon second half of the year, are there any of those that will be You're particularly informative about the sort of the aerial extent of the deeper zones.
Speaker 3
Well, yes, it's a mosaic. It's a picture that we're trying to put together. So yes, I We mentioned FANG tooth, for example, being a very large structure, stratigraphic feature, I should say. Obviously, 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?
Speaker 14
Right.
Speaker 3
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.
Speaker 2
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 aerial extent and productivity of potential developments, you might talk about that.
Speaker 3
Absolutely. So remember, we'll be doing drill stem tests at Waru, at Mako and then also Long tail before the end of the year. So that will give us really key data to understand the size of those reservoirs in
Speaker 2
And ultimately, that helps us define the value of our and 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.
Speaker 3
And I would anticipate on those lines that eventually we'll do a DST at Whiptail as well.
Speaker 14
Great. Thanks a lot. Just what I was looking for.
Speaker 2
Thank you.
Speaker 0
Thank you very much. This concludes today's conference call. Thank you for your participation. You may now disconnect. Have a great day.