Q3 2021 Hess Corp Earnings Call
Yeah.
Thank you for your patience Your conference call will begin momentarily again, thank you for your patience and please continue to standby.
[music].
Yeah.
Good day, ladies and gentlemen, and welcome to the third quarter 2021, Hess Corporation Conference call. My name is Josh and I will be your operator for today at this.
This time all participants are in a listen only mode. Later, we will conduct a question and answer session. If at any time you require operator assistance. Please press star followed by zero and we will be happy to assist you. As a reminder, this conference is being recorded for replay purposes I would now like to turn the conference over to Jay Wilson.
Vice President of Investor Relations. Please proceed.
Thank you Josh good morning, everyone and thank you for participating in our third quarter earnings Conference call.
Our earnings release was issued this morning and appears on our website www Dot dot 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 <unk> annual and quarterly reports filed with the S. E C.
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 our website. Following the presentation I'll now turn the call over to John Hess.
Jay Good morning, everyone welcome to our third quarter Conference call today, I will review our continued progress in executing our strategy Greg.
Greg Hill will discuss our operations and John Riley will cover our financial results.
With Cop 26, beginning this Sunday it is appropriate to address the energy transition.
Climate change is the greatest scientific undertaking of the 21st century.
The World is two challenges to grow our global energy supply by about 20% in the next 20 years and to reach net zero emissions by 2050.
The International Energy Agency published its latest World energy outlook earlier, this month, which provides four scenarios to shed light on these challenges. It is important to remember that these are scenarios not forecast to help guide policymakers and business leaders and their decision making.
In all four scenarios oil and gas will still be needed in the decades to come.
Significantly more investment will be required to meet the world's growing energy needs much more than renewables and much more in oil and gas a reasonable estimate for global oil and gas investment from these IEA scenarios is at least 400 billion each year over the next 10 years last year that number was.
$300 billion. This year's estimate is $340 billion to ensure a successful and orderly energy transition we need to have climate literacy energy literacy and economic literacy.
Our strategy is to grow our resource base have a low cost of supply and sustained cash flow growth.
While delivering industry, leading environmental social and governance performance and disclosure.
By investing only in high return low cost opportunities, we have built a differentiated and focused portfolio that is balanced between short cycle and long cycle assets.
Our cash engines or the Bakken the Gulf of Mexico, and South East Asia, where we have competitively advantaged assets and operating capabilities.
Guyana is our growth engine and is on track to become a significant cash engine in the coming years.
There's multiple phases of low cost oil developments come online.
Also by adding a third rig in the Bakken in September and completing the turnaround and expansion of the Tiger gas plant. The Bakken is expected to generate significant free cash flow in the years ahead.
By successfully executing our strategy our company is positioned to deliver strong and durable cash flow growth through the end of the decade based.
Based upon the most recent sell side consensus estimates our cash flow is estimated to grow at a compound annual growth rate of 42% between 2020 and 'twenty 'twenty, three which is 50% above our peers and puts us in the top 5% of the S&P 500.
As our portfolio generates increasing free cash flow, we will first prioritize debt reduction and then cash returns to shareholders through dividend increases and opportunistic share repurchases.
We have continued to maintain financial strength as well.
As managing for risk as.
As of September 30th we had $2.4 billion of cash on the balance sheet in July we prepaid half of our $1 billion term loan maturing in March 'twenty 'twenty, three and we plan to repay the remaining $500 million in 2020 two.
This debt reduction combined with the startup of Liza Phase two early next year is expected to drive our debt to EBITDAX ratio under two and also enable us to consider increasing cash returns to shareholders.
In August we completed the sale of our interest in Denmark for total consideration of $150 million effective January one 2021 and received $375 million in proceeds from Hess midstream is buyback of class B units from its sponsors Hess Corporation and global infrastructure partners.
Earlier this month our company also received net proceeds of $108 million from the public offering of Hess own class a shares of Hess midstream.
The Denmark sale and these midstream monetization brought material value forward and further strengthened our cash and liquidity position.
Key to our long term strategy as Guyana, one of the industry's best investments on the Stabroek block, where Hess has a 30% interest and Exxonmobil is the operator, we announced the 19th and 20th significant discoveries during the third quarter at Whiptail and Pink tail and on October 7th we announced the 20.
First significant discovery on the block at Caterpillar back these discoveries will underpin our Q a future low cost oil developments, we see the potential for at least six F. P. S. OS on the Stabroek block producing more than 1 million gross barrels of oil per day in 2027 and up to 10 F. P.
So as to develop discovered resources on the block.
On October 7th we increased the gross discovered recoverable resource estimate for the block to approximately 10 billion barrels of oil equivalent up from the previous estimate of more than 9 billion barrels of oil equivalent and we continue to see multibillion barrels of future exploration potential remaining.
In terms of our current Guyana developments gross production from the Liza phase one.
Complex averaged 124000 barrels of oil per day in the third quarter. The Liza Phase two development is on track for start up in early 2022 with a gross production capacity of 220000 barrels of oil per day, and the Liza Unity F. P. S O arrived in Guyana.
On Monday.
Our third development on the Stabroek block at the pie or a field is on track to achieve first oil in 'twenty 'twenty four also where the gross capacity of 220000 barrels of oil per day.
Our three sanctioned oil developments have a breakeven a brent oil price of between 25 and $35 per barrel.
The plan of development for our fourth development on the block at Yellow tail was recently submitted to the government of Guyana for approval pending government approvals. The project is envisioned to have a gross capacity of approximately 250000 barrels of oil per day with first oil in 2025.
Turning to sustainability, we are proud to be recognized as an industry leader in our environmental social and governance performance and disclosure earlier.
Earlier this month, our company received a AAA rating in the M. S. C. I E. S. G ratings for 2021 after earning a ratings for the previous 10 consecutive years, the AAA rating desert banks Hess as a leader in managing industry specific ESG risks relative to peers.
And reflects our strong management practices to reduce carbon emissions as well as our top quartile performance in areas, such as bio diversity and land use reduction of air and water emissions and waste and making a positive impact on the communities where we operate.
In summary, we remain focused on executing our strategy and achieving strong operational and ESG performance. Our company is uniquely positioned to deliver cash flow growth over the next decade that is not only industry, leading but which we believe will rank among the best in the S&P 500.
After our term loan is paid off and our portfolio generates increasing free cash flow, we will prioritize return of capital to our shareholders through dividend increases and share repurchases.
You and I will now turn the call over to Greg Hill for an operational update.
Yeah.
Thanks, John in the third quarter, we continued to deliver strong operational performance meeting our production targets. Despite extended hurricane related downtime in the Gulf of Mexico and safely executing a major turnaround at our Toyota gas plant in North Dakota.
Company wide net production averaged 265000 barrels of oil equivalent per day, excluding Libya in line with our guidance.
In the fourth quarter and for the full year 2021 we expect company wide net production to average approximately 295000 barrels of oil equivalent per day, excluding Libya.
Turning to the Bakken third quarter net production averaged 148000 barrels of oil equivalent per day.
This was above our guidance of approximately 145000 barrels of oil equivalent per day, and primarily reflected strong execution of the tayo. Good gas plant turnaround and expansion no small task in a COVID-19 environment, they're required strict adherence to extent extensive safety protocols to keep more than.
650 workers safe.
For the fourth quarter, we expect Bakken net production to average between 155000 and 160000 barrels of oil equivalent per day.
For the full year 2021, we forecast our Bakken net production to average approximately 155000 barrels of oil equivalent per day compared to our previous guidance range of 155 to 160000 barrels of oil equivalent per day. This guidance reflects an increase in NGL prices.
<unk>, which reduces volumes under our percentage of proceeds contracts, but significantly increase as this year's earnings and cash flow.
In the third quarter, we drilled 18 wells and brought 19, new wells online in the fourth quarter, we expect to drill approximately 19 wells and to bring approximately 80, new wells online.
And for the full year 2021 we continue to expect to drill approximately 65 wells and bring approximately 50, new wells online.
In terms of drilling and completion costs, although we have experienced some cost inflation, we are maintaining our full year average forecast of $5 $8 million per well in 2021.
Since February we've been operating two rigs, but given the improvement in oil prices and a robust inventory of high return drilling locations. We added a third rig in September.
Moving to a three year 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 cost.
Now moving to the offshore.
In the deepwater Gulf of Mexico third quarter net production averaged 32000 barrels of oil equivalent per day compared to our guidance range of 35000 to 40000 barrels of oil equivalent per day.
Our results reflected an extended period of recovery following hurricane Ida, which caused power outages at transportation and processing facilities downstream of our platforms.
Production was restored at all of our facilities by the end of September.
In the fourth quarter, we forecast Gulf of Mexico net production to average between 40040 5000 barrels of oil equivalent per day.
For the full year 2021 are forecast for Gulf of Mexico net production remains approximately 45000 barrels of oil equivalent per day.
And southeast Asia net production in the third quarter was 50000 barrels of oil equivalent per day in line with our guidance at 50000 to 55000 barrels of oil equivalent per day.
Reflecting the impact of planned maintenance shutdowns and lower nominations due to COVID-19.
Fourth quarter net production is forecast to average approximately 65000 barrels of oil equivalent per day and.
And our full year.
2021 net production forecast remains at approximately 60000 barrels of oil equivalent per day.
Now turning to Guyana.
In the third quarter gross production from Liza Phase one averaged 124000 barrels of oil per day or 32000 barrels of oil per day net to Hess.
Replacement of the flash gas compression system on the Liza Destiny with a modified design is planned for the fourth quarter and production optimization work is now planned to take place in the first quarter of 2022.
These two projects are expected to result in higher production capacity and reliability.
Net production from Liza Phase one is forecast to average approximately 30000 barrels of oil per day in the fourth quarter and for the full year 2021.
Liza Phase two development will utilize the 220000 barrels of oil per day unit D. F. P. S O.
<unk> arrived in Guyana Monday evening next steps will be mooring line installation and umbilical and riser Hookup first oil remains on track for first quarter 2022.
Turning to our third development of pie are the prosperity F. P. S O whole entered the Keppel yard in Singapore on August 1st.
Topside fabrication of dine in Mac and development drilling are underway.
Overall project is approximately 60% complete.
Prosperity will have a gross production capacity of 220000 barrels of oil per day and is on track to achieve first oil in 2024.
As for our fourth development yellow tail.
Earlier this month the joint venture submitted the plan of development to the government of Guyana.
Pending government approvals and project sanctioning the yellow tail project will utilize an M. P. S O with a gross capacity of approximately 250000 barrels of oil per day.
First oil is targeted for 2025.
As John mentioned, we announced three discoveries since July.
In July we announced that the whiptail, one and two wells encountered 246 feet and 167 feet of high quality oil bearing sandstone reservoir respectively.
This discovery is located approximately four miles southeast of Walgreen, one and three miles west of yellow tail ends.
In September we announced that the pink tell one well located approximately 22 miles southeast of Liza one encountered 220 feet of high quality oil bearing sandstone reservoirs and finally earlier this month, we announced a discovery at cat aback located approximately four miles east of tear.
But one.
Well encountered 203 feet of high quality hydrocarbon bearing reservoirs of which approximately 102 feet was oil bearing.
These discoveries further underpin future development and contributed to the increase of estimated gross discovered recoverable resources on the Saybrook block to approximately 10 billion barrels of oil equivalent.
Exploration and appraisal activities in the fourth quarter will include drilling the Fangtooth, one exploration well located approximately 11 miles northwest of Liza one this.
This well is a significant step out tests that will target deeper campaigning and San Antonia and aged reservoirs.
Appraisal activities in the fourth quarter will include drill stem tests that long tail, too and whiptail too as well as drilling the tripletail too well.
In closing we have once again demonstrated strong execution and delivery and are well positioned to deliver significant value to our shareholders I will now turn the call over to John Reilly.
Thanks, Greg in my remarks today, I will compare results from the third quarter of 2021 to the second quarter of 2021.
We had net income of $115 million in the third quarter of 2021 compared with a net loss of $73 million in the second quarter of 2021.
On an adjusted basis, which excludes items affecting comparability of earnings between periods. We had net income of $86 million in the third quarter of 2021 compared to net income of $74 million in the second quarter of 2021.
Third quarter earnings include an after tax gain of $29 million from the sale of our interest in Denmark.
Turning to E&P on.
On an adjusted basis E&P had net income of $149 million in the third quarter of 2021 compared to net income of $122 million in the previous quarter.
The changes in the after tax components of adjusted E&P results between the third quarter and second quarter of 2021 were as follows.
Higher realized crude oil NGL and natural gas selling prices increased earnings by $110 million.
Lower sales volumes reduced earnings by $147 million lower DD&A expense increased earnings by $37 million.
Our cash costs increased earnings by $14 million lower exploration expenses increased earnings by $10 million.
All other items increased earnings by $3 million for an overall increase in third quarter earnings of $27 million.
Sales volumes in the third quarter were lower than the second quarter, primarily due to hurricane related downtime in the Gulf of Mexico planned maintenance downtime and lower nominations in Malaysia, and lower sales in the Bakken, resulting from the planned tayo good gas plant maintenance turnaround.
In Guyana, we sold three 1 million barrel cargoes of oil in the third quarter up from two 1 million barrel cargoes of oil sold in the second quarter for.
For the third quarter, our E&P sales volumes were under lifted compared with production by approximately 175000 barrels which had an insignificant impact on our after tax results for the quarter.
Turning to midstream.
Midstream segment had net income of $61 million in the third quarter of 2021, compared with $76 million in the prior quarter.
Third quarter results included costs related to the Toyota gas plant maintenance turnaround that was safely and successfully completed.
Stream EBITDA before non controlling interests amounted to $203 million in the third quarter of 2021, compared with $229 million in the previous quarter.
Turning to our financial position at quarter end, excluding midstream cash and cash equivalents were $2.41 billion and total liquidity was $6 billion, including available committed credit facilities, while debt and finance lease obligations totaled $6 $1 billion.
During the third quarter, we received net proceeds of $375 million from the sale of $15.6 million has owned class pest midstream and proceeds of approximately $130 million from the sale of our interest in Denmark.
In July we prepaid $500 million of our $1 billion term loan and we plan to repay the remaining $500 million in 2022.
In October we received net proceeds of approximately $108 million from the public offering of $4 3 million Hess owned class a shares of Hess midstream.
Our ownership in Hess midstream on a consolidated basis is approximately 44% compared with 46% prior to these two recent transactions.
In the third quarter net cash provided by operating activities before changes in working capital was $631 million compared with $659 million in the second quarter.
In the third quarter net cash provided by operating activities. After changes in operating assets and liabilities was $615 million compared with $785 million in the second quarter.
Changes in operating assets and liabilities during the third quarter decreased net cash provided by operating activities by $16 million compared with an increase of $126 million in the second quarter.
Now turning to guidance first for E&P, our E&P cash costs were $12 76 per barrel of oil equivalent, including Libya and $13 45 per barrel of oil equivalent excluding Libya in the third quarter of 2021.
We project E&P cash costs, excluding Libya to be in the range of 12 to $12 50 per barrel of oil equivalent for the fourth quarter and $11 75 to $12 per barrel of oil equivalent for the full year compared to previous full year guidance of 11 to $12 per barrel of oil equivalent.
The updated guidance reflects the impact of higher realized selling prices in 2021, which significantly improved cash flow, but reduce volumes received under percentage of proceeds contracts and increase production taxes in the Bakken.
DD&A expense was $11 77 per barrel of oil equivalent, including Libya and $12.38 per barrel of oil equivalent excluding Libya in the third quarter.
DD&A expense, excluding Libya is forecast to be in the range of $13 to $13.50 per barrel of oil equivalent for the fourth quarter and the full year is expected to be in the range of $12.50 to $13 per barrel of oil equivalent.
This results in projected total E&P unit operating costs, excluding Libya to be in the range of 25 to $26 per barrel of oil equivalent for the fourth quarter and $24 25 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 $50 million to $55 million in the fourth quarter and approximately $160 million for the full year, which is at the lower end of our previous full year guidance of $160 million to $170 million.
The midstream tariff is projected to be approximately $295 million for the fourth quarter and approximately $1.095 billion for the full year.
E&P income tax expense, excluding Libya is expected to be in the range of $35 million to $40 million for the fourth quarter and the full year is expected to be in the range of $135 million to $140 million, which is up from previous guidance of $125 million to $135 million, reflecting higher commodity prices.
We expect non cash option premium amortization will be approximately $65 million for the fourth quarter.
For the year 2022, we have purchased W. T. I collars for 90000 barrels of oil per day with a floor price of $60 per barrel and a ceiling price of $90 per barrel. We have also entered into Brent collars for 60000 barrels of oil per day with a floor price of $65 per barrel and a ceiling price of 92.
$5 per barrel the cost of this 2022 hedge program is $161 million, which will be amortized ratably over 2022.
During the fourth quarter, we expect to sell two 1 million barrel cargoes of oil from Guyana.
Our E&P capital and exploratory expenditures are expected to be approximately $650 million in the fourth quarter full year guidance remains unchanged at approximately $1.9 billion.
For midstream.
We anticipate net income attributable to Hess from the midstream segment to be approximately $70 million for the fourth quarter and the full year is projected to be approximately $280 million, which is at the midpoint of our previous guidance of $275 million to $285 million.
Turning to corporate corporate expenses are estimated to be in the range of $30 million to $35 million for the fourth quarter and the full year is expected to be in the range of $125 million to $130 million, which is down from our previous guidance of $130 million to $140 million.
Interest expense is estimated to be in the range of $90 million to $95 million for the fourth quarter and the full year is expected to be in the range of $375 million to $380 million compared to our previous guidance of approximately $380 million. This.
This concludes my remarks, we will be happy to answer any questions I will now turn the call over to the operator.
Yeah.
Thank you ladies and gentlemen, if you have a question. Please press star followed by one on your phone.
My question has been answered or you would like to withdraw your question press the pound questions will be taken in the order received please press star one to begin.
Your first question comes from the line of.
Our rooms.
With with Jpmorgan you May proceed with your question.
Good morning.
Greg I wanted to maybe start with you on Liza Phase two you mentioned that the ship got to stay broke block on Monday, but just using Liza phase one as a guide can you give us a sense are around you know how many days or months do you think you could you could be the first oil.
Yeah sure. So thanks for the question Arun you know remember now that its arrived in waters. The first thing that we have to do is more to the seafloor and then obviously, there's a lot of flow lines and risers and umbilical you know to get hooked up to the vessel. So what I would say is we are firmly on track for you know in early 2022.
Targa up and don't think I could be more definitive than that but early 2022 looks like a very possible.
Great Great and then my follow up or Greg maybe for you as well.
One of the questions from the buy side is is just around overall inflation and just how to think about.
Some of the inflationary.
Pressures raw materials et cetera on future phases of the project that I know that you're in the market now.
With Exxon on yellow tail.
And then you know one of your key subsea provider did put some color around.
The subsea kit that they expect around yellow tell and you are ru.
You know they cited it may be a 500 million to $1 billion range for yellow tail and a little bit over 1 billion for you or La Roux, just maybe you could just help us think about.
You know our inflationary pressures Greg.
Sure I think you know first of all yes. There is there is inflation going on and I think there's a couple of things we have to remember first of all.
For the first three phases, which you mentioned those are under existing EPC contract. So we're we're basically insulated from cost increases on those EPC contracts and then Exxon Mobil is doing an extraordinary job I think of utilizing this design one build many strategy to deliver efficiencies now in yellow tail we.
We still don't have the final numbers. So once that project is sanctioned.
We'll give the market color on what the costs are I do think it's important to remember the nature of the PSC, though so by the time you get the yellow tail the efficiency of the PSC is so rapid.
That any cost increases rapidly get recovered so the impact on overall project return is not very very much at all right because of that super efficient PSC and the break evens for yellow tail, we project, even with some cost increases will be.
And the you know firmly in the 25% to $32 a barrel range. So.
One of the best projects on the planet.
Even with some potential cost increases great project.
Great. Thanks, a lot Greg.
Thank you. Our next question comes from Doug Leggate with.
Bank of America, you May proceed with your question.
Thanks, Good morning, everybody.
I know you haven't given 2022, yet but.
Given the oil price recovery that we've seen on the.
Very smart edge user thank you guys.
I'll go back to the Capex guidance that you gave in 2018 versus <unk> and I Wonder if I could just ask you to give us a kind of framework, we should think about spending trajectory.
And then if I mean embedded in that question be blunt with you I think there's some concern over the coals.
The sticker shock on yellow pill, so if I threw a number and said well we should be thinking something in the $12 billion type of range.
Mark.
Doug Let me start with just giving some color on.
On our capital for 2022 now you know, obviously, we will finalize that and it will give our full guidance in January but from a directional standpoint.
Let's start with the Bakken you know we've added a rig dare rule of thumb when we add a rig is approximately $200 million when we add a rig in the Bakken. We're also to your point with the higher prices, we're seeing more ballots for non operated wells. So for that we could see an increase of approximately 50 million in our in our.
Non op JV wells next year, so if you're looking at Bakken approximately $250 million of of a capital increase as we look at next year, obviously with a pickup in production and an increasing cash flow, though also as well coming from Bakken and Guyana, We expect our development spend so we went into the year with it.
With the guide was $780 million for our development spend in Guyana, we're going to come in under that and so let me just say, we'll probably be approximately $750 million on our Guyana development spend this year, so with Liza phase two and it continued development on Pi are up and will begin spending on yellow tail we.
Think it's approximately $1 billion will be the Guyana capital for the developments next year. So approximately again another $2 50, there the.
The other areas than our Gulf of Mexico, and Southeast Asia on Gulf of Mexico, You know, we're basically not spending much much money at all this year in the Gulf of Mexico, and we typically spend $150 million to $200 million and we do plan to drill a tie back well and one exploration well next year and in Southeast Asia, We're looking to complete.
Our phase three and phase four developments in North Malay basin. So we'll have some increase there. So I'd say combined those will be about 200 million. So you've got 500 million from Bakken and Guyana 200 from Gulf of Mexico, and Southeast Asia, but I have to remind everyone will have liza phase two coming online.
And so you know I'll just do I always do that simple math, if when you when Liza phase two comes on in full and we have our share of 220000 barrels of oil per day were basically and I'm just going to use a $60 Brent price and about a $10 cash cost we pick up $1 billion of additional cash flow from Liza phase two along.
And when that comes on and then obviously you have pie are in yellow tail. So we'll get much more cash flow as each F. P. S. O comes down so that's a directional we'll update in January John you want to talk yoga and doggone yellow tail well you know they have to bees, Ben are submitted to the government and it is higher cost I think.
Everybody needs to realize this F. P. S. O is going to have capacity of approximately 250000 barrels of oil per day on a gross basis it'll be our largest oil development to date in Guyana and while its costs will be higher the resource. We are developing is significantly higher and this development.
Has simply outstanding financial returns some of the best in the industry as Greg mentioned and our breakeven costs between 25 and $32 per barrel Brent. So its outstanding economics, yes, the costs are higher but the resource we're recovering as much higher and these are some of the best economics in the industry.
So I wouldn't embarrass any wanted to $12 billion John.
I won't comment on that let's let the F. D. P be approved and then we will announce the official number.
Thanks, My follow up hopefully a quick one and it really is only on yelp.
You mentioned the 250.
Thank you Luis.
Yes, so 20% to 50, Greg I just wanted to just check in with you on how should we think about.
Adoption optimization all of these tools.
Is it 10% to 15% in other words above the nameplate.
Okay.
Yeah, Doug So I think you know based on again. This is just my experience being in this business 38 years I would think that you know for developments of these size and everyone will be bespoke. So everyone will be a little bit different but I think a range of 10% to 20%.
Capacity for Debottlenecking or capacity increases is a reasonable expectation.
Again, everyone will be a little bit bespoke, you'll wait and get some dynamic data see where the bottlenecks are but I don't think that's an unreasonable expectation for future vessels and I think the second point is remember.
These increases in capacity.
Our typically achieve for for very low investment and obviously with the PSC. The rapid cost recovery. These are very profitable thing to do.
Appreciate the answer guys. Thank you.
Thanks.
Thank you. Our next question comes from Paul Cheng with Scotiabank. You May proceed with your question.
Good morning, good morning, Greg.
I think previously that the expectation that the button that you need to have one would be doing at the same time, you're at the time of RNG and now is being separately and push it to the first quarter is there any particular reason for that decision.
Greg.
Yeah, So Paul but you know as you said the optimization work on the desk that he is now planned for the first quarter.
This was simply deferred to allow other planned maintenance and inspection work to be done concurrently which is much more efficient. So the operator, just pushed it to get some efficiencies and completing a bunch of other work at the same time already had the vessel down which we fully support.
With that being more efficient that when the vessel gets done then you do the optimization I mean, I'm actually surprised you say it will be more efficient to separate out into two.
Defense.
No it won't all of that that's what I meant Paul is that you know when do we take it down to do the optimization.
Exxonmobil wanted to do some other work while the vessel was down so pulling some work forward. Some maintenance work that was scheduled for later in the year by doing that all at the same time concurrently, it's just much more efficient and so they needed parts and pieces and et cetera.
And that's why it got pushed to the first quarter.
And quickly I think Oh region Noni, when you signed the agreement with Deca and our government.
At some point that you guys are supposed to give up the gas we source there.
I mean, now that I think up to yellow tell it doesn't seem as though you guys going to do it so at.
Any king Penguin that the gas.
The gas when it could be the battle.
Or that that's what they know they can find NIE, yes, we need to do subject to negotiation with the government.
Hey, Greg Yeah.
Yeah. So I think there's two pieces ball so.
The first piece is the gas the energy project right, there's going to be a the slipstream of gas. If you will 50 to 100 million cubic feet a day pipeline to shore.
That is a wood supply gas and onshore power plant to generate lower cost cleaner more reliable energy.
For the benefit of the people that.
That project is in the design phase right now and once once it's done then we will share the details of the project after sanction regarding the long term gas solution, which is what I think you were referring to you know their studies that way, but it it's way out in the future Paul.
It's not anything certainly we need to worry about in the next five years potentially even be well beyond that so.
But there are studies going on because remember the highest value of the gas.
Is pressure maintenance of these reservoir to significantly increase recovery and the other unique part about the gas as its miscible.
So there'll be an enhanced oil recovery effect as a result of putting that gas back in the reservoir. So the the highest and most beneficial you use if you will of that gas is actually reinjection.
And the final question for me I think is for Don.
John I think you mentioned that once that your net debt to EBITA get to let's say below two times a year, we couldn't see it increasing their.
Cash returned to shareholders.
And at that point that how should we look at it I mean is there a way. So you had pocketing that big incremental cash flow, let's say, 50% still going to the balance sheet and 50% for any incremental.
Casualty time to show without any Kyle estimate that you can you can share and also at that point should we assume that the main vehicle is going to be buyback or it's just going to be increasing the common dividend or that he has stepped up with it but then how should we be looking at those.
<unk>.
Sure so.
Our strategy remains the same and you said it basically we get phase two online we pay off the remaining part of the term loan and our debt to EBITDAX will be below two at that point and we'll begin increasing returns to shareholders. What we're gonna do first with with the returns is increase our dividend.
We'll start there and then obviously as each F. P. S. O comes on we get significant as I mentioned earlier, you know another $1 billion with Pi or another billion dollars with yellow tail will have increasing free cash flow. We can we'll still progressively increased the dividend, but when we have that free cash flow. The majority of that will go.
Back to shareholders and that point, we will be looking at opportunistic share repurchases.
Hey, John when you were talking about.
That once you drop below two times I suppose that.
I'll, let them talk to have we'd be much below two times EBITDAR ratio. So what what that ultimate raised. So you won you said less than one time or less than half on half on multiple upon.
Yes, I'm going to answer it two ways. So once once we do get under two we are comfortable with our absolute debt levels. We have our liquidity is very good you know we have a 300 maturity $300 million maturity coming in 2024, and our next maturity is into 2027.
So we'll continue we can pay off the maturity as they come due and then what will happen is because the EBITDA just increases so much with each F. P. S. L will drive under one times fairly quickly actually when these <unk> come online. So yes, we do want to be below one and look we can do.
That at various commodity prices.
Just again due to the great returns that we have in Guyana.
Thank you.
Thank you. Our next question comes from Phillips Johnston with capital. One you May proceed with your question.
Hey, guys. Thanks, just one for me.
On last quarter's call, we did touch on your strategic strategic thoughts around <unk>.
Hess midstream.
But I just wanted to follow up on the topic, just given the size of that asset.
It seems like you guys, obviously want to get your Bakken volumes up to that optimal level of 200, a day before plateauing at that level once that occurs and once.
Operational and marketing control of midstream is perhaps less critical.
Would you think it makes sense to harvest that asset just by selling it to a third party.
Freeing up capital in the process to potentially return that to shareholders.
Philip I mean, we are very happy with our midstream investment in Gi P is too. So the midstream continues to add what we believe is differentiated value to our E&P assets. Like you said, you know being able to get it up to 200000 barrels a day also.
With that maintaining the operational and marquee and control. It provides takeaway options optionality for us to high value markets.
And as John mentioned earlier, we're very focused on minimizing our mission our mission. So it gives us the ability to increase our gas capture and drive down flaring. So both G. I P. And has remained committed to maximizing the long term value of Hess midstream. So the offerings. We did you know we had the secondary in Q1 and earlier this month they were designed to.
Increase the float of Hess midstream get their liquidity up there any Q3 buyback actually helped meet Hess midstream optimize its capital structure getting to that three times.
Leverage position so pro forma for these transactions Hess midstream it maintains a strong credit position and it has continuing free cash flow. After distributions. So it will continue to have that low leverage and ample balance sheet capacity east coast with the free cash flow will continue to drive that leverage down so that can support future growth there.
Midstream side or incremental return of capital to its shareholders, including has so basically what we're talking about is continuing what we've been doing here with Hess midstream.
And they've been clear our objective is to maximize the value of Hess midstream.
To Hess and also maximize the value of Hess midstream.
To its unit holders and Gi P as well.
Okay.
Hey, guys. Thank you.
Yeah.
Thank you. Our next question comes from Neil Mehta with Goldman Sachs. You May proceed with your question.
Good morning team good morning.
Good morning, guys, Hey, kickoff question is on hedging and.
You made some progress in terms of 2022 and implemented this caller.
Can you just talk high level why you thought that was the appropriate way to attack hedging and it does appear to still leave you a lot of optionality on the upside while protecting your downside, but maybe kick off there.
Sure. So I mean, our hedge strategy I mean, it's just for 2022, it's consistent with our past strategy we.
We look to provide significant downside protection to do this while also given the majority of upside to our shareholders and we're looking for that price protection as we continued to fund our world class investment opportunity in Guyana, So with it as I mentioned, we have the callers 90000 barrels of oil per day of W. Ti puts at a floor of 60.
And the ceiling at 90, and the 60000 barrels of oil per day, Brent puts floor 65 in the ceiling at 95, we use those high ceiling calls to reduce the cost of the program just to be more efficient with our with our hedging program, but also as you mentioned, we retain the exposure to greater than $2 billion in additional cash flow in the case.
Of high oil prices above those hedged floor prices.
In addition, we have not hedged any of our natural gas, obviously know NGL productions hedging we haven't hedged all of our oil production either so we.
We continue to be in a good position to be able to.
Accrete up value with higher oil prices, but again, you know we've got that significant price protection on the downside to continue the investment.
Great guys and then the follow up is just on the Bakken can you spend some time just talking about your development strategy. There what would it take with oil prices up here for you guys to pursue a growth strategy as opposed to a free cash flow strategy in.
In the Bakken.
Greg.
Yeah sure. So you know remember that the primary role of the Bakken and in our portfolios to be a cash engine. So that's the first thing and as such any decision to add rigs in the Bakken is going to be driven by returns in our corporate cash flow position.
And it now having said that at $60 W. T. I you know, we have 2200 future locations, which I'm, assuming you would go up to four rigs over 50 rig years of inventory.
Our ultimate objective is to we'd like to get the Bakken back the 200000 barrels a day.
Why because it optimizes the rent picture and maximizes the free cash flow generation in the Bakken, we can do that by adding a fourth rig and depending on market conditions next year, we would consider adding that fourth rig at the end of next year.
And I think the other thing that's important to remember is if is for rig the maximum we will run in the Bakken that's sort of the efficient frontier if you will.
To just take the Bakken to 200000 barrels a day plus or minus and then just hold it.
With that inventory, we have for nearly a decade at 200000 barrels a day and at that point, you know depending on oil price it generates between $750 billion to $1 billion of free cash flow. So it just becomes this massive cash annuity.
For a very long time and that is the strategy get it up to that level and just hold that cash annuity our position with our inventory as long as we can.
Thanks, Tim.
Thank you. Our next question comes from Noel Parks with Tuohy Brothers You May proceed with your question.
Hey, good morning.
Good morning.
You know I was wondering if you could maybe.
Walk through some of the components of the resource estimate increase you.
You took it from 9 billion barrels.
It's 10 billion barrels.
For the project and I'm just.
Particularly interested.
At the announcement, you said that some of that came from new discoveries like cat of that.
But I'm just wondering the degree well two things would agree that Ah maybe de risking from the most recent drilling helped contribute to the incremental increase.
And.
Also maybe you could drill down a little bit on sand quality and are in the most recent discovery.
You know the.
And you know the consistent you.
You know consistent with your pre drill analysis et cetera.
Yeah, Greg.
Sorry, I was on mute for a second look I think the resource estimate was a combination of a lot of things. Obviously, you know the big things, we're whiptail, one in and whiptail too and pink tail in cat. It back. So those were the primary drivers of taking that number from you know the nine.
Greater than 9 billion to approximately 10 billion. So that was the majority of you.
The change that move.
It's important to also remember that in spite of that Theres still multibillion barrels of additional upside you know above and beyond. This this 10 billion barrels already regarding sand quality. It's all very good I mean, everything we've discovered this year has extraordinary sand quality.
As we mentioned the cat it back well I'm the last well that we announced you know had 102 feet of oil bearing sands, but 243 feet of hydrocarbon bearing reservoirs.
And also whiptail, one was 246 feet with deal 267 feet. So these are very large very high quality reservoirs in all three of those.
Discoveries, so there's no issues with sand quality or reservoir quality in any of those wells.
I'm just wondering in the more recent discoveries anything you can you've been able to extrapolate I guess, maybe just from the consistency among the findings is that.
Helping form.
Your your optimism for the.
Future drilling and step out further.
Sure I think you know what it what it confirms is that you know that entire eastern seaboard is what I like to call. It from you know turbot all the way to Liza and further north is just great great reservoir rock and so part of our strategy going forward in 2022 will be the.
<unk> to build out the prospectively that we see in the and continue to explore and those very high quality.
Upper campaign in reservoirs that I just talked about.
The second objective, we will have in 2020 twos to get more penetration in the deep that's the one with the most uncertainty now and as we mentioned in the fourth quarter, we will drill a well called fangtooth. It specifically aimed at the deep stratigraphy.
And when I say deep at slower campaigning upper sand, Tony and which is about 3000 feet deeper than those upper campaigning reservoirs and then the third objective of our 2022 exploration and appraisal programs continue to appraise. All these outstanding you know discoveries that we've made right. So appraise explorer.
Campaigning explore a.
Deeper reservoirs, though there are three primary objectives next year.
Great. Thanks, a lot.
Yeah.
Okay.
Thank you. Our next question comes from David Heikkinen with Pickering Energy you May proceed with your question.
Good morning, I, just wanted to check a couple of things on yellow tail have you guys finalized is at 45 or 55 wells.
The eight different subsea sites.
Again trying to narrow down on what the total cost is going to be as ware.
Putting estimates together.
Yeah, no that that's still that's still under discussion with the partnership exactly what that configuration will be you know now.
As we said when we when we take final sanction will be able to share all of those details as to what the final project actually looks like.
And to follow up on the point that Greg was making yellow tail has world class economics and returns because we're covering a lot larger resource. So while people are talking a focus on cost they should be focused on the resource which is a lot higher once we get the F. T. P. We can give granularity on that and again the break even.
It's going to be between 25 and $32 per barrel Brent.
It's a much big aerial extent it looks like it is.
The huge area being developed.
With that versus high or even.
And then it was very helpful to put together the.
Kind of incremental capital year over year I did my math right at that roughly two two and a half billion before exploration expense.
No that is that that increase that I gave before so is it 500, combined Bakken and Guyana, and then 200 with Gulf of Mexico, and Southeast Asia. So 700 from our two from our one nine and that includes exploration.
Okay.
Yeah, No no problem and then obviously I just always have to point out with phase II comes on we're picking up that at $60, Brent that $1 billion of additional cash flow. There. So and then Bakken obviously, we're going to pick up some additional cash flow as well from the higher production.
And that's before a potential fourth rig in the Bakken that would get you up to 200000 barrels equivalent a day.
That's correct.
Perfect I've got my numbers right now thanks, guys.
Thank you.
Thank you very much. This concludes today's conference. Thank you for your participation you may now disconnect.
Have a great day.
Thanks.
[music].
Yes.
Okay.
[music].
Yeah.
[music].
Yeah.
[music].
Sure.
Yes.
Hmm.
[music].
Yes.
[music].
Sure.
[music].
Yeah.
[music].
Hmm.
[music].
Okay.
[music].
Hum.
[music].
Yeah.
[music].