Q1 2021 Hess Corp Earnings Call
Okay.
Good day, ladies and gentlemen, and welcome to the first quarter 2021 Hess Corporation Conference call. My name is Catherine and I'll be your operator for today at this time all participants are in a listen only mode. Later, we will conduct a question and answer session. If any time you require operator assistance. Please press star followed by the 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 Catherine good morning, everyone and thank you for participating and our first quarter earnings conference call.
Our earnings release was issued this morning and appears on our website www Dot Hess 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 and such statements.
These risks include those set forth and the risk factors section of Hess is 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 day non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.
As we have done in recent quarters, we will be posting transcripts of each speaker's prepared remarks on our website following their presentations.
On the line with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Reilly, Chief Financial Officer on the I'll turn the call over to John Hess.
Thank you Jay welcome to our first quarter Conference call. We hope you and your families are all well.
Today, I will review, our continued progress and executing our strategy.
And then Greg Hill will discuss our operations and John Riley will then review our financial performance.
Let's begin with our strategy, which has been and continues to be to grow our resource space have of low cost of supply.
And sustained cash flow growth by.
By investing only in the high return low cost opportunities. We have built a differentiated portfolio that is balanced between short cycle and long cycle assets with Guyana as our growth engine and the Bakken Gulf of Mexico, and South East Asia as our cash engines.
Guyana is positioned to become a significant cash engine as multiple phases of low cost oil developments come on line, which we expect will drive our portfolio of breakeven and Brent oil price below $40 per barrel by the middle of the decade.
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.
Even as we have seen the oil prices recover since the beginning of this year, our priorities continue to be to preserve cash and preserve our operating capability and preserve the long term value of our assets in terms of preserving cash at the end of March we had $186 billion of cash on the balance sheet.
The 3.5 billion revolving credit facility, which is undrawn and it was recently extended by one year to 2020, four and no debt maturities until 2020 three.
We have maintained a disciplined capital and exploratory budget for 2020 one of $1.9 billion.
More than 80% of this year's capital spend is allocated to Guyana, where our three sanction the oil developments have of breakeven oil price of between $25 and $35 per barrel and to the Bakken, where we have a large inventory of future drilling locations that generate attractive financial returns at $50 per bed.
Oral W. T I.
And to manage downside risk in 2020. One we have hedged 120000 barrels of oil per day with $55 per barrel W. T. I put options and 30000 barrels of oil per day with $60 per barrel Brent put options to.
To further optimize our portfolio and strengthen our cash and liquidity position, we recently announced two asset sales.
In March we entered into an agreement to sell our oil and gas interest and Denmark for a total consideration of $150 million effective January one 2021.
This transaction is expected to close and the third quarter.
On April eight we announced the sale of our little knife and Murphy Creek non strategic acreage of interest in the Bakken for a total consideration of $312 million effective March one 2021.
This acreage is located in the southern most portion of our Bakken position and the connected to the Hess midstream infrastructure. The sale of this acreage most of which we were not planning to drill before 2020 six brings material value forward. This transaction is expected to close within the next few weeks.
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During the quarter. We also received $70 million of net proceeds from the public offering of a small portion of our class a shares and Hess Midstream L. P.
The Bakken remains a core part of our portfolio.
In February as W. T I oil prices moved above $50 per barrel, we added a second rig which will allow us to sustain production and strong cash flow generation from our largest operated asset.
In terms of preserving the long term value of our assets Guyana with its low cost of the supply and industry, leading financial returns remains a top priority on the Stabroek block, where Hess has a 30% interest and Exxonmobil is the operator, we have made 18 significant discoveries to date with grow.
<unk> discovered recoverable resources of approximately 9 billion barrels of oil equivalent and we continue to see multibillion barrels of future exploration potential remaining.
We have and active exploration and appraisal program. This year on the state of Roadblock yesterday, we announced the discovery of the war room, two well with encouraging results that further define the large aerial extent of this accumulation.
Underpinning a potential future oil development.
In addition drilling activities are underway for appraisal at the long tail, three well and for exploration at the call we'd be one prospect.
Production from the Phase one ran at its full capacity of 120000 gross barrels of oil per day during the first quarter and mid April production was curtailed for several days after of minor leak was detected and the flash gas compressors and discharged silencer.
Production has since ramped back up and is expected to remain in the range of 100000 to 110000 gross barrels of oil per day until repairs to the discharge silence or are completed and approximately three months.
Following this repair production is expected to return to or above Liza destiny nameplate capacity of 120000 barrels of oil per day.
The Liza phase two development is on track to achieve first oil and early 2020 two with the capacity of 220000 gross barrels of oil per day, our third oil development on the Stabroek block at the pie or of field is expected to achieve first oil in 2020 four also with the capacity of 220.
And gross barrels of oil per day.
And you and nearing work for yellow tail, a fourth development on the Stabroek block is underway with anticipated start up in 2020 five pending government approvals and project sanctioning.
We continue to see the potential for at least six F. P. S. OS on the block by 2020 seven and longer term for up to 10 F. P. S owes to develop the discovered resources on the block.
As we execute our company strategy, we will continue to be guided by our long standing commitment to sustainability and are proud to be an industry leader in this area. We support the aim of the Paris agreement and also a global ambition to achieve net zero emissions by 2050.
As part of our sustainability commitment our board and our senior leadership have set aggressive targets for greenhouse gas emissions reductions and.
In 2020, we significantly surpassed our five year of emission reduction targets, reducing the operated scope, one and scope two greenhouse gas emissions intensity by approximately 40% and flaring intensity by approximately 60 per cent compared to 20 and 14 levels.
We recently announced our new five year emission reduction targets for 2020, five which are to reduce operated scope, one and scope two greenhouse gas emissions intensity by approximately 44 per cent and methane emissions intensity by approximately 50% from 2017 levels.
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In addition, we are investing and technological and scientific advances designed to reduce capture and store carbon emissions, including groundbreaking work being conducted by the Salk Institute to develop plants with larger root systems that according to the Salk Institute are capable of absorbing and storing.
The billions of tons of carbon per year from the atmosphere.
In summary, our company is executing our strategy that will deliver increasing financial returns visible and low risk production growth and accelerating cash flow growth well into this decade, as we generate increasing free cash flow. We will first prioritize debt reduction and then the return of <unk>.
Capital to our shareholders through dividend and increases and opportunistic share repurchases I will now turn the call over to Greg for an operational update.
Thanks, John.
Overall in the first quarter, we demonstrated strong execution and delivery across our portfolio the <unk>.
Company wide net production averaged 315000 barrels of oil equivalents per day, excluding Libya, which was in line with our guidance.
The Bakken and experienced extreme weather conditions and higher NGL prices during the quarter.
Both of which led to lower volumes. However, the higher NGL prices resulted and significantly higher net income and cash flows.
Bakken net production and the first quarter averaged 158000 barrels of oil equivalent per day.
Which was below our guidance of approximately 170000 barrels of oil equivalents per day.
Of the shortfall approximately 8000 barrels per day was due to the significant increase in NGL prices in the quarter.
Much of our third party gas processing from our operated production is done under percentage of proceeds or pop contracts.
Where we charge a fixed fee for processing wet gas, but take NGL barrels as payment instead of cash.
Volume from these contracts get reported as Hess net production.
When the NGL prices increase and they did and the first quarter. It takes fewer barrels could cover our gas processing fees and.
Our reported NGL production was reduced but again the.
Higher NGL prices resulted and significantly higher earnings and cash flow.
The other factor and affected Bakken production and the quarter was related to winter storm, Yuri which brought power outages and average windshield temperatures of minus 34 degrees Fahrenheit for two weeks in February.
These extreme temperatures were below safe operating conditions for our crews and led to higher nonproductive time on our drilling rigs.
<unk> higher Workover backlogs and lower non operated production.
As discussed in our January earnings call, we added a second rig and the Bakken in February and.
And the first quarter, we drilled 11 wells and brought four new wells online in the second quarter, we expect to drill and approximately 15 wells and bring approximately 10, new wells online and.
And for the full year 2021, we expect to drill approximately 55 wells and bring approximately 45, new wells online.
Thanks to the continued application of lean and technology, our drilling and completion costs are expected to average approximately $5 8 million per well in 2021, which represents a six 5% reduction.
From $6 $2 million, and 2020 and of 15% reduction from $6 $8 million in 2019.
For the second quarter, we forecast that our Bakken net production will average approximately 155000 barrels of oil equivalent per day and.
And for the full year 2021.
155000, and 160000 barrels of oil equivalents per day.
This forecast reflects the residual weather impacts and higher NGL strip prices the.
Sales of our non strategic Bakken acreage and the planned turnaround at the time of the gas plant and the third quarter.
We expect net production to build and the second half of the year and forecast of <unk> 2021 exit rate of between 170000, and 175000 barrels of oil equivalent per day.
Moving to the offshore.
And the deepwater Gulf of Mexico first quarter net production averaged 56000 barrels of oil equivalent per day, reflecting strong operations following hurricane recovery and late 2020.
And the second quarter, we forecast that the Gulf of Mexico net production will average approximately 50000 barrels of oil equivalents per day for.
For the full year of 2021, we maintain our guidance for Gulf of Mexico net production to average approximately 45000 barrels of oil equivalent per day, reflecting planned maintenance downtime and natural field declines.
And the Gulf of Thailand net.
And net production and the first quarter was 64000 barrels of oil equivalent per day as natural gas nominations continue to increase due to strong economic growth.
Second quarter and full year of 2021 net production or forecast the average approximately 60000 barrels of oil equivalents per day.
Now turning the Guyana.
Our discoveries and developments on the Stabroek block are world class in every respect.
And with Brent breakeven oil prices and between 25 and $35 per barrel represent some of the lowest project breakeven oil prices in the industry.
Production from Liza Phase, one and averaged 121000 gross barrels of oil per day or 31000 barrels of oil per day net to Hess in the first quarter.
As John mentioned production at the Liza Destiny was curtailed for several days following the detection of the minor gas leak and the flash gas compressors discharge silence or on April 11.
Production is currently averaging between 110000 and 100000 gross barrels of oil per day and is expected to stay in that range. While repairs were made to the silencer.
Upon reinstallation and restart of the flash gas compression system expected and approximately three months per.
<unk> is expected to return to or above nameplate nameplate capacity of 120000 barrels of oil per day.
For the second quarter, we now forecast net production to average between 20020 5000 barrels of oil per day, and our full year 2021 net production to average approximately 30000 barrels of oil per day.
S. P M and offshore has placed an order for and upgraded flash gas compression system, which is expected to be installed and the fourth quarter of 2021 per.
Production optimization work is now planned in the fourth quarter, which will further increase the Liza destiny for goodness and capacity.
I think it's important to note that the overall performance of the subsurface and Liza one and has been outstanding.
We have seen very strong reservoir and well performance that has met or exceeded our expectations. Once the flash gas compressors. You're placed we are confident that we will see a significant improvement and uptime and reliability.
It leaves the phase two of the project is progressing to plan with about 90% of the overall work completed and first oil remains on track for early 2022.
The Liza unity peso with the production capacity of 220000 gross barrels of oil per day is preparing the sale from the Keppel yard in Singapore to Guyana mid year.
Our third development Pi Ara is also progressing the plan with about 38 per cent of the overall work completed.
And the project will utilize the leaves of prosperity Fps.
Which will have the capacity to produce up to 220000 gross barrels of oil per day.
The peso hole is complete and top sides construction activities and commenced in Singapore.
First the oil remains on track for 2024.
Front end engineering and design work continues for the fourth development on the Stabroek block at yellow tail.
The operator expects to submit a plan of development to the government of Guyana and the second half of this year.
Pending government approval and project sanctioning the.
Yellow tail project is expected to achieve first oil in 2020 five.
The Stabroek block exploration program for the remainder of the year, we will focus on both campaigning and leaves the type of reservoirs and on the deeper sand Tony and reservoirs.
In addition, key appraisal activities will be targeted and the southeast portion of the stabroek block to inform future developments in.
In terms of drilling activity as announced yesterday the <unk> two well successfully praised the water and discovery and also made and incremental discovery and deeper intervals.
The well encountered approximately 120 feet of high quality oil bearing sandstone reservoir.
And was drilled six eight miles from the discovery, well and playing a potentially large aerial extent.
The standard of drill Max is currently appraising, the long tail of discovery and additional appraisal as planned at Mako and and the Turbot area, which will help define our fifth and sixth developments on the block.
The standard care and has commenced exploration drilling at the Kobe, B, one well and and exploration well and whiptail as planned the spud and May <unk>.
Further exploration and appraisal activities are planned for the second half of 2021 with a total of approximately 12 wells to be drilled this year.
And noble Tom Madden, and the noble Bob Douglas and the noble Sam Croft, which recently joined the fleet will be primarily focused on development drilling now shifting back to production comes.
The wide second quarter net production is forecast to average between 290002 hundred 95000 barrels of oil equivalent per day.
Full year 2021 net production is now also expected to average between 290002 hundred 95000 barrels of oil equivalent per day.
Compared to our previous forecast of <unk>.
<unk> 310000 barrels of oil equivalent per day the.
This reduction reflects the following approx.
Approximately 7000 barrels of oil equivalent per day due to lower entitlements, resulting from the increase and NGL strip prices.
Again, this will be accretive overall to earnings and cash flow.
Second factor is approximately 6000 barrels of oil equivalent per day was related to the sale of our interest in Denmark, and non strategic acreage and North Dakota for which we brought full value forward.
The balance <unk>.
Primarily reflect short term weather fracs and the Bakken from which we expect to catch back up over the course of the year and again forecast a 2021 Bakken exit rate of between 170000, and 175000 barrels of oil equivalents per day.
In closing our team once again demonstrated strong execution and delivery across our asset base under challenging conditions, our distinctive capabilities and world class portfolio will enable us to deliver industry, leading performance and value to our shareholders for many years to come and will now turn the call.
All over to John Reilly.
Thanks, Greg.
My remarks today I will compare results from the first quarter of 2021 to the fourth quarter of 2020.
We had net income of $252 million and the first quarter of 2021 compared to an adjusted net loss of $176 million, which excluded and after tax gain of $79 million from an asset sale and the fourth quarter of 2020.
Turning to E&P E&P.
E&P had net income of $308 million in the first quarter of 2021 compared to an adjusted net loss of $118 million and the previous quarter.
The changes and the after tax components of adjusted E&P results between the first quarter of 2021, and the fourth quarter of 2020, whereas follows.
Higher realized crude oil NGL and natural gas selling prices increased earnings by $192 million.
Higher sales volumes increased earnings by $99 million.
Lower DD&A expense increased earnings by $88 million lower cash costs increased earnings by $39 million. All other items increased earnings by $8 million for an overall increase and first quarter earnings of $426 million.
Excluding the two VLCC cargo sales, our E&P sales volumes were over lifted compared with production by approximately 300000 barrels which improved after tax results by approximately $10 million.
The sales from the two VLCC cargoes increased net income by approximately $70 million in the quarter.
The impact of higher NGL prices improved first quarter earnings by approximately $55 million and reduced Bakken NGL volumes received under percentage of proceeds or pop contracts by 9000 barrels of oil equivalents per day compared with the fourth quarter of 2020.
Turning to midstream.
The midstream segment had net income of $75 million and the first quarter of 2021 compared to $62 million in the prior quarter.
Midstream EBITDA before Noncontrolling interest amounted to $225 million and the first quarter of 2021 compared to $198 million and the previous quarter.
In March Hess received net proceeds of $70 million from the public offering of $3 million 450000, Hess owned class a shares and Hess midstream.
Now turning to our financial position at.
At quarter, and excluding midstream cash and cash equivalents were approximately $1 $86 billion and our total liquidity was $5 5 billion, including available committed credit facilities, while debt and finance lease obligations totaled $6 6 billion.
Our fully Undrawn $3 5 billion revolving credit facility is now committed through May 2024. Following the amendment executed earlier this month to extend the maturity date by one year.
In the first quarter of 2021 net cash provided by operating activities before changes in working capital was 850 $815 million compared with $532 million in the fourth quarter of 2020, primarily due to higher realized selling prices and.
And the first quarter net cash provided from operating activities. After changes in working capital was $591 million compared with $486 million in the prior quarter.
The sale of our little knife, and Murphy Creek acreage and the Bakken for total consideration of $312 million is expected to close within the next few weeks and the sale of our interest in Denmark for total consideration of $150 million is expected to close in the third quarter of this year.
Now turning to guidance.
Our E&P cash costs were $9.81 per barrel of oil equivalent, including Libya and $10.21 per barrel of oil equivalent excluding Libya in the first quarter of 2021.
We project the E&P cash costs, excluding Libya to be and the range of 12 to $13 per barrel of oil equivalent for the second quarter, primarily reflecting the timing of maintenance and workover spend.
Full year E&P cash costs are expected to be and the range of 11 to $12 per barrel of oil equivalents, which is up from previous full year guidance of $10 52 of $11 50 per barrel of oil equivalents due to the impact of updated production guidance.
DD&A expense was $11.83 per barrel of oil equivalents, including Libya and $12.36 per barrel of oil equivalent excluding Libya in the first quarter.
DD&A expense, excluding Libya is forecast to be and the range of $11 50 to $12 50 per barrel of oil equivalent for the second quarter and full year guidance of 12 to $13 per barrel of oil equivalent is unchanged.
This results in projected total E&P unit operating costs, excluding Libya to be and the range of $23 50 to $25 50 per barrel of oil equivalent for the second quarter and $23 to $25 per barrel of oil equivalents for the full year of 2021.
Exploration expenses, excluding dry hole costs are expected to be and the range of $40 million to $45 million and the second quarter and full year guidance of $170 million to $180 million is unchanged.
The midstream tariff is projected to be and the range of $260 million to $270 million for the second quarter and full year guidance of $1.090 billion to $1.115 billion is unchanged.
E&P income tax expense, excluding Libya is expected to be and the range of $25 million to $30 million for the second quarter and of $105 million to $115 million for the full year, which is up from previous guidance of $80 million to $90 million due to higher commodity prices.
We expect non cash option premium amortization will be approximately $65 million for the second quarter and approximately $245 million for the full year, which is up from previous guidance of $205 million, reflecting additional premiums paid to increase the strike price on our crude oil hedging contracts.
And the second quarter, we expect to sell two 1 million barrel cargoes from Guyana, whereas we sold.
Three 1 million barrels in the first quarter and we expect to sell five 1 million barrel cargoes over the second half of the year.
Our E&P capital and exploratory expenditures are expected to be approximately $500 million and the second quarter and the full year guidance of approximately $1 $9 billion remains unchanged.
For midstream, we anticipate net income attributable to Hess for the midstream segment to be and the range of $60 million to $70 million for the second quarter and the full year guidance of $280 million to $290 million remains unchanged.
For corporate corporate expenses are estimated to be and the range of $30 million to $35 million for the second quarter and full year guidance of $130 million to $140 million is unchanged.
Interest expense is estimated to be and the range of $95 million to $100 million for the second quarter and full year guidance of $380 million to $390 million is unchanged.
This concludes my remarks, we'll be happy to answer answer any questions I will now turn the call over to the operator.
Ladies and gentlemen, if you have a question. Please press star followed by the one on your telephone. If your question has been answered or you would like to withdraw your question press the pound key quest.
Questions will be taken and the order receipt. Please press star one to begin.
So the first question comes from Neil Mehta with Goldman Sachs. Your line is open.
Thanks, guys. Congrats on a good quarter, John you talked about accelerating returns back to shareholders. When you get net debt to EBITDA sub two times and it seems like between leave the two and the forward curve, you're going to get there inside of of one year. So how do you think about what to do with the excess cash and the.
Optimal allocation of that to shareholders.
Thanks Neil.
Yes, now with the you know we've had a strong first quarter and and we're seeing market conditions favorable for oil right now and is still our plan our strategy.
The phase two comes on and that's 220000 barrel a day ship. So we will get our entitlement there will significantly drive our cash flow inflection for US next year and therefore, our debt to EBITDA will begin to get under two as we take that excess cash flow than we have and pay down the <unk>.
Term loans. So the first thing that we're going to do with excess cash flow is pay down the $1 billion term loan once we have that paid off and that increased EBITDA from phase two we will be under two times debt to EBITDA.
For our balance sheet, and then we'll be in that position to start increasing returns to shareholders and we've been consistent about it with the first thing. We'll do is increase our dividend will start to increase the dividend and then S. R.
Our cash flow continues to grow with Pi Ara coming on and then yellow tail and as like we said, we expect now up to 10, Sps sales will have a significant cash flow growth will begin to do opportunistic share repurchases after the dividend increase.
Clear. Thank you and that's the follow up is just about the long term value of the Guyana research resource. So much has been said about the long term risks the oil demand and I was just curious how and how do you think about the value of of.
So some of the projects and the Dsos that come in post 2026 as electric vehicles start to accelerate and some of the competitive threats start to be there for traditional transportation demand and does that change in any way. The way you think about prosecuting this project, including the potential to monetize some of some of the <unk>.
And earlier in order to pull forward the value to mitigate some of the long term demand risks.
Yeah, Great question, Neil. Thank you a couple of points, we'd like to make a you know the look the world has to future challenges.
One is how do we provide more energy supply, 20% more energy supply by 2040, and how do we get to net zero.
Emissions by 2015.
And I think the best resource to provide insights into these challenges as the world energy outlook of the International Energy agency and under the sustainable development scenario, which says that even if all of the pledges of the Paris climate accord.
And were met oil and gas would still be 46 per cent of the energy mix and 2040. So it's not just about climate literacy. It's also about energy literacy oil and gas are still going to be needed 20 years out the key to all of this because none of us kind of call of oil price theres always going to be volatility.
And some of the pressures you're talking about obviously youre going to be a factor and that the key will be having a low cost of supply and we believe that we're uniquely positioned in that regard with a growing resource a low cost of supply of.
That positions our company with the differentiated portfolio of assets that we have with the growing resource at low cost of supply to deliver a sustainable and industry, leading cash flow growth and financial returns for our shareholders and when you talk about the longer term I think it's important to realized that Guyana isn't as longer term we're bring.
And forward almost every year first and 2022 with Liza two then in 2020 four with Pi Ara and yellow tail in 2025. The payouts are very quick and the returns are very high. So you know we are going to be bringing value forward and you can look at a cadence most likely.
Of bringing on one of these low cost developments about every year. Thereafter, so we are bringing the value forward and with low cost of the supply. We think we're going to be uniquely positioned to provide sustainable and industry, leading cash flow growth.
Thanks, Tim.
Thank you and next question comes from Jay.
And <unk> with J P. Morgan your line is open.
Yeah good morning.
Morning, Good morning.
Greg I was wondering if you could provide an update on the Debottlenecking project at Liza Phase, one and and maybe discuss how the repair activities on the flash gas compressor impact the timing of the project and also wanted to see if you could provide a little bit more color.
You mentioned that S. P M may be replacing the flash gas compressors, so maybe a little bit more color around that.
Yeah sure. So let me and let me take it and that you know and two pieces. So first let's talk about the flash gas compressors.
As John and I, both mentioned in her opening remarks, and a couple of days of downtime.
The associated with that where production was curtailed for a couple of days.
Net flash gas compressors now back in Houston.
Being torn down and looked at with the expectation that it will be restored.
Within the next three months right. So once that happens then we will get back to that 120.
And barrels a day plus I'll say that the July.
Then the next increment as you mentioned is the Debottlenecking project, which now is going to occur in the fourth quarter and that will take the Liza phase one up another income rent of production now Theres still and final engineering phases of that so I can't give you an exact numbers and what that's going to be.
But that will come in the fourth quarter also in the fourth quarter Exxon is going to replace the existing flash gas compressor with some of the components of it had been redesign.
So that the shut that shut down and the fourth quarter of about 14 days will accomplish those two things it'll be the debottlenecking and also the installation of the new redesign flash gas compressors for phase one.
Great and my follow up is perhaps for John Reilly, John how does the improvement and oil prices impact yours, and exxon's thinking on the purchase versus lease decision on the Fps So from a timing perspective.
Right now Exxon is and discussions with SPM theyre, having commercial discussions on the purchases of that so it is ongoing and the oil price itself doesn't really have a factor in there, but they're just they're going through these discussions we expect to have that information later in the.
Year, and we'll we'll provide the guidance on the timing of the PSL purchases when we when we get that information.
All right fair enough. Thanks.
Yeah.
Thank you. Our next question comes from Doug Leggate with Bank of America. Your line is open.
Thanks, Good morning, everyone.
Doug.
So.
Greg IRR of 38% complete.
As of at least on the the whole SPM is telling US 12 14 months.
On the.
Some of the topside installation for the standardized units.
Could you middle of next year of a completed the Fps. So can you walk me through how you get from the middle of 2020 two to 2024 port of forest oil when the growth throughout the middle of next year.
Well I mean, Doug as you know prior of does have a very drilling.
Drilling and surf.
Program in particular that the surf requires.
Three.
The three open water.
Seasons, if you will.
Get all of that subsea kit and so you know look buyer is going well there is still contingency built into the project, which I think is prudent at this point given that significant amount of sort of work that has to be done but.
The exxonmobil is executing extremely well.
Hopefully.
And our will come on earlier in 2024, So we will see Doug and Theres a lot of work left to do yet.
Okay.
And in person and Greg I'll, let take a small bet with you the PCL of 23 of them about the some point.
Okay.
My follow up is on the exit the market.
How long have you been able to lose.
Yeah.
The sudden 8000 barrels a day of Ngls and.
And the pulp contracts.
On the fourth quarter, you also guided sort of exit rate of about 175 has been reasonable even with the second rig. So can you just walk us through whats going back sort of there to allow you to stick with the state and guidance and I'll leave it there. Thanks.
John do you want to answer the pop contract question, John right, but yeah sure. So the first I can just start.
With the way the pop contracts work day, the amount for the full year and in our guidance you saw that it's about a 7000 barrel a day reduction from our original guidance now, it's a little higher and in the first second and third and a little bit lower and in the fourth so we're not hit with as high of number on that pop in the fourth quarter.
But yet there is still impacting that and and originally we were guiding at that 175 now with the $1 70, and 175 that pop does have impact to it and I'll start with Greg, but the well performance is good at the wells that we're bringing on we're seeing very good.
The production, we're seeing better than and expectations now you got to remember we had 12 on and the fourth quarter only four in the first we're just beginning now to pick up from the second rig and that will really pick up and the third and fourth quarter. So we see the performance from from those wells will pick that up and give us that ability to get back.
To that exit rate of $1 70 to $1 75.
Greg I don't know if the if there's anything else you want to add.
And I think he and I think you nailed it John.
And that's really helpful guys. Thanks, very much Jay.
Thank you.
Thank you. Our next question comes from Jeanine Wai with Barclays. Your line is open.
My first question is on Guyana.
Well the one.
Average Q, you indicated and encountered newly identified interval of below the original discovery well can you provide just any color on the commerciality of the zones and have you seen them elsewhere and the block and do you plan to test them elsewhere. This year.
Go ahead, Greg Yeah. Thanks, Yeah. Thanks, Janine so.
Again, what were too with the Great result, right.
We had high quality oil fans of 120 feet.
I think the most significant part about <unk> was that it was $6 eight miles from Wahoo, one which demonstrates the very large aerial extent you know for.
For the wall room as well.
Reservoir itself and unit.
You said, we did discover a deeper zone, it's in the lower part of the campaign in and that does have read through to the other.
Parts of the block, but certainly the reason we didn't call. It the 19th discoveries in this particular location.
It's clearly not as significant as the other 18 right.
But it does have some read through the other parts of the block.
And so are there he is that the appraisal of the appraisal is very encouraging results.
You have a excellent reservoir characteristics you are of high quality oil and given that why would one versus one or two of 6.8.
The $6 eight miles away you know it shows the potential for large area of the extent of our highly prolific high quality reservoir.
Okay.
Really helpful. Thank you.
And my second question, and maybe just going back to the Debottlenecking discussion and everyone's question lethal and capacity of going up and Q4.
And now what level of later.
The future potential opportunities are there and de bottlenecking opportunities built into the 220 named nameplate capacities for the upcoming ship. It just seems like that's pretty standard for a lot of these major capital projects, including <unk> and <unk>.
And when we do the math, if you do any kind of moderate debottlenecking and it really pulls forward a lot of any day now so just wondering kind of the potential for that for the <unk>.
Yes, Greg.
I think you could assume that there would be.
And Debottleneck necking potential and all of those ships.
What typically happens as you bring these facilities up to their nameplate.
And then you gather a lot of dynamic data and you really need that data.
So you need fluids running through the facility at full capacity.
Determine where might pinch points, where my bottlenecks and what can I do the increase that capacity and the.
That's why you typically see these debottlenecking projects occur.
Year after.
Of that operating experience on the vessel because of the key piece of data that you have to have is the dynamic data of how is that the absolute really operating under dynamic conditions. So, but I think you can expect every one of those will get the bottleneck above their nameplate in the future.
Great. Thank you very much.
John.
Thank you. Our next question comes from Paul Cheng with Scotiabank. Your line is open.
Hey, guys good morning.
And as Paul.
And I think I'm sort of.
The question first John the.
Net debt to EBITDA and less than two.
And at the 60 total Pos that doesn't seems to have a very conservative number pretty soon and it's just the near term. So what is the longer term expectation.
That the EBITDA change a lot due.
Due to the commodity prices.
Yes, Youre right I mean, it's a little and our EBITDA is going to change one from commodity prices and to as each F. PSL comes on and Guyana, Obviously are our EBITDA is going to jump off with each of which he shift coming on line. So for US. What we did was set at two is kind of of Max and once we got to that.
Debt to EBITDA being under two that's when we would start with the returns to shareholders. Now we have no intention of increasing get during that future time period, because now we will be generating free cash flow. So what we will have with each ship coming on as the EBITDA goes up that debt to <unk>.
EBITDA is going to drive down and it's going to drive under one.
Look we're going to have a very strong balance sheet, and obviously be and are positioned for beginning to increase dividends first and then because of that free cash flow position doing opportunistic share repurchases.
You have a net that pocket at all.
So really short term as we said it is at two times and then after that it's just going to be a function of our free cash flow driving it so quite frankly, you know I.
Love to have that keep it underneath one.
And we have the portfolio to do it you know we just unique each F. P. S O coming on I mean, I'll, let you put your own Brent assumptions in there, but for the amount of production that we get all Brent based production. We're just going to have significant EBITDA growth and therefore, that's going to put our balance sheet and a very strong position and so wed.
Like to keep that debt to EBITDA very low from that standpoint, and what we do with that excess cash as John said earlier is we'll return it to shareholders through dividend increases and share buybacks.
And John the.
First quarter working capital was a big the use of cash and you and the second quarter and.
And the comp guidance that you can pull line.
So let me just do the first quarter first and I'm going to give the the normal recurring and there were two nonrecurring things that of offset each other so.
The the basic driver of the $220 million of draw was an increase in receivables of $150 million, which we're happy to have obviously oil prices going up so our receivables went up from that standpoint, and then we did have you saw the lower cash costs of the lower capital numbers.
So we did have a reduction in payables of $70 million. So that 150, and 70 was the draw and working capital. We did have two nonrecurring items one was the.
As we increase the strike prices on our hedges. So we had premiums paid there, but we also had the reduction and inventory from our VLCC sales. So they net against each other so as you move into the second quarter with receivables that should balance out now with the prices now price.
<unk> continue to go up you'll you'll still.
See that any potential increase in receivables and then we should be building as we mentioned and our guidance on capital.
So I would expect the payables to be let's just call it flat so not.
And forecasting a draw if per se and the second quarter.
Okay. Thank you.
Greg if I could have a quick question on Uh huh.
I think in the past that the expectation is that you would get to about 200000 barrel per day and sort of up to total at that full and number of years. So is that still the the medium term objective of Boston and then find though the on visa on the day, but can you tell us with the quit the co pay.
And what that what is the unit that you and the Liza one and you are.
The button and they are allowed.
Allows us to get a higher production and capacity from that shape. Thank you.
So let me let me take the second one first so.
Again, all of the engineering is still underway.
And you know on Liza phase one.
The optimization project or Debottlenecking.
There was nothing remarkable.
The piping changes et cetera.
To eliminate or reduce the friction and basically.
Flowing through the facility on on the top sides. So we can give more color.
Is that as it is the engineering of that project.
It gets done now regarding the Bakken now.
Again, the primary role of the Bakken and our portfolios could be of cash engine and so as such.
The decision to add any rigs and the Bakken is going to be driven by corporate returns and corporate cash flow needs now.
If prices remain strong and the second half of this year. We're considering the addition of the third rig and the fourth quarter of of.
2021.
And then as you indicated our medium term or long term objective again going to be driven by returns and drove my corporate cash flow.
And would be to get the Bakken back to 200000 barrels a day that would probably require a fourth rig.
And by doing so.
At $60 of Debbie Ti the Bakken would be a billion dollar of year free cash flow generator at 200000 barrels a day. The other nice thing about the 200000 barrels a day is it optimizes.
And use of the infrastructure that we have built up there. So it's sort of at the ultimate sweet spot sweet spot for the Bakken, but again, whether we add that fourth rig of the third rig is going to be driven by returns and corporate cash flow needs because of the role of the Bakken has to be of cash engine.
Thank you.
Thank you our next.
Our next question comes from Ryan Todd with Simmons Energy Your line is open.
Good thanks.
Maybe.
A quick one on VR and AR as you think about your drilling program over the rest of the year and maybe end of the first half of next year. What are the what are the key issues that you are looking to address or the you know the key question of what Youre looking to answer over the next six to 12 months.
Greg and.
Sure Ryan So theres really three objectives.
Of the the exploration and appraisal program this year with the with the three drilling rigs the.
The first one is to appraise the existing discoveries and.
And that's really to underpin the fifth and the sixth.
Ship and Guyana so.
<unk> was the first cab off the rank if you will of long tails next.
Herb it will be after that we'll also do Mako as well so we want to get those understood where the appraisal wells and some DSP.
To really inform where ship five and were shipped six gonna go since the yellow tail is number four.
The second objective is to continue to explore the campaigning and.
And to really fill out that patchwork quilt of prospective the if you will between turbot and Liza and.
And you'll see and our Investor pack, there's a number of polygons there that we'd like to get drilled.
This year as well and then the third objective is can we get some deeper penetrations in the San Antonia and.
Certainly the San Antonia and has the potential.
To be of very large and.
Addition to the recoverable resources, and Guyana, and now remind everyone. We've had four penetrations coupled with the Apache is the result.
We see that as very positive, but we got a lot more drilling to do understand it and that is another key objective this year and it gets more penetrations and that so we can begin to piece of the puzzle together on the same Tony and.
Thanks, Greg and I was really helpful and.
Maybe John one for you on a on the higher level of issue.
As we Hess has always been active on the ESG related front, including the efforts as you talked about earlier, the reduced scope, one and two of emissions.
As you step back and consider the ongoing the energy transition and look a little further down the line are there other roles and what you think has maybe able to participate or is.
The best use of your.
The time and capital to really just going to be.
And on low cost of supply of barrels.
Yes, no our strategy.
Remains to be focused on growing our resource of the oil resource is going to be needed and the next 20 years key is having a low cost of the supply and putting ourselves in a position.
To generate sustainable and industry, leading cash flow growth that that's how we're gonna make maximize returns and value for our shareholders, having said that.
And climate change is real the greatest scientific the challenge of the 21st century, I'd recommend everybody to read Bill Gates' booked and how.
How do we avoid the climate disaster, because it really talks about the technological.
The logical challenges ahead of us the <unk>.
Innovation needed there are no easy answers the energy transition is going to take a long time.
A lot of money and.
And need.
Technological breakthroughs to be able to provide more energy to the world as I talked about before but also get on a track to net zero emissions.
Emissions greenhouse gas emissions by 2050, and you know one way that we are going to lead and that the part of that is obviously get our own carpet and footprint down for scope, one and scope two emissions.
And the targets that we've set for 2025 actually get us on the trajectory better and superior to the O GCI all of them.
The oil industry <unk>.
Standards that have been set a number one and number two we are looking at ground breaking research.
And and we think nature offers of that opportunity to really make a difference and the world swing at the Salk Institute, we're very enthusiastic about where most people don't realize but there's a more carbon and the soil. Then there is and the atmosphere and if we can figure out by supporting the great research.
The Salk Institute to capture and store carbon in the soil.
And at a much higher rate and a much higher density than currently is being done that could be of potential game changer and contribute.
And to getting us to net zero carbon emission and so we're trying to play a role, but the first second and third priority is to maximize value for our shareholders.
Great. Thanks, John.
Okay.
Thank you. Our next question comes from David <unk> with Cowen Your line is open.
Sorry about that thanks for squeezing me in guys I just wanted.
One of them wanted to just follow up on some of the Bakken conversations you had a really attractive disposition earlier and the quarter.
I think some of the the.
You know ideology behind that was the.
And the production wasn't hooked up to some of the Hess midstream are there still remaining assets up there to the similar profiles that would be.
Amendable the printing right now.
No you know the the the the majority of our inventory of very high return locations are really underpinning. If you assumed a four rig program of 15 year drilling inventory that's intact.
This is the southern most part of that you know quite frankly, the returns there weren't as attractive as our current inventory.
Wasn't a accretive.
And the strategic tests midstream, so I would say that was more of a one off of unique opportunity, where we brought value forward. The rest of our acreage and we're very excited to have and again as Greg said before the key role of the Bakken is the generates the cash flow and free cash flow through of the company and we're gonna be guided by returns in terms of.
What a rig program is.
And I appreciate the gist of.
A follow up for me just.
You talked earlier about sort of the optimal level of Bakken production.
And you know and really how it becomes like a cash cow now and Thats really its role in the portfolio. How do you think about Gulf of Mexico, along the same day and as it relates to sort of maintaining volumes or the attractive exploration targets. There is high backs that youre looking at beyond 'twenty one.
And that sort of makes sense here or.
Or how does the gun fit and right now.
Yeah, Greg I think it would be great. If you would just talk about you know the role that the deepwater Gulf plays in terms of trading of cash pension as well, but it does have some growth opportunities absolutely. So the the Gulf of Mexico is like the Bakken.
And important cash engine and the platform for.
Higher return opportunities for half so are our minimum the objective is to hold it flat and.
And we have and inventory of of tieback opportunities that we believe we can hold it flat and the in the short term three to four years, probably once we get back to work with some of the tieback opportunities first of these hybrid.
The return opportunities Llano, six which were currently evaluating with shell and.
And if we sanction the attic quickly add production.
With the expected first oil and four months from spud.
And then we also have a large number of exploration blocks. So during the downturn as you recall.
When everybody was focused on the Permian, we stayed focused on the offshore and we acquired 16, new leases and the Gulf of existing leases. So they won't be affected by the bite and moratorium, particularly on new leases.
And in that we see some very good hub class opportunities as well, both and the Miocene and and the emerging Cretaceous.
Our foot play so we'd like to get back to work on the hub class opportunity and the first one is likely going to be of well called Heron, which is of very large.
Miocene opportunity. So we've got the inventory to as a minimum hold it flat and then potentially even grow it but like the Bakken investment and the Gulf of Mexico is going to be a function of returns and <unk> and cash flow needs of the corporation.
Well, we certainly get the inventory of you do it and we'd like to get back to work as soon as we can.
Thanks for the.
And the uptake.
Thank you. Our next question comes from Roger read with Wells Fargo. Your line is open.
Hey, good morning. Thanks.
Morning.
Just two things I guess the follow up on kind of on the the smaller side of things at least the first one but as you talked about the improvement and capex per well and the backend and I was just curious over the 19 2021 period is that truly apples to apples with the wells in other words, the kind of similar.
Our completion methods and what Youre seeing in terms of production per well in other words is there and efficiency above and beyond.
The what youre seeing on the Capex side and then my other question was going to be on.
Nols and the possibility of the changed tax rate and how you think about that affecting utilization of those over time.
Greg first and then John.
Yeah sure so on the on the Bakken.
No those wells.
Let's say the last three years, we've been drilling the same types of wells.
You know really for the past three years, so there's no differences and say like shorter laterals or anything like that so that you know the the trajectory of well costs coming down is purely lean manufacturing and technology gains.
Along the way.
And so the wells that we're drilling this year.
And I had been had been the same they'd be and the $1 2 million barrel of recoverable.
One of <unk> of about $1 20, which was the same as last year and I think importantly, irr's, averaging nearly 90% of it at current oil prices. So again, a great inventory.
Got a lot of confidence and my team just as we showed with plug and perf or sliding sleeve. We're doing the same with plug and plug and perf through lean manufacturing and technology. We just continue to drive those well costs down and improve productivity as well.
And then Roger on the on the tax policy. So it's a little early for me to to be able to comment on them because of what from what's been released.
More headlines there's just not that much detail on these areas now to your point, we do have a significant net operating loss carry forward, which will mitigate the effects of increased tax rates or are changes and depreciation method. So we will just have to wait for more detail.
Alright, thank you.
Thank you. Our next question comes from Bob Brackett with Bernstein Research. Your line is open.
Good morning, all and thanks for taking my question at the end here I had a question as you return to the southeast part of the block and explore it sounds like the targets are going to be the deeper penetrations in the San Antonia and can you talk about one is there a double opportunity. There are there is still ways to drill wells to get companion.
Plus the Antoni and and maybe a broader question about the future of the exploration are there big perhaps riskier of prospects that you could target and future years. It could be somewhat game changers that could move up the queue in terms of the development plan.
Yeah, Thanks, Bob Greg.
Yeah, So Bob looked at and.
No of the San Antonia and.
Really underlies the entire of Liza complex, so I don't want to imply that that.
And that the southeast portion of the block is the best area for the same Tony and it really underlies.
All of the campaigning and.
And now having said that we need more penetrations.
To understand it and we will get a number of penetrations this year through both ways.
You suggested one is through deepening.
The deeper tails on campaign and exploration wells, but also some standalone, St and Tony and penetrations as well so we'll get a good sense with the four that we have under our belt, coupled with the patches of results.
You know, we're pretty excited about the same Tony and but we've just got more drilling to do but again the aerial extent of the San Antonia and reservoir system is as big or bigger than the Liza complex. So there you know.
Well I wouldn't I wouldn't pick any areas being particularly.
And the sweet spot yet.
Yeah, and Bob to your other point, we still see significant exploration prospects on this block.
As we drill more and get more seismic definition.
On the drilling opportunities some of it's going to be campaigning and some of it's gonna be San Antonia and some of it's going to be further out obviously, we have this aggressive and active program. This year theres more to come and you know our partner Exxonmobil, I think and their investor day and made it pretty clear that there's potential to double the discovered.
Resource on the block.
And we would stand by that in terms of the exploration upside that still remains.
Thanks for that.
Thank you. Our next question comes from Vin Lavagna Hill with the meat.
MS <unk> your line is open.
Hey, guys. Thanks for taking the question first one on cash return.
Current operators and kind of laid out different strategies I think based on business mix.
But mainly centered around percentage of operating cash flow or percentage of excess cash flow generated back to shareholders.
You guys are in the unique spot and Guyana.
Wondering if the asset kind of pushes you and one direction or the other as far as percentage of operating cash flow of percentage of the free cash flow back to shareholders or maybe something entirely different yeah. Those formulas are mainly for shale producers, that's borne and assembly line of cash flow generation, you know of we have sustainable and industry leading cash.
Flow growth. So percentages I don't think are as relevant to us, but what we've been very clear on as we generate free cash.
John Reilly said, the first priority is to pay down the term loan and then after that the majority of our free cash flow will go back as cash returns to shareholders first increasing the dividend and then opportunistic share repurchases. So the word majority of is the key word there.
Great. Thanks, and maybe just take I know quickly.
Had outlined basically of one F DSO per year kind of.
Starting with the pay.
In 2024, and the release you did mentioned at least six Fps is by 2027.
And you're reading a little bit too deep into it here, but just wondering if there was any hurdles factors of variables that we should be considering or that you guys are considering that could potentially accelerate DSO of deployment schedule and longer term.
Yeah look in our exploration and appraisal program cashiers to really help define what.
What the fifth ship will be and potentially the sixth ship in terms of development and I think the cadence of about one ship per year is.
Is the one we're aiming at terms of design, one build many being capital discipline and bringing value forward Exxonmobil as Greg said before is doing an outstanding job of project management on the building these ships and bringing them into the theater, obviously debugging of.
Lease of one but will benefit for Liza two in terms of that and you know it's basically the cadence of about one ship of year and the exploration or appraisal program is to give definition to those future developments.
Thanks, guys I appreciate it.
Thank you. Our next question comes from Monroe Helm with Barrow Hanley. Your line is open.
Thank you very much to get me and the queue Congrats.
Relations and continuing to execute on your game plan, which is.
Furniture to the asset base and the market is starting to recognize it.
Thank you moving ahead.
And we had my questions you were kind of a follow on two questions on the San Antonio.
Greg can you be more specific about which will any of the wells that you've identified the drilling the first half.
Targeting and San Antonio and.
Coming true.
And along those lines one of them up to the launch.
And kills hub trucks of boat.
Yeah, So there will be and Monroe certainly of the early early first part of the year first half of the year long tail of three we'll have a tail on it.
The dip down and at the same Tony and and flip tail will as well.
So recall with tail is kind of of the next campaigning.
The exploration prospect and the Q right. After <unk>. So both of those will have the San Antonia and tails on them.
And then there'll be other ones and the second half of the year, we're still trying to define the exact drilling order and the second half of the year, but those are the would be the first the next two.
And I think you said that there will be squeezed slip of the same Tony interest as the current there'll be yes at least one that will be aimed at the same Tony and.
It's the only.
My second question is and Exxon so sensors.
Because the double the reserve the exploration program does that include the San Antonio.
Yes.
Okay. Thank you very much.
Yeah.
Thank you thank.
Thank you.
Thank you very much of this concludes today's conference call.
Thank you for your participation you may now disconnect everyone have a great day.
Thank you.
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