Q3 2020 Hess Corp Earnings Call
Welcome to the third quarter 2020 S Corporation Conference call.
My name is Andrew and I'll be your operator for today.
At this time all participants are in listen only mode later.
Later, we'll conduct a question and answer session.
Anytime you require operator assistance. Please press star followed by zero he 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 Andrew 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 at Www 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 factor section of <unk> annual and quarterly reports filed with the FCC.
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.
As usual with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Reilly, Chief Financial Officer.
I will turn the call over to Josh.
Thank you Jay welcome.
Welcome to our third quarter conference call.
Hope you and your families are well in staying healthy during these challenging times.
Today, I will provide an update on our progress in executing our strategy in the current low oil price environment.
Then Greg Hill will discuss our operations and John Reilly will review our financial results.
Before we address this quarter I would like to talk briefly about the macro outlook for oil and how it informs our strategy.
The International Energy Agency, just published its 2020 World energy outlook that provides an aggressive sustainable development scenario in which if all the pledges are the Paris climate agreement Ormat oil and gas would still be 46% of the energy mix in 2040.
The energy transition will take time and major breakthroughs in technology will be needed.
Well, we need policies to encourage renewable energy to battle climate change oil and gas will be needed for many decades to come and we will continue to be fundamental to world economic growth and human prosperity.
The key for our company is to have a low cost of supply in any price environment.
By investing only in high return low cost opportunities, we have built a differentiated portfolio of assets that we believe will provide industry, leading cash flow growth over the course of the decade, which is superior to our peers and to most companies in the S&P 500.
Our portfolio is underpinned by significant cash engines in the Bakken deepwater Gulf of Mexico, and Southeast Asia, as well as multiple phases of low cost <unk> oil developments, which we believe will drive our company's breakeven price to under $40 per barrel Brent by mid decade.
To realize our long term strategy, we must manage the short term challenges facing our industry.
Our priorities during this low price environment are to preserve cash.
Preserve capability and preserve the long term value of our assets.
In terms of preserving cash we came into 2020 with approximately 80% of our oil production hedged with put options for 130000 barrels per day at $55 per barrel West, Texas intermediate and 20000 barrels per day at $60 per barrel Brent Ti.
Enhance cash flow and maximize the value of our production in March and April when U.S. oil storage was near capacity, we charter three very large crude carriers or be lccs to store 2 million barrels each of May June and July Bakken crude oil production. The first B.L.C.C. cargo of 2.1 million Boe.
Sales was sold in China at a premium to Brent in September this.
The second and third VLCC cargoes are expected to be sold in Asia by the end of the year.
We have also reduced our 2020 capital and exploratory budget by 40%.
From $3 billion to our current revised guidance of $1.8 billion, primarily by reducing our Bakken rig count from six to one and.
And we reduced our full year 2020 cash operating costs by $275 million at.
At the end of September we had $1.28 billion of cash a $3.5 billion undrawn revolving credit facility and no debt maturities until the term loan comes due in 2023.
In terms of preserving capability, we have been operating one rig in the Bakken since may down from six rigs at the beginning of the year to maintain the lean manufacturing capabilities and innovative practices that Greg and his team have built more than four over more than 10 years.
Our plan is to remain at one rig until oil prices approached $50 per barrel W.T. <unk>.
Before reducing the rig count we achieved our goal of 200000 barrels of oil equivalent per day six months ahead of schedule.
In addition, our Bakken team has cut our average drilling and completion costs below $6 million per well and we continue to see further opportunities for cost reductions.
In terms of preserving the long term value of our assets Guyana with its low cost of supply and industry, leading financial returns remains our top priority.
We are very pleased that on September thirtyth. The government I've got you ought to approve the development plan for the pie our field.
Third oil development on the Stabroek block, where Hess has a 30% interest.
Exxon Mobil is the operator.
Alright is targeted for first oil in 2024 and.
And we expect to have at least five f. dsos on the block producing more than 750000 gross barrels of oil per day by 2026.
The three sanctioned oil developments, Lisa one which is producing at least one two and <unk>, which are in construction have breakeven Brent oil prices of between $25 and $35 per barrel, which are world class by any measure.
On September Eightth, we also announced the Redtail and yellow tail two discoveries, bringing total discoveries on the block to 18 in.
Incorporating the current assessment of additional volumes from the Red tail yellowtail too and Walkthrough discoveries.
We are increasing the estimate of gross discovered recoverable resources for the Stabroek block to approximately 9 billion barrels of oil equivalent.
We also now see the potential for up to 510 F.P.S. So at shows to develop the current discovered recoverable resource base.
We announced on October 5th an agreement to sell our 28% working interest in the Shamsi field in the deepwater Gulf of Mexico to BHP Billiton.
Fields, operator for total consideration of $505 million had an effective date of July Onest 2020.
This transaction brings value forward and the low price environment and further strengthens our cash and liquidity position until the lease up phase two development in Guyana comes online in early 2022.
We expect to close the transaction before the end of the year.
Our strategy will continue to be guided by our company's long standing commitment to sustainability, which we believe creates value for all our stakeholders early.
Earlier this month, the transition pathway initiative or T. P. I published its 2020 report on the progress of 163 energy companies and transitioning to a low carbon economy.
And supporting efforts to mitigate climate change in line with the task force on climate related financial disclosures or Tcfe the recommendations and.
<unk> was 2020 report Hess is the only U.S. oil and gas company to achieve a level four star rating.
Which is only a water to companies that demonstrably manage climate related risks and opportunities from a governance operational and strategic perspective, and satisfy all T.P.I. management quality criteria.
In summary, we continue to execute our long term strategy deliver.
Delivering strong operational performance, while prioritizing the preservation of cash capability and the long term value of our assets during this low price environment.
As a result, Hess is uniquely positioned to deliver industry, leading cash flow growth and financial returns over the decade.
As our portfolio generates increasing free cash flow, we will prioritize debt reduction and increasing cash returns to our shareholders I will now turn the call over to Greg for an operational update.
Thanks, John.
In the third quarter, we once again delivered strong operational performance.
Pretty wide net production averaged 321000 barrels of oil equivalent per day, excluding Libya.
Which was within our guidance range of 320000 to 325000 barrels of oil equivalent per day, but.
Bakken net production averaged 198000 barrels of oil equivalent per day.
21% from the prior year quarter and above our guidance of approximately 185000 barrels of oil equivalent per day.
Our strong Bakken performance offset hurricane related downtime in the Gulf of Mexico, where production for the quarter averaged 49000 barrels of oil equivalent per day, just below our guidance range of 50000 to 55000 barrels of oil equivalent per day.
In the fourth quarter, we expect company wide net production to be approximately 300000 barrels of oil equivalent per day, excluding Libya.
This guidance assumes that the skins, the sale closes December 1st and that transitory hurricane related impacts in the Gulf of Mexico.
We'll reduce production in the fourth quarter by approximately 25000 barrels of oil equivalent per day.
We anticipate all hurricane recovery work to be completed before the end of the year, which will allow our shut in Gulf of Mexico production to be fully restored.
For the full year 2020.
Our net production guidance is approximately 325000 barrels of oil equivalent per day, excluding Libya can.
Compared to our previous guidance of 330000 net barrels of oil equivalent per day.
Moving to the Bakken.
In the third quarter, we drilled six wells and brought 22, new wells online.
For the fourth quarter, we expect to drill six wells and bring a 11, new wells online and for the full year 2020, we still expect the girl.
70 wells and bring 110, new wells online.
In the third quarter efficiency gains enabled us to further reduce our average drilling and completion costs per well to bite to $5.9 million, which we believe is top quartile for the Bakken through.
Through the continued application of technology and lean manufacturing techniques, we expect to reduce our DNC costs even further.
For the fourth quarter we.
We expect Bakken net production to average between 180000 and 185000 barrels of oil equivalent per day.
For the full year 2020, we now expect Bakken net production to average approximately 190000 barrels of oil equivalent per day up from our previous guidance of 185000 barrels of oil equivalent per day.
Although we have a large inventory of future drilling locations that generate good financial returns at current prices.
To preserve capital discipline and keep the asset free cash flow positive we plan to maintain a one rig program until oil prices approached $50 per barrel the VTI.
Operating a single rig allows us to preserve our lean manufacturing capability.
We have worked hard hard to build over the years, both within half and among our primary drilling and completion contractors.
Moving to the offshore.
The Gulf of Mexico has felt the effects of seven name storms this season and.
Including Hurricanes data, which is currently in the Gulf that have disrupted operations across the industry.
Production from the Konger and Llano fields is expected to remain shut in for approximately 40, and 75 days respectively. During the fourth quarter due to hurricane recovery work and the Penn State six well will remain shut in until a workover can be completed in December.
In the fourth quarter Gulf of Mexico, net production is expected to average approximately 40000 barrels of oil equivalent per day.
And for the full year 2020, we expect net net production to be in the range of 55000 to 60000 barrels of oil equivalent per day down from our previous guidance of six.
65000 barrels of oil equivalent per day again weeks.
We expect all hurricane impacted production to be fully restored before the end of the year.
Also on the golf in September the Sox, one well reached a gross peak rate of approximately 17000 barrels of oil equivalent per day or 9000 barrels of oil equivalent per day net to half.
The BP operated Galapagos deep exploration well in which he has held a 25% working interest was not a commercial success.
The data from this well in the play will be incorporated into the continued assessment of our acreage position in the Cretaceous, which remains highly perspective.
Moving to the Gulf of Thailand.
Net production in the third quarter increased to an average of 50000 barrels of oil equivalent per day compare.
Compared to 44000 barrels of oil equivalent per day in the second quarter as a result of higher nominations.
We expect fourth quarter net production to be flat with the third quarter at approximately 50000 barrels of oil equivalent per day, reflecting continued kobe uncertainties.
Our guidance for full year 2020, net production is now approximately 50000 barrels of oil equivalent per day compared to our previous guidance range of 50000 55000 barrels of oil equivalent per day.
Now turning to Guyana [noise].
In the third quarter gross production from Liza Phase one averaged 63000 barrels of oil per day or 19000 barrels of oil per day net to Hess.
Ongoing work to complete commissioning and that of the natural gas injection system continues.
And once complete will enable the Liza destiny floating production storage and offloading vessel or Fps. So.
To reach its nameplate capacity of 120000 gross barrels of oil per day in December.
It is important to note that the delays in commissioning the gas injection system or mechanical in nature and the reservoirs in wells continued to deliver at or above expectations.
The design one build many concept for the Fpsos will allow the learnings to be captured and applied to future projects.
Production from the vessel has been averaging approximately 105000 barrels of oil per day for the last few weeks.
The Liza phase two development is progressing to plan with approximately 80% of the overall topsides hole and sub sea work completed the.
The project will have a gross production capacity of 220000 barrels of oil per day and remains on track for first oil by early 2022.
In September we announced the final investment decision to proceed with the development of the pie or a field pipe.
IR will utilize the prosperity at P.S. so.
Which will have the capacity to produce up to 220000 gross barrels of oil per day and will initially target a resource base of about 600 million barrels of oil.
First oil is expected in 2024 10.
10 drills centers are planned with a total of 41 wells, including 20 production wells and 21 injection wells.
Also in December we announced the 17th and 18th discoveries on the Stabroek block offshore Guyana.
The yellow appeal to well encountered 69 feet of high quality oil bearing reservoir adjacent to and below the yellow tail one discovery in.
In addition, the red tail, one well encountered approximately 232 feet of high quality oil bearing reservoir.
The well is located approximately 1.5 miles northwest of the yellow tail discovery.
Hey, drill stem test is planned at red tail in the fourth quarter.
These discoveries further demonstrate the significant exploration potential of the block and.
And contribute to the discovered read recoverable resource estimate increasing to approximately 9 billion barrels of oil equivalent.
And we'll likely form the basis of our fourth development on the block.
In terms of exploration the Stana Karen Drillship is currently drilling the Pan and your one well on the tighter block approximately 46 miles northwest of Lisa.
This well, which is the deepest well drilled offshore Guyana is designed to penetrate multiple geologic intervals, including the campaigning same Tony in inter Roni.
The next exploration well on the Stabroek block will be half, the one which will target campaigning age reservoirs, approximately 30 miles east of the Liza field.
This well should spud and near the end of the year and re expect results during the first quarter.
Before I leave Guy and I'm I think it's important to remind you of what makes the stabroek block so unique.
First the size and scale.
The block is 6.6 million acres, which is equivalent in size to 1150 Gulf of Mexico blocks.
So far.
We have drilled 20 prospects and it made 18 discoveries they contain approximately 9 billion barrels of recoverable oil and gas resources.
With multi billion barrels of exploration potential remaining.
Secondly to.
World Class reservoir quality with exceptional permeability prosody the results in high flow rates and high recovery factors.
Third.
Words are shallow and there was no salt.
That allows us to drill wells in a fraction of the time and cost of other deepwater basins.
Fourth.
There's a production sharing contract with a competitive cost recovery mechanism fit.
Fifth.
Development is occurring at the bottom of the offshore cost cycle excess capacity throughout the offshore supply chain greatly reduces the risk of project delays and cost overruns.
Fixed Exxon Mobil is arguably in arguably the best project manager in the World for this type of development and their operatorship greatly reduces extra execution risk and finally, it's.
Its low cost of supply.
The first three developments have industry, leading Brent breakeven prices of between 25 and $35 per barrel.
For all these reasons, Guyana will create extraordinary long term value for our shareholders and for the citizens of Guyana.
In closing I'd like to recognize our team for delivering strong results across our portfolio.
While ensuring the safety of our workforce and the communities in the midst of a pandemic pandemic and a challenging hurricane season in the Gulf of Mexico.
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 2020 to the second quarter of 2020.
We incurred a net loss of $243 million in the third quarter of 2020, compared with a net loss of $320 million in the second quarter.
Excluding items affecting comparability of earnings between periods, we incurred an adjusted net loss of $216 million in the third quarter.
Turning to S&P.
On an adjusted basis N P incurred a net loss of $156 million in the third quarter of 2020 compared to a net loss of $249 million in the previous quarter.
The changes in the after tax components of adjusted MMP results between the third quarter and the second quarter of 2020 were as follows.
Higher realized selling prices improved results by $134 million.
Higher sales volumes improved results by $33 million.
Higher exploration expenses reduced results by $40 million.
Higher cash costs, driven by production taxes reduced results by $23 million higher DDNA expense reduced results by $6 million.
All other items reduced results by $5 million for an overall increase in third quarter results of $93 million.
As John mentioned earlier, we sanctioned to pay our field development in September.
The corporations net share of development costs, excluding pre sanctioned costs and Fps. So purchase cost is forecast to be approximately $1.8 billion, which is consistent with the projections from our December 2018, Investor day presentation.
The timing of the F.P.S., so purchase is still being evaluated.
Our net share of development cost is forecast to be approximately $250 million in 2021 $450 million and 2022.
$500 million in 2023.
$300 million, and 2024 and $225 million in 2025.
Now turning to midstream.
The midstream segment had net income of $56 million in the third quarter of 2020 compared to $51 million in the previous quarter, reflecting higher throughput volumes.
Midstream EBITDA before non controlling interest amounted to $180 million in the third quarter of 2020 compared to $172 million in the previous quarter.
For corporate on an adjusted basis after tax corporate and interest expenses were $116 million in the third quarter of 2020 compared to $122 million in the previous quarter.
Turning to our financial position at quarter end, excluding midstream cash and cash equivalents were approximately $1.3 billion and our total liquidity was $4.8 billion, including available committed credit facilities, while debt and finance lease obligations totaled $6.6 billion.
Our fully undrawn $3.5 billion revolving credit facility is committed through May 2023.
Net cash provided by operating activities before changes in working capital was $468 million in the third quarter compared with $301 million in the previous quarter, primarily due to higher realized selling prices.
In the third quarter net cash provided from operating activities. After changes in working capital was $136 million compared with $266 million in the prior quarter.
Changes in working capital during the third quarter decreased cash flow from operating activities by $332 million, primarily due to a reduction in payables, reflecting reduced operating activity levels and the temporary increase in accounts receivable and inventory, resulting from our v. LCC transactions, which will reverse.
Over the next two quarters.
We have hedged over 80% of our remaining crude oil production for 2020.
September Thirtyth 2020, the fair value of open hedge contracts was approximately $205 million, while realized settlements on close contracts. During the first nine months of the year were approximately $700 million.
Proceeds from the sale of the first VLCC cargo of 2.1 million barrels of oil well received in October and proceeds from the sale of the second and third VLCC cargoes totaling 4.2 million barrels of oil are expected to be received in the first quarter of 2021.
During the fourth quarter, we expect to close on the sale of our working interest in the Shen Seafield for total consideration of $505 million with an effective date of July Onest 2020.
Proceeds from the Shanxi sale will allow us to fund our Guiana investment program in a $40 oil price environment through the start up of lease a phase II with cash cash flow from operations and cash on hand as.
As phase two comes online our operations in Guyana will begin to generate free cash flow for the corporation, even in a $40 oil price environment and depending on commodity prices at that time. The corporation will begin generating free cash flow between 2022 and 2024.
As we generate free cash flow, we plan to first reduce debt and then increase returns to shareholders.
Now turning to guidance.
First free and paid.
Our E N P cash costs were $9.86 per barrel of oil equivalent, including Libya and $9.69 per barrel of oil equivalent excluding Libya in the third quarter.
We project the N.P. cash costs, excluding Libya to be in the range of 11 to $11.50 per barrel of oil equivalent for the fourth quarter, which reflects the impact of hurricane related shutdowns in the Gulf of Mexico full.
Full year guidance is unchanged at $9.50 to $10 per barrel of oil equivalent.
DDNA expense was $16.16 per barrel of oil equivalent in the third quarter data.
DDNA expenses, excluding Libya is forecast to be in the range of $15.50 to $16 per barrel of oil equivalent for the fourth quarter and in the range of $16 to $16.50 per barrel of oil equivalent for the full year, which is in the lower end of our previous guidance range. This.
Results are projected totally into unit operating costs, excluding Libya to be in the range of $26.50 to $27.50 per barrel of oil equivalent for the fourth quarter and $25.50 to $26.50 per barrel of oil equivalent for the full year.
Exploration expenses, excluding dry hole costs are expected to be in the range of $35 million to $40 million in the fourth quarter and approximately $135 million for the full year, which is down from previous guidance of $140 million to $150 million.
We expect to recognize an additional $7 million of dry hole costs associated with the Galapagos deep wells in the fourth quarter.
The midstream tariff is projected to be approximately $240 million in the fourth quarter and approximately $945 million for the full year, which is up from previous guidance of $905 million to $930 million.
M.P. income tax expense, excluding Libya is expected to be in the range of $10 million to $15 million for the fourth quarter and $25 million to $30 million for the full year.
Our crude oil hedge positions remain unchanged, we expect that noncash option premium amortization will be approximately $95 million for the fourth quarter and approximately $280 million for the full year.
Our S&P capital and exploratory expenditures are expected to be approximately $400 million in the fourth quarter and approximately $1.8 billion for the full year, which is down from previous guidance of approximately $1.9 billion, primarily from Diana spend coming in under budget.
For midstream, we anticipate net income attributable to Hess from the midstream segment to be approximately $55 million in the fourth quarter and approximately $220 million for the full year, which is up from previous guidance of $195 million to $205 million.
For corporate.
Corporate expenses are estimated to be in the range of $30 million to $35 million for the fourth quarter and $115 million to $120 million for the full year, which is in the lower end of our previous guidance range interest expense is estimated to be approximately $95 million for the fourth quarter and approximately 375.
$5 million for the full year, which is in the lower end of our previous guidance range.
This concludes my remarks, we will be happy to 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 one on your phone.
If your question has been answered or you would like to withdraw your question press the pound key.
Questions will be taken in the order receipt.
Please press one star one to begin.
Your first question comes from the line of Doug Today with Bank of America.
Thanks, Good morning, everybody I hope Youre doing well there I'm just thank you you too.
Sean Reilly, probably is my first question John I'd like to ask you about the cash burn in the quarter, three and post working capital.
How are you thinking about the trajectory of balance sheet surety, if you like going through the end of the year, because there's obviously a lot of moving parts.
With Shenzhen the VLCC sales. So just how are you going to manage the balance sheet through the next phase of development in Guyana, given what looks like continued worsening in oil prices.
Sure Doug. Thanks for the question I guess, what I want to start with is is our cash position. So if you look at September Thirtyth, we have approximate $1.3 billion of cash and as we mentioned we have the the Shenzhen sale closing in the fourth quarter. So let me just use round numbers you can take that 1.3.
Billion and yet the shenzhou sales of 500 to it on a pro forma basis. It gets you up to about $1.8 billion of cash.
The next thing above and beyond what our cash flow from operations well be generating over the over the next couple of quarters. It is the VLCC transactions. So we have not received any of that cash right now and so we have over 6 million barrels that we will be receiving cash for as these VLCC transactions close one we've already.
Close so we have that cash in October for that the other two is as we said close around the end of the year. So we'll probably get that early next year, but if you take that 6 million barrels times current prices I'll just round it down even and say it's 200 million.
Dollars. Therefore, you go from the 1.3, plus the 500 to Shenzhen plus that 200 million, we essentially have $2 billion on a pro forma basis of cash. So that's the first thing I think you know to start with we've really put ourselves in a position with that shenzhou sales in the VLCC transactions to actually act as a hedge.
Here as we move into this next year with this low price environment.
So starting with that $2 billion. The next thing as you mentioned was just to look at our quarter and our cash flow. So.
After working capital we had that a reduction from working capital of 332 million and if I could just again use round numbers about half of that is due to the VLCC transactions. We've got receivable on the books plus the inventory builds from the crude oil going on the ships. That's just going to reverse naturally as I said over the next two key.
Orders the other thing that we have in there is a reduction of payables and it's really just reducing operating activity levels Capex is coming down all the costs are coming down as we reduce activity and now we're getting to a point, where it's stabilizing right. Our capital levels you saw for the quarter down to 331.
Really in a in in the third quarter. So we'll be stabilizing so we won't be having those polls and if prices do come back at some point and activity levels, which they will I will increase at that point, we'll actually get some inflow from working capital. It's just how it works on that activity levels come down you get a pull in when activity levels go.
Up you begin to get an inflow. So if you actually looked at our cash flow from operations, we had 468 million there and not a cash flow statement you see the outflow for capital was 426 million. So.
Except for that temporary increase it from the from the working capital, we actually exceeded our cash flow exceeded our capital and basically if you. If you didn't have that working capital I'll pull we'd be kind of at a cash flow breakeven for the quarter. So again as we move forward, we're continuing to focus on reducing capital and reducing.
Cost and doing everything we can and getting our cash balance to a point that we can withstand this low prices and like I said, we're in a position even in this low price environment to fund all the way through to phase two when we get to 60000 barrels a day approximately a brent based production coming into and generating cash flow for.
The Corporation.
So really sort of explanation as to build a number I think is is what I was really looking at it. So thank you for that.
My follow up is John This is John Hass. This is probably a bit of a curve ball really but one of your competitor companies. The other day when announcing their acquisition.
Can you talk.
Talks about a handful of investable piece and I'm glad to see that you were cited as one of them.
On a go forward basis, but my question is when you look at consolidation across the sector.
Clearly has doesn't need to do anything given guyana, but from the point of view of lowering the cost base.
So the broader industry I'm just curious what your view is on enhances participation potentially one way or the other in a in the current consolidation we seem to be undergoing right now I'll leave it there. Thanks.
Yeah, Doug obviously, our first second and third priority is to remain focused on executing our strategy, which we believe will maximize value for our shareholders. We have built a high quality and differentiated portfolio that provides a long term resource growth.
With a low cost of supply. So we already are on that trajectory for that low cost of supply, we don't need M&A to get there and it's underpinned obviously by multiple phases of Guyana oil developments and all of this together will position our company to deliver industry, leading cash flow growth over the course of the decade, obviously, we're giving some guidance now of.
Increasing our resource estimate and a guy out of the Stabroek block to approximately 9 billion barrels of oil equivalent with a potential for 10 ships not just five ships, obviously a lot of work needs to be gone to bring those forward. So we have a great a hand to provide industry, leading cash flow growth and at the same time go.
Down the cost curve, which will generate industry, leading free cash flow with the passage of time. So you know, we're always looking to optimize our portfolio, but we see nothing in the M&A market that will compete for capital against our existing portfolio of high return opportunities.
Great. Thanks again, guys. Appreciate you taking my questions.
Your next question comes from the line of.
Our on gyro with JP Morgan Chase.
Yeah. Good morning, originally I'm from from JP Morgan.
My first question really.
Revolves around pay our Greg VF and de cost came in a bit higher than buyside expectations. I was wondering if you can maybe put the budget into context around contingencies and any implications for phase four phase five f. into your capital efficiency in good.
Yeah, Yeah in terms of that guidance I suggest the John Reilly address that sure. So Rudy as you know as I said the net development costs for Hess is 1.8 billion. So when you gross that up it's approximately $6 billion, we do have contingencies in our numbers for.
That it's you know set especially fairly high contingencies early in the process.
And it comes to that $6 billion on a gross up basis and yet. The one thing you also have to add when you're doing the f. and D is the ultimate purchase cost from the S.P.S. So we did not include that in our numbers because that's still the timing of that is being evaluated and the costs gets lower as you as you move out in time. So we don't know what that is.
Exxon in its phase two release had the Fps. So at approximately 1.6 billion, that's what they disclose for phase two we expect it to be lower with synergies. So if I round that it's it's 1.5, so you get about $7.5 billion there.
And then we do have some pre sanctioned cost add and I know Exxon has got some additional contingencies beyond that but Exxon is you know, we're really happy with them as an operator, they've been performing great and it's part of that performance. They have been coming in under budget. So I, what I was saying from that the other thing that I want to add with Payor is all the costs and.
The contingencies that we have in our numbers in the pre sanction costs and the expected Sps. So cost is in that calculation for the $32. Brent breakeven. So this truly is a world class asset and adds to obviously that will be the third project in Guyana.
And we're looking forward to doing the next project after that we'll looks like it's going to be the greater yellowtail area based on early.
Drilling a size that we see there we actually expect those costs to be at a lower than payor and probably the breakeven therefore will come between 25 and $32 for the for the greater Yellowtail area.
Great. That's great color my follow up Jon is if you could give us some color you touched upon this in your prepared remarks on the F.P.S. cell related Capex I believe the consortium did leased the destiny for 10 years with the 10 year option, but you do have the approach.
Just option, which I believe last for up to two years. So I was wondering if you could provide the current thoughts on exercising the option and are you anticipating some of the F.P.S. so related capex to be incurred in 2021.
Okay. So at our at the current date right now and Exxon on behalf of the of the group is discussing with SBM. The date, the timing of purchasing all the fpsos and that would be Lisa phase one phase two and payor. So as of right now we do not expect any cost for purchased.
Cost poor Liza phase one in 2021.
But again the timing Unfortunately, and I can't really go much beyond that that timing is still being discussed and.
Part of the discussion is is moving out some of the timing of the purchase of those F. dsos, but nothing has been decided at this point, but right now for 2021. It is not expected to have any purchase costs in it.
And is it fair to say that the net the Hess that the purchase costs under destiny would be around 250 million just not to the Hess.
Okay. So depending on timing it can vary that earlier on it could be somewhere closer to 300 still under 300 and then it will decrease as you move out in time.
Great. Thanks, a lot.
Welcome. Thank you.
Thank you and our next question comes from the line of Brian singer with Goldman Sachs.
Thank you good morning.
Brian My first topic is the if Guyana with regards to the 9 billion via we approximate estimate for discovered resource and then also I think you mentioned do it.
Believed that that can support up to 10, Sps. So just a couple of questions. There number one given that there is no longer the greater then or the plus sign there can you just remind us what's in that and not in that relative to the recent discoveries you made some comments that it seems like yellowtail and redtail have been updated but is there anything that's not in that and have there.
Any downward revisions to any of the any of the past discoveries within that approximately 9 billion BOE number and then as it relates to that up to 10 Fps. So how should we think about a peak oil production number is it as easy as 180 times, one plus up to 220 times nine or when do you expect some fps as to be in decline when later.
Developments are brought online.
Fair enough, Greg do you want to tackle the resource number and what really what was behind that yeah. So that the upgrade from the the greater to eight greater than eight to nine really reflected the results of the drilling remember in war room Yellowtail, two and retail one.
So a good portion of the results of that Uh huh.
Were included in that billion barrel call. It you know.
Resource upgrade so that brings us close to being up to date, there's obviously some additional upside to that number we'll we'll figure out with further testing and potential appraisal in and around that area. So there is more upside coming.
On top of that number but that really reflects the results of those three wells.
And to your question on the 10 10 at the end. So it was again as John said in his opening or a remark.
You know that we still have to do a lot of engineering work on those paying their P.S. those but I think a this regular cadence of one a year you could assume.
And then and obviously as you get further out in time so.
Some of those earlier appeal so it could be in decline. However, remember, we still have multi billion barrels upside that hasn't been explored or appraised.
So how all that kind of works out and works as always fillers new hubs.
As yet to be determined then I think.
Furthermore, Brian if you think about the San Antonio and.
You know that remember the San Antonio and 3000 feet deeper.
In the campaign in the currently represents that 9 billion barrels.
And if you look at it on seismic.
The extent of the channel systems is as expensive or more expensive than the campaigning.
And the industry has got five penetrations in it too on state broken and three answer and I am obviously on Apache's block.
So you know that will be.
A subject of a lot of exploration appraisal drilling over the next couple of years and depending on how that turns out.
You know the San Antonio and also as well as multi billion barrels remaining upside in that campaign and all of that could be used as both always fillers and new hub class developments. So you know I always like to say Guyana is a story that's going to go on more than 10 years.
Because of that multi billion barrels of upside and we haven't even scratched the surface of the San Antonio and yet and we're in the early innings in the campaigning still.
And and you know obviously, great Greg gave great contacts and Brian obviously, we want to our investors to know there's still tremendous potential here as Greg is talking about but a lot more work needs to be done in terms of exploration and appraisal to inform you know the specifics of.
The size of the ships the timing of the ship, but generally speaking you know one of your as a good a good Uh huh.
Estimates, so think about but the most important thing is you know we need to work with the government and we need to work with our partners. So it's still early days, but we want people to realize you know in 2018 I.
I think the resource estimate was 4 billion barrels of oil equivalent and that's when we talked at least five ships and a at least a 750000 barrels a day. So we wanted investors to get an update of what the potential a number of ships could be based upon the resource upgrade that we're giving so you know.
A lot more work needs to be done, but it's obviously very exciting.
That's great. Thank you for that color my follow up is on more of the financial side can you just talk about any updates to how you're thinking about either maintenance capital or 2021 capital plans and and then in the context of some of the balance sheet questions and free cash flow discussion earlier, how you think about the hedging versus not.
Moving into next year.
Sure. So let me start with the capital what we see now I mean, obviously, we're still going through our budget process and we'll give our final guidance on our January call, but we see 2021 capital being comparable to to 2020 as we move forward and basically you have.
Backing because we went from six rigs to one their capital coming down and then with top priorities sanction, adding some additional rigs next year for development and exploration that Guy and his capital is going up so those are the two big movements.
Movements, but we see it as being comparable right I I get asked a lot on.
With the lower capital you know, 40% down this year these maintenance capital levels and there it is not actually because.
What happens from from our standpoint, if we stay at one rig there will be some declines in the Bakken and if we don't do tie back wells in the Gulf of Mexico, We will get some decline there but.
But this is the uniqueness of of Guyana right. When we bring on phase two it's it's again approximately 60000 barrels a day Brent equivalent type pricing for that production. So we're picking up 60000 barrels a day, there that offsets to declines in Bakken and Gulf of Mexico, and you have pay our 2024 and then.
As as both John and Greg, we're saying, what we're kind of on pace for one a year. He should go after that so we can continue to actually grow at these lower capital levels.
Golf at Southeast Asia stays flat at that 150 to 200 million type level of capital. So we can have that about 65000 barrels a day, so actually our maintenance capital levels would be you know a good bit lower than where we are at this at this lower level. So again, its uniqueness, where we can we can grow and it's just because guyana.
As returns and the profile of it are so good that we can grow and generate free cash flow because of the low cost nature of these developments the low breakeven.
Oh, sorry, I think you did you had one other question about hedging so just to get to your hedging question. So obviously, we continue to have the 130000 barrels a day of put options at 55 W.T.I. for the remainder of 2020, and we have 20000 barrels a day of our.
Brent put options at $60 for remainder of 2020.
So as we move into 2021, we clearly would like to put on a hedge and put some insurance to put a floor on for next year, because we are still investing with this guy and a.
Phase two coming on and you know in early 2022, so we'd like to put a floor on now the great hedge position that we have for this year. The Shenzhen sales. The Vlccs I told you have put us in a good position going into it. So there's no rush for us to have to get hedges on right now we'd like to use put options to get the full in.
Sure, it's which obviously paid off.
This year put options you know our expenses due to the time value of money if you're further away from that period, you wanted to hedge and then obviously you know where volatility is right now in the market. So you will see us hedge it could be you know later this year it could be early in 2021, but you should look for us to put on a kind of a significant again.
In insurance position for a floor for us next year.
Great. Thank you for that detail.
Thank you and our next question comes from the line of Jeanine Wai with Barclays.
Hi, Good morning, everyone. Thanks for taking my questions. This is Janine way.
Morning, Ginny good morning, and it can go.
Diana that that's not my question is on in terms of the pad development costs I know you've touched on this already and we know that the aerial extent, it's a little larger than the prior development, which is contributing to the cost but higher also has my resource and I think I heard you mentioned earlier in the queue in a way that the next phase is likely to be lower on the breaking.
Even so I was just wondering can you provide a little more color on this lower breakeven maybe in terms of all the different moving pieces can.
Can you discuss how the payer development compared to feature development phases in terms of size and probably scope.
Yeah, I think Greg you know just hitting yellowtail both in terms of the thickness aerial extent than you know what we've seen with red tail as well just to give the context you know we can't be more specific than that now we still got the DST to go on Red tail, but you know we're relatively optimistic about the economic attractiveness of that being the next.
Sure.
Sure you know I think what you know what the yellow tail and the red till wells.
Both showed remember right red tail was only a mile and a half from the from the yellowtail well.
Is that the reservoir or expand it's very large it's larger than we thought.
I'm just based on the results of the Yellowtail one.
So there's a huge resource base there we know that the reservoir quality is very similar to the Allstate Liza two and also the crude quality is leaves alike.
And so.
You know very bigger tanks bigger reservoirs in and around that greater yellowtail area and.
That's why John had mentioned it will likely have a lower development costs. It looks like you will probably need.
Fewer wells to get the same amount of resource. However, I will say, we've still got engineering work to do you know we've got to get through our various gates on our development process can be further definitive about that but also because of the nature of the PSC, you'll have more barrels on which affects the rate of cost recovery, which will also.
Tend to drive that breakeven on a lower.
But I think as you look at the reservoir of yellowtail versus buyer, it's big it's very big.
Okay, great. Thank you very much and I hope everyone is doing well there. Thanks.
Thank you you too.
Your next question comes from the line of Ryan Todd with Siemens Energy.
Great. Thanks.
Maybe if we started out in the Bakken and the button production continue to exceed expectations. The congrats on hitting the 200000 barrels that they target early.
I know you've said the one rig isn't enough to hold production flat declines, but given the continued outperformance can you give us an idea of how you think about maybe an update on how you think about exit rate declines.
2021 versus 2020 or going forward from here.
Yeah, Greg.
Yeah. We're still you know we're in the throes of of our development plan right now for next year.
So I want to give you guidance in January like we always do on the Bakken I think that would be more appropriate.
Right I mean, its development as we speak.
They maybe with that do you still have ducs to.
To work down or or will.
Sales and and.
Well drilled to be at a similar level next year no.
No. We don't really we don't carry a large DUC inventory, particularly with one rig.
You know we did in the first part of the year because remember we had six rigs that built in inventory that will effectively be worked off during the fourth quarter.
And it'll be then it'll just be normal work in process right now so.
So there won't be there won't be a DUC inventories so to speak other than wells waiting on completion crew.
And Greg maybe just to provide some context for Ryan you might remind everyone. What the role of the Bakken is and the portfolio and that takes precedence over what the rig rate is or what the production rate is and that sort of thing.
And then also you know it takes about two to keep production flat it might just remind people of that sure that we're working on final guidance for a quarter from now.
You know it would take it as John mentioned, let me start with you know what it would take hold the Bakken flat take two rigs to hold it flat broadly in the 180000 barrel a day range with two rigs we can hold it at that level, but I think you know as John mentioned important context for the Buck and the role of the Buck.
And in the portfolio now.
He is to be a cash generator.
And so the rig count will be a function of obviously oil price, but also corporate cash flow needs that is what will govern you know the rate at which you know we develop the Bakken now in order to maintain that you know magnificent magnificent catch fire power that the Buck.
And have you.
No.
Obviously, we would like to at least hold it flat right. So it doesn't decline away and you lose some of that catch fire power capability as we as I said in my opening remarks, though.
We won't consider adding that second rig to hold it flat until W.T.I. pro price.
Prices approached $50 at that point, we would look at where we are and we make an informed decision on whether to add that second rig.
But the Bakken.
Again, its primary role is cash.
Yeah, it's not the growth engine guyan as the growth engine. It will be the cash engine and of course, we could grow it as oil prices improve.
Thanks, I guess, maybe the that the natural follow up.
Or transition to follow up on the Gulf of Mexico is I think as you are.
Our lives a similar role in the portfolio as a as a as a cash cow underpinning the development can.
Can you maybe talk a little bit more about the decision to sell your stake. In addition to the field is that just opportunistically, helping you to.
Bridge, the pull forward that cash flow to bridge the gap.
Hi are starting to the phase two started up.
John any any any change I guess and how you think about the use of that asset or no does it to be clear the Gulf of Mexico is a core a focus area for the company and it will be for the future, but we did have a unique opportunity to monetize shenzhou John Reilly can provide some background sure. So just to reiterate our AR.
Off of Mexico strategy has not changed with the Shenzhou sale, Sean said its core part of our portfolio. We plan to pursue both in sales tieback opportunities to our existing hubs as well as hub class exploration as oil prices recover. So again, it really does remain unchanged with.
This shenzhou sale with BHP being the operator, we're able to get a price for Shenzhen that met our value expectations. You know so therefore, the sale fit well with our strategy to preserve cash and the long term value of our assets in this current low oil price environment and then as I mentioned you know the proceeds there add to our kind of 1.3.
Billion dollar so we already have on the balance sheet and we can use it to fund our investment opportunities in Guyana, and we will use our cash on hand, and cash flow from operations to fund Guy and all the way through to phase two where we get a step up in cash flow when phase two comes online.
Great. Thank you.
And our next question comes from the line of.
Bob Brackett with Bernstein research.
Hi, Good morning number of my questions have been asked already so I'll just throw one out around live yeah, we're seeing the country as a whole gets back to export in volumes.
What do you think about that in terms of the Hess portfolio.
Well, Bob you know the Libya is a cash engine when it's producing given that the NRC is just lifted the force majeure restrictions and the country has agreed to a cease fire.
The Assuta Port has now reopened and initial Liftings have started.
But it still remains to be seen what a normalized level of production in Libya is going to be given the uncertainties and continued political unrest.
So you know obviously when we get cash from it we're happy to do that.
But at the same time, you know its not at a point, where it's stabilized would it could be in our numbers on an ongoing basis.
Thank you for that.
Sure sure.
Your next question comes from the line of Paul Chang with Scotia Bank.
Thank you good morning morning.
Good morning.
The first question, yes, actually I think either for John or quake, or maybe fall I'm I'm trying to have a better understanding if I look at least to get my recollection correct there.
Total development cost is about $6 billion, that's including the P.S. So a 1.6, so called get 4.4 billion and the total capacity is 224 that P.S. So so in paraiba. We also looking for to 20, so one would have thought.
Of course will be lower than these two as you get more experience in developing there. So quick and John can you help me understand a little bit what how that these signed me change and white audience of having a lower cost is actually become how are you.
Yeah, Hi, John.
Sure. So let me just start with they like each development is unique Paul so like as I mentioned, the greater yellowtail area, we see that with lower development costs in a breakeven that drops you know between 25 and $32 at that point with Pi Arpine at $32.
So the difference we are getting synergies like you said for the building of the Fps. So because we do expect that to come in at a lower cost so with pay our as compared to Liza phase two and I always have to remind everybody and I know I'm not objective all when I say this but Lisa phase two with Brent breakeven of $25.
Hi, This is arguably the best project that is out there in the industry. So we are comparing things to this you know really tough project and pay our is world class. So it it does cost more and why what it what happens is Pandora has a greater number of distinct reservoirs and therefore also at greater air.
Ill extent so it was always as we said it was back in our December 2018, Investor presentation. It was always going to have a higher cost than lease a phase two so.
So those costs now came exactly in with what we were expecting yeah, just the aerial extent of the reservoirs cause more wells to be there some more flow lines to be there and that's what causes that cost to be there and the Brent breakeven going to 32 versus the 25 now again yellowtail, we expect that.
To be lower because I think the reservoirs the individual reservoirs as Greg mentioned I have I have a great aerial extent on on its own. Therefore, we believe the cost will be lower in the Brent breakeven between 25 and 32.
Thank you I have one quick that when onea, you're talking about the gas injection system yet the mechanical you. So you said the saipem on that what's causing that mechanical problem, yet, but there were two issues. Paul. So first was the cooling fan blades on the on the big.
Gas compressors and that that was a design issue for sure.
Those were Reengineered, new fan blades installed in both of those compressors are currently operating and that's why our.
Our production now is averaged about 105000 barrels a day for the last couple of weeks. So things are things are back on track.
For the main gas compressors, the last pieces of flash gas compressor.
And there was a failure in the lube oil system that is a design related issue and that compressor is back in Germany.
Being retrofitted as we speak and the plan is to get it out of the platform.
<unk> or the <unk>. So during the month of November and then begin to ramp up to the full nameplate in December. So both were design issues I think you know.
I've said before Paul but.
The silver lining and all this to me is in this design one build many strategy all of the learnings that are coming out of this are being incorporated into future phases. So that will over time just continue to increase.
The reliability and an ability to bring these on these vessels.
On flawlessly.
Okay. Thank you and just a quick one Gulf of Mexico in the quarter, how how much is the hurricane impact and also John John Bonn, The international ex the unit cost one is so high in the third quarter.
Sure. So let me start with the Gulf of Mexico in the in the third quarter. So between maintenance shutdowns that we already have we're undergoing at lotto and conquer because shell is working on the enchilada auger platforms, so with that maintenance shutdowns and the hurricane downtime. It was approximately 19000.
And barrels a day of an impact in the third quarter and then you heard from as in Greg's script. There that so fourth quarter is going to be about 25000. So what's really happening again is llano when Congress continuing now with the shutdown due to the hurricane damage that was incurred to bid.
This difference then between the third and fourth quarter, though is that Penn state well that Greg mentioned, so that is going to be down for basically most of the quarter not coming back till the end of December. So that's what takes the 19 to 25 in Q4 and then the international cost that you saw what you have to.
Do is take out $8 million associated with the severance charge. So of that 27 million special severance charge 8 million of it was over on the international side.
Thank you.
You're welcome.
And your next question comes from the line of David Heikkinen with Heikkinen energy.
Good morning, guys. Thanks for taking my question just a couple of quick questions. The.
Your first of all I'm tied tour what is what do you expect the.
Well costs to be.
John.
So this one this well as Greg has mentioned is is going to be more expensive than our typical wells that we've been drilling from an exploration stage standpoint on stabroek. So because it is one going deeper we are using managed pressure drilling on this just to be careful as we drill all the way down.
Down onto the deeper sections, as Greg mentioned going San Antonio and Turonian. So Exxon has not put out an estimate on this right now, but it will take longer and its going to generally cost a bit more and just remember that we do have a lesser though working interest in Chi tour that we do stable.
Okay and then.
Given all the recovery of volumes in the Gulf of Mexico, do you have a feel for a run rate going into 2021.
With all the moving pieces, the 19 backs plus I guess Penn state.
Gets you back to your earlier this year right.
Well I guess, yes volumes.
Yes, sure. So I mean, basically what we in the Gulf of Mexico full year, when we incorporate shut downs and things like that as approximately we were saying 65000 barrels a day I mean, it can be higher than that when you. When you don't have shut down some quarters. So we will get back on that run rate except for the shenzhou sales right. So you know you had 11000 barrels being sold so.
Basically take it down to approximately 55000 barrels a day that on a run rate when everything we coming back starting in January onest.
Perfect and with the design one build many concepts it looks like you've ordered the same basic compressor kit that you will just put side by side on the additional Sps. So all the kinks that you're working out with.
Phase one really do hopefully will be avoided at least with the same kit is that is that correct or it doesn't you.
Greg alluding, yeah, absolutely, Dave and in fact, the if you look at the park numbers and this is extreme standardization. If you look at the part numbers I think it's something like 85% of the park numbers on the top side or the same in phase two and phase one.
Well, that's that's what I think the real advantage of standardization is as you can just quickly ruled learnings you know in the future phases in really a really drive very high reliability and these vessels as a result than that.
Yeah, Yeah, so a lot of learnings and this first six months that'll that'll stabilize things and less downtime as you move forward. That's helpful color and thank you all.
Thank you all right.
Thank you.
Next question comes from the line of Roger read with Wells Fargo.
Yeah. Thanks, good morning, Mark.
Good morning.
Well just curious kind of your opening comments, where you said you expect to get to sub $40 in terms of total development as we get to the middle of the decade.
Is that solely rely on what you're going to do again Guiana or is that also envisioning some additional asset sales down the road thinking.
The opportunity, obviously that popped up on shenzhou, but if there's anything else planned in there.
No. There is nothing else planned and now with our current portfolio and it really is as these f. FIA sales in Guyana come online as we spoke about you know phase two being a 25 dollar breakeven I are a 32 yellow tail being 25 and 32 as these f. dsos get brought online it drives down.
Our overall breakeven in the portfolio to below $40.
Okay. The other question to follow up on as you think about 21, you talk about running the one rig in the Bakken side, you mentioned well costs have gone under 6 million there any thoughts on inflation deflation as you look at activity in the Bakken in 21, as you're thinking about your cap.
Ex budget.
Greg.
No I think you know, we're we're not really assuming any any inflation whatsoever next year in the Bakken you know things are still well over supplied.
We already have contracts locked in with their strategic suppliers for that now they do have some market based adjustments if the market does improve but I think the important thing is you know through technology and innovation will still drive that cost lower no matter what.
Okay, great. Thank you.
Your next question comes from the line of Pablo Bulking up with Raymond James.
Thanks for taking the question.
Both of my questions are related to cold it the first one in Malaysia, it's having a a very serious outbreak that just emerged in the last 30 days. Since you are one of the few international operators there.
I would ask what the what the status is and how you're coping.
With that I hadn't outbreak.
Yeah, Greg you might talk about the field as well as the officer.
So remember during the first outbreak coded.
You know there were essentially no impacts to the operation side, you know logistically you had to get people quarantine and deaths ignore that but we worked all that out so.
We really didnt skip a beat on the operating side and I remember, Malaysia is a very active area for us we have ongoing drilling programs ongoing.
Projects, so very active and we saw no impact as a result of co bid based on the on the protocols that we developed if you look at the office.
Again during the first outbreak everyone was working remotely.
We got up to about 80% complement back in our office and now we've taken that back down again, so people would just go back to working remotely.
I think it all with you know we've seen no impact to the operations or to our ability to work in Malaysia. It has resulted in lower nominations, which is why we kept our or guidance for the fourth quarter for Malaysia at 50000 barrels equivalent just because of those coven uncertainties in the second outbreak.
Okay. Similar question about beyond originally the timetable for reaching.
Well capacity or plateau, what was August now you're you're the.
Next on of course talking about December how much have kind of social distancing restrictions or labor availability related coded.
I've had with that four month delay.
Yeah, Greg obviously, it impacted repairs, but go ahead, yeah, no I think you know it it's on the margins I would say I mean really the.
You know the design issues that I talked about you know where the where the primary reason. However, you know as Exxon has very strict protocols, which I think are absolutely appropriate.
So anyone before they go off shore asked to self quarantine in country for 14 days and be tested so.
So obviously any special work are.
That needs to be done, it's going to take a little bit longer, but I will complement exon mobil.
Fuse lead because they've had some 2500 crew change events.
And so for touch would have had no covert cases offshore so I think what's going on there is absolutely remarkable.
In terms of how how will all that's being executed amidst a pandemic.
Thanks very much.
Thank you very much. This concludes today's conference. Thank you for your participation you may now disconnect have a great day.
[music].