Q3 2019 Earnings Call
Good day, ladies and gentlemen, and welcome to the third quarter 2019, Hess Corporation Conference call. My name is Andrew and I'll be your operator for today.
This time, all participants are in listen only mode.
Later, we'll conduct a question and answer session. If at any time you require operators distance. Please press star followed by zero and we'll be happy to assist you.
As a reminder, this conference is being recorded for replay purposes.
I would now let's 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 Www Dot has 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 assesses annual and quarterly reports filed with the FCC.
Also on todays 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.
Now as usual with me today or John Hester, Chief Executive Officer, Greg Hill, Chief Operating Officer, John Riley Chief Financial Officer, I'll now turn the color to Josh. Thank you Jay welcome to our third quarter Conference call I will provide a strategy update then Greg Hill will discuss our operating performance and John Wiley will review.
Our financial results.
We continue to execute our strategy of disciplined capital allocation.
Focusing only on low cost high return opportunities, we had another strong quarter, delivering higher production and lower capital exploratory expenditures than our previous guidance.
Our portfolio with Guyana, and the Bakken as our growth engines, and Malaysia, and the deepwater Gulf of Mexico was our cash engines is on track to deliver industry, leading performance in terms of financial returns cash flow growth and a portfolio break even below $40 per barrel Brent by 2025.
A key part of our strategy is maintaining a strong balance sheet and liquidity position with $1.9 billion of cash on our balance sheet at the ended the quarter. We are in a strong financial position to fund our high return growth projects across a range of prices.
As a result of strong execution throughout our portfolio, we have reduced our full year 2019 capital on exploratory expenditure guidance by a further $100 million to $2.7 billion.
Earlier this month Hess Midstream partners announced plans to convert to an up see structure and acquire Hess infrastructure partners, including its oil and gas midstream interests water services business outstanding economic general partner interest and incentive distribution rights in Hess Midstream partners.
Upon completion of this transaction, which is expected in the fourth quarter Hess Corporation will receive approximately $275 billion in cash and will own approximately 134 million units or 47% of the new Hess midstream consolidated entity valued net to has said approximately 2.85.
$5 billion as of last night's close cash proceeds will be used to fund our world class investments in Guyana, and the Bakken, where we plan to invest more than 75% of our capital expenditures over the next five years.
Turning to Guyana on the Stabroek block, where Hess has a 30% interest and Exxon Mobil is the operator gross discovered recoverable resources are estimated at more than 6 billion barrels of oil equivalent with multi billion barrels of future exploration potential remaining.
In September we announced a 14th discovery on the block at the Triple tail, one well located in the turbo area approximately three miles northeast up long tail discovery.
Well encountered approximately 108 feet of a high quality oil bearing sandstone reservoirs subsequently additional hydrocarbon bearing reservoirs have been encountered below the previously announced triple tail discovery.
Triple tail is still under evaluation and will further underpinned the turbo area as a major development hub.
During the quarter drilling an appraisal activities were completed that hammerhead with encouraging results, including the successful drill stem test.
These results are being evaluated for potential future development also drilling in evaluation activities continue on the range or two well with the objective of appraising the range or oil discovery.
In terms of our developments the lease a phase one development is now targeted to start up in December and will produce up to 120000 gross barrels of oil per day utilizing the Lisa destiny floating production storage and all floating vessel or Fps, So which arrived in Guyana on August 29.
The Lisa Phase two development is also progressing to plan and we'll use the second half P.S. So the Lisa unity with a gross production capacity of 220000 barrels of oil per day first oil is expected by mid 2022.
Planning is underway for a third development at par Yara, which will use and Fps. So with gross production capacity of 220000 barrels oil per day and first production from PR is expected in 2023.
We're also seeing positive results from our focused exploration program in the deepwater Gulf of Mexico, where we have acquired 60 blocks over the past five years for approximately $120 million to pursue high return infrastructure led and hub class prospects.
Yesterday, we announced a successful oil discovery at the Sox, one exploration well in Mississippi Canyon, which encountered approximately 191 feed of net pay in high quality oil bearing Miocene reservoir has since the operator in holds a 57.14% interest.
We expect to commence production in the first quarter 2020, you Sox will be a low cost high back to the tubular bells production facilities and is expected to generate strong financial returns.
We also plan to spud the Oldfield well by the end of the year Kosmos is the operator and has as a 60% interest in this prospect, which is located approximately six miles east of the East Sox one well.
Moving to the Bakken our transition to plug and perf completions has been very successful and we are seeing the expected uplift in initial production rates in estimated ultimate recovery and most importantly in value.
Net production in the Bakken is on track to reach approximately 200000 barrels of oil equivalent per day by 2021.
We then plan to reduce our current six rig program to four rigs, which will enable us to maintain production of approximately 200000 barrels oil equivalent per day, resulting in material free cash flow generation across a range of prices.
Now turning to our financial results in the third quarter, we posted a net loss of $205 billion or 68 cents per share compared to a net loss of $42 million or 18 cents per share in a year ago quarter on an adjusted basis, we posted a net loss of $98 million or 32 cents per share compared with adjusted net.
Income of $29 million or six cents per share in the third quarter of 2018.
Compared to our third quarter 2018, our financial results, primarily reflect lower realized selling prices, which were partially offset by reduced exploration expenses.
Third quarter net production averaged 290000 barrels of oil equivalent per day, excluding Libya up from 279000 barrels of oil equivalent per day in the year ago quarter for the full year 2019, we're raising our guidance for net production to approximately 285000 barrels of oil equivalent per day, excluding Libya.
Up from our previous guidance range of 275000 280000 barrels of oil equivalent per day.
Third quarter net production in the Bakken averaged 163000 barrels of oil equivalent per day up 38% from 118000 barrels of oil equivalent per day, a year ago for the full year 2019, we're raising our guidance for the Bakken net production to approximately 150000 barrels of oil equivalent per day.
<unk> up from our previous guidance range of 140000 to 145000 barrels of oil equivalent per day.
In summary, our strategy of disciplined capital allocation and a focus portfolio of assets is achieving positive results and uniquely positions our company to deliver increasing and strong financial returns visible on low risk production growth and significant free cash flow I will now turn the call over to Greg for an operational.
Uptake.
Thanks, John I'd like to provide an update on or progress in 2019, as we continue to execute our strategy.
Starting with production in the third quarter net production averaged 290000 barrels oil equivalent per day, excluding Libya.
Which was above our guidance range for the quarter of 270000 to 280000 barrels of oil equivalent per day.
Based on this strong year to date performance, we're increasing our full year 2019, net production production guidance, excluding Libya to approximately 285000 barrels of oil equivalent per day.
Paired to our previous guidance range of 275000 280000 barrels of oil equivalent per day.
We expect fourth quarter production to average approximately 300000 barrels of oil equivalent per day on the same basis.
In the Bakken.
Third quarter net production averaged 163000 barrels of oil equivalent per day significantly above our guidance range.
145000, 250000 barrels oil equivalent per day in nearly 40% higher than the year ago quarter.
Bare did the second quarter.
Oil production was up by 12% as a result of continuing strong performance from our plug and perf completions.
Natural gas and NGL volumes were also higher in the third quarter.
As a result of increase gas capture from the startup of the little Missouri for gas plant in late July .
And the decline in NGL prices during the quarter, which increased our entitlement from gas processing contracts.
Operating under percentage of proceeds agreements in the Bakken.
During the third quarter, we brought 33, new wells online and over the fourth quarter. We now expect to bring online between 55 and 60 new wells.
For the full year 2019, we expect to bring online approximately 155, new wells, which is slightly below our original guidance of 160 wells, primarily due to weather related issues earlier this year.
For full year, 2019, with stronger well performance more than offsetting fewer new wells coming online.
We now forecast Bakken net production will average approximately 150000 barrels of oil equivalent per day.
Compared to our previous guidance range of 140000, the 145000 barrels of oil equivalent per day.
In the fourth quarter.
Bakken production is expected to average approximately 165000 barrels of oil equivalent per day.
This modest increase from a third quarter reflects a backend loaded completions program contingency for winter weather and our expectation for seasonally higher NGL prices, which may reduce our entitlement from percentage of proceeds contracts.
In the third quarter or average drilling and completion costs were $6.7 million per well down 8% from 7.3 million in the first quarter.
Through the continued application of lean manufacturing, we expect to achieve further cost reductions as we progress towards our targeted drilling and completion costs of $6 million per well.
Overall, we remain firmly on track to deliver net production of 200000 barrels oil equivalent per day by 2021, while continuing to drive down well costs.
Now moving through the offshore.
In the deepwater Gulf of Mexico, net production averaged 59000 barrels of oil equivalent per day in the third quarter, reflecting planned maintenance and downtime associated with Hurricane Barry in July which reduced third quarter net production by approximately 6000 barrels of oil equivalent per day the guy.
Gradual ramp up of the Llano five wells in which half has a 50% working interest has been underway since July when the well with first brought on production.
Well as approaching its peak rate with current production at approximately 8000 net barrels of oil equivalent per day.
Our infrastructure led to exploration in the Gulf of Mexico is also proving successful.
Yesterday, we announced an oil discovery at the Hess operated E. Socs, one exploration well in which helps holds a 57.14% interest.
Well encountered approximately 191 feet of net pay and high quality light oil bearing Miocene aged reservoir.
Planning is now underway to tie back to dwell into an existing slot at the tubular bells production facility during the first quarter of 2020.
We also plan to spud another infrared infrastructure led exploration well by year end on the Oldfield prospect approximately six miles east of the Sox, one in which Kosmos is the operator and half has a 60% interest.
Turning to southeast Asian, net production averaged 60000 barrels oil equivalent per day in the third quarter, reflecting the completion of a successful two week planned shut down for maintenance activities at the joint development area.
Now turning to Guyana, where exploration success on the Stabroek block continues and development activities are progressing to plan.
Last month, we announced in the oil discovery at the Triple tail, one well located in the turbot area approximately three miles northeast of long tail discovery.
People tail one is our fourth discovery in 2019 and brings the total number of discoveries on the block to date to 14.
The well was drilled and 6572 feet, a water and encountered approximately 108 feet of high quality oil bearing sandstone reservoirs.
Drilling operations and evaluation are ongoing with additional hydrocarbon bearing reservoirs encountered below the previously announced discovery.
Following completion of activities at Triple tail.
The noble Tom Madden Drillship will next drill the walk through one prospect located approximately 10 miles east of the Liza one well.
Also on the block the Stena, Karen Drillship is currently conducting well operations on the range or two appraisal well, which includes an extensive logging in coring program.
Following range or to the rig will move to the previously announced yellowtail, one discovery to conduct a production test.
A fourth drillship noble Don Taylor is expected deriving Guyana November and we'll drill them May go one exploration well located approximately six miles south of the Liza one well.
Turning to our Guyana developments Liza Phase one project is now targeted to achieved first oil in December .
The Liza Destiny, Fps, so where the gross production capacity of 120000 barrels of oil per day.
Rivaling Guyana on August 29.
Drilling of the Liza Phase one development wells by the noble Bob Dogus Drillship is proceeding to plan and sub sea installation is nearly complete.
Liza phase II sanctioned in May of this year will utilize the Liza unit, the FPSO, which will have a gross production capacity of 220000 barrels of oil per day and will develop approximately 600 million barrels of oil.
The whole is nearing completion and is expected to sale to the capital yard in Singapore by year end, where the topside modules will be installed and the vessel Commission development drilling of leads the phase two will commence in the first quarter of 2020 with first oil expected by mid 2022.
Pending government approvals a third development Ampyra is planned to utilizing the FPSO with a gross production capacity of 220000 barrels of oil per day and is expected to achieved first oil in 2023.
In closing our execution continues to be strong in 2019, we're on track to deliver higher production on lower capital and explore Tory expenditures than previously guided.
Our offshore cash engines continued to generate significant free cash flow.
The Bakken is on a strong capital efficient growth trajectory, our Gulf of Mexico exploration program is proving to be successful and Guyana continues to get bigger and better all of which position us to deliver industry, leading returns material free cash flow generation and significant shareholder value.
I'll now turn the call over to John Riley.
Thanks, Greg in my remarks today, I will compare results from the third quarter of 2019 to the second quarter of 2019.
We incurred a net loss of $205 million in the third quarter of 2019 compared to a net loss of $6 million in the second quarter 2019.
On an adjusted basis, which excludes items affecting comparability of earnings between periods, we incurred a net loss of $98 million into third quarter of 2019 compared to a net loss of $28 million in the previous quarter.
Turning to GNP.
On adjusted basis, DNP incurred a net loss of $34 million third quarter of 2019 compared to net income of $46 million in the previous quarter.
The changes in the after tax components of adjusted NP results between the third quarter and second quarter of 2019 were as follows.
Higher sales volumes increased results by $63 million.
Lower realized selling prices decrease results by $66 million.
Higher DDNA expense decreased results by $48 million higher cash cost decrease results by $24 million. All other items decrease results by $5 million for an overall decrease in third quarter results of $80 million.
Turning to midstream to midstream segment had net income of $39 million in the third quarter of 2019 compared to $35 million in the second quarter of 2019.
Midstream EBITDA before non controlling interest amounted to $133 million in the third quarter 2019, compared to $127 million in the previous quarter.
Turning to corporate.
On an adjusted basis after tax corporate and interest expenses were $103 million into third quarter of 2019 compared to $109 million in the previous quarter.
Now to our financial position.
At quarter end cash and cash equivalents were $1.9 billion, excluding midstream and total liquidity was $5.7 billion, including available committed credit facilities, while debt and finance lease obligations totaled $5.6 billion.
As John has mentioned, we will receive approximately $275 million in cash upon completion of Hess Midstream partners acquisition of Hess infrastructure partners, which is expected to close in the fourth quarter. This year.
In the third quarter of 2019 net cash provided from operating activities was $443 million or $543 million before changes in working capital and items affecting comparability.
Cash expenditures for investing activities were $721 million in the third quarter.
Now turning to guidance.
First for S&P in.
In the third quarter, our MP cash costs were $12.13 per barrel of oil equivalent, including Libya and $12.75 per barrel of oil equivalent, excluding Libya, which beat guidance on higher production than forecast.
We project NP cash costs, excluding Libya in the fourth quarter to be in the range of $12.50 to $13 in 50 cents per barrel of oil equivalent and full year 2019 cash costs to be unchanged at $12.50 to $13 per barrel of oil equivalent.
DDNA expense in the third quarter was $17.67 per barrel of oil equivalent, including Libya and $18.79 per barrel of oil equivalent excluding Libya.
DDNA expense, excluding Libya is forecast to be in the range of $17.50 to $18.50 per barrels oil equivalent in the fourth quarter and $18 to $18.50 per barrel of oil equivalent for the full year, which is at the lower end of previous guidance.
This results in projected total LP unit operating costs, excluding Libya to be in the range of $30 to $32 per barrel of oil equivalent for the fourth quarter and $30.50 to $31.50 per barrel of oil equivalent for the full year of 2019.
Exploration expenses, excluding dry hole costs are expected to be in the range of $70 million to $75 million in the fourth quarter with full year guidance expected to be in the range of $190 million to $195 million, which is down from previous guidance of $200 million to $210 million.
The midstream tariff is projected to be approximately $215 million for the fourth quarter and full year guidance is expected to be approximately $725 million.
The increase in fourth quarter tariff expense compared with the third quarter is due to an anticipated increase in midstream volumes driven by increasing third party throughput with the ramp up of the little Missouri for gas processing plant in North Dakota.
The effective tax rate, excluding Libya is expected to be an expense in the range of zero to 4% for the fourth quarter and for the full year.
Our crude oil hedge positions remain unchanged, we have 95000 barrels of oil per day hedged for the remainder of 2019 was $60 WT put option contracts.
We expect noncash option premium amortization to be approximately $29 million for the fourth quarter.
Full year S&P capital and exploratory expenditures are now expected to be approximately $2.7 billion down $100 million from previous guidance.
The reduced spend reflects efficiencies across the portfolio, but primarily in the Bakken, where we have reduced well costs and the number of wells expected to be completed for the year, while being on track to exceed our original production guidance for the year.
For midstream, we anticipate net income attributable to Hess from the midstream segment, excluding specials to be approximately $55 million in the fourth quarter and approximately $165 million for the full year.
For corporate for the fourth quarter of 2019 corporate expenses are estimated to be in the range of $25 million to $30 million with full year guidance unchanged at $110 million to $115 million.
Interest expense is estimated to be in the range of $75 million to $80 million for the fourth quarter with the full year guidance unchanged at 315 million to $320 million.
This concludes my remarks, we will be happy to answer any questions I will now turn the call over to the operator.
Thank you.
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 pound.
This will be taken in the order received please press star one to begin.
Your first question comes from the line of Devon Mcdermott Morgan Stanley .
Good morning, Congrats on strong results today.
Seven.
So my first question is actually on the Bakken and it's been one of the strong points in the portfolio.
Each quarter, so far this year, despite some of the weather headwinds on its bit of a two part question. The first one is one of the areas of strength on production. This quarter was on the higher gas and NGL volumes and you mentioned that part of that was a little Missouri for plant start up in part of that was the pop contracts some of which reverses into the fourth quarter. I was wondering just how you're thinking about.
That reversal, the normalized oil mix going forward and any rule of thumb and how we can think about the sensitivity around those pop contracts and then the second part of the question is stepping back as we think about this transition to plug and perf and how it's gone relative to expectations. It seems like.
The results have been beating at least the guidance that you laid out at the Investor day last year.
Strictly on the cost side, so what opportunities have you found to drive down costs, so far and what opportunities do you see going forward to further cut cost out of the system and improve returns there.
Okay. Let me take your first question so yeah, you're right.
This that really good thing the volumes in the third quarter due to higher midstream capture so the first thing I wanted to phase, it's not a reservoir issue at all.
There's no machine material change in that you are at the wellhead.
I think it's important to note that in the third quarter, we had very strong oil production growth. So it was 12% increase.
Versus the Q2 level. So the oil is doing great and as you mentioned the higher natural gas and NGL volumes amounted to about 7000 barrels a day and that was due to two things first.
First of all the increase gaps capture from the little Missouri for gas plant that came on in July and then secondly, as you mentioned that the higher gas and NGL entitlement and are under our pop contracts.
Now how those pop contracts are going to perform in the future is obviously going to be a function of NGL prices.
Seasonally in the fourth quarter, we lowered our expectations for those typically because the NGL prices are our are higher higher in the with the weather.
As we look forward I think what we can say is that we expect that the Bakken oil percentage is going to average approximately 60% low sixtys.
On a go forward basis, now one or the thing I will say is of NGL prices stay low.
There's a chance that that will actually be higher than the 200000 barrels a day as a result of additional pop volumes. So this is all a very good thing.
Now on your second question in terms of performance of the Oh, the Bakken Wells, you're right extremely pleased with the performance of the team both not only on the productivity side.
So the plug and perf is on average exactly on track with what we expected.
15% uplift in IP, when 85% uplift in the yours well on track for that but the second thing I'm really proud of the team on is their performance on the cost side recall, we started the first quarter the year at $7.3 million are well second quarter, we came in at $7 million.
Well and the third quarter, we came in at $6.7 million, a well now all of that is lean manufacturing gains primarily.
We're also doing some technology things, we ran some fiberoptic in the wells that allowed us to reduce.
Our stage count and that also led or or lower well costs now we're marching our way towards the $6 million a well.
We talked about in Investor day, and if were successful in achieving that 6 million dollar well cost is going to add a further billion dollars.
To the NPV of the Bakken, So we're well on track for productivity standpoint, and it will cost standpoint.
Great So pretty impressive improvement there and just one more if I may has actually on on the Gulf of Mexico, I think it's been a strong area the portfolio that probably doesn't get as much attention as it maybe shed and you mentioned you picked up 60, new blocks over the past few years, there and we had the Sox discovery announced yesterday and get a at a high level, how should we think about.
The Gulf of Mexico, and the rolling the portfolio going forward in terms of investment level production profile and also the cadence of exploration here over the next few quarters and into 2020.
Sure. So obviously, it's a very important part of the portfolio strong cash generation, we have outstanding capability there not only in terms of exploration, but also project delivery. So the way we think about the Gulf of Mexico is think of it as being relatively flat.
At about 65000 barrels a day over the next several years and we're confident that we can keep it at that level really through a combination of high value short cycle exploitation projects.
And infrastructure led exploration.
A couple of examples of that obviously, the llano five well, which we talked about in her opening remarks still ramping but producing a 8000 barrels of oil equivalent per day net to us.
And then in terms, while ex feedstocks, one discovery, which we're very pleased with the outcome of the well.
Hundred 91 feed of light oil bearing high quality might see reservoir exceeding our pre drill expectations.
And the thing I would say about Isa boxes. This is not your typical tie back in terms of size. This is a significant discovery.
That's going to generate very high returns and cash flow.
Particularly since its tied into that existing slot and will be brought online very quickly.
So discovery first oil as a matter of a few months.
Now the valuation of that well. The result is still ongoing and we intend to provide further updates including resource estimate production rate et cetera. Early next year. After we have some dynamic production data, but I really wanted to highlight E stocks because I think it's a great example of what we think we can do.
In the Gulf in the short term and the next well up which is similar to ease Sox is the oldfield aisle ex well.
Now beyond that.
We will need a new hub did keep it flat or grow at.
And as Weve, a cried those leases over the past five years that John mentioned in his opening remarks, we see some 25 leads and prospects in there. So we've got a fairly healthy inventory.
And you can assume rate for capital planning purposes. This would be within our long term capital plan and probably have.
Two wells a year might be infrastructure led hub class all infrastructure led all hub class, but about two shots on goal year.
Perfect. Thanks, so much.
Your next question comes from the line of Roger read with Wells Fargo.
Yeah. Thanks, good morning.
Morning.
I guess, maybe kind of answered the one other question is always going to ask a if you think about capex next year with fewer wells this year and the backend and then the Sox development do we have any thought process at this point on 2020, capex or whether maybe the bias to the upside.
With those two factors may be more wells in the Bakken as a catch up and then.
Anything in the Gulf.
No. Roger this was all part of our of our plan now we will give guidance for 2020 in January but kind of I mentioned on the last call and consistent with our Investor Day, We expect our capital exploratory spend for 2020 to be approximately 3 billion.
And it's going to be exactly what we said.
Back in that Investor day, we're only investing that high return low cost opportunities like he socs that you that you just mentioned in order to grow that free cash flow in a disciplined reliable manner, but our capital really through 2020, 575% of forward spend is going to be allocated to a world class assets in Guyana in the Bakken and everything you too.
Talked about now with wells, we do expect to be more efficient in the Bakken because as with lean will reduce the cost will get maybe more wells in 2020 versus 2019, but that's all factored into that 3 billion spend at ice that I mentioned.
Okay, Great and then.
The the commentary about the Llano five well kind of ramping up.
And looking at Kiana, starting production and December 19, what's the right way, we should think about how that field will start up I know you're not the operator.
But.
Is that a phase kind of saying, we're going to be pretty careful was to wells or there is enough understanding that we should think about those you know I think it's eight wells and total just kind of coming on and rapid succession.
No I think I think.
You should assume that three to four month ramp in production.
We'll want to get a lot of dynamic data.
Including some potential buildups along the way.
So this was all designed to slow the ramp the wells up and see what we've got going on the reservoir first first wells in the reservoir of that's non income and in deepwater to do that.
And I think another point that needs to be made is you know the production ramp up from first oil discovery to Ah production in five years is industry, leading performance and we're very proud of the job the joint ventures Dawn, specifically Exxon Mobil as our operator in bringing that forward and that's going to augur well.
For our future developments as well.
Great. Thank you ill leave it there.
Your next question comes from the line of Doug, Let's say Bank of America.
Hi, good morning, Thank you good effort.
Good morning, everybody.
I guess, John maybe I could kick also undergrad to kick off with side Guyana.
We've been on range are known for for quite Awhile.
And I just wanted me sort of not reading too much into your line is joint about difference between evaluate with the intention of appraising can you just give us.
Any early prognosis that you have currently and I guess, Greg specifically.
The thing I guess would all watching here as you were planning a flow test is on just on that.
Hi, this feeling the conclusion of crusher communication with Ranger, one because I guess, what's going to be the key thing here is whether or not you go compartmentalization hopefully we've got a viable development any anything you can share there.
A follow up please.
Yeah, Doug I mean, what what I can say is that.
On Ranger drilling in evaluation are ongoing.
As you recall, we've got a very extensive logging coring program like set around this well, but what I can say is that.
However, based on the logs in core is taken so far.
We've seen encouraging reservoir development.
Information of the of the presence of oil. So that's about all we can say at this point in time, so stay tune lot operations on going on the well.
Maybe just press you a little bit on this drug is there anything this disappointed you on manger.
Not to date.
Okay.
A follow up is also getting on a release it obviously, we're going to see.
A change in reporting here in terms of high earnings and cash flow are going to all going to flow through I'm. Just wondering joined Riley. If there's any help you can give the street in terms of how this is going to play out because you will obviously have to report tox associated with us, but as we all know there is no.
So is there any way you can.
Hi, how are you can navigate this going forward because it is going to be such a large part of the portfolio cash flow going forward because headline earnings if I'm not mistaken I'm going to be kind of over the place where does this thing comes online. So any any help you can offer and I'll leave it there. Thank you.
Shared dug in and really what what I will do is on on the January call that we give the forecast for the year. It that's when we'll give them more detailed explanations on this but you are exactly right. So the way that contract works after the cost recovery the profit oil a split for the government.
And the working interest owners and the government out of its profitable pace for the taxes of the working interest owners. So what that requires us to do is for cord attacks. So we will have a tax line associated with our guy at a production.
And then what you have is up above in revenue essentially additional barrels being recorded to offset that tax. So the revenue line up above will offset that tax line now we will lay that out as we get through the year and I get through the full forecast, we get exxon's numbers and then put it.
Together with all our numbers I'll lay out what the tax rate looks like for next year can be a little more specific about Diana, but you're exactly right whatever taxes that show up there do not affect the bottom line cash flow of from Mark I had a production.
Okay, I know, it's going to be completed by appreciate the answers. Thanks.
Your next question comes from the line of Bryan singer Goldman Sachs.
Thank you good morning.
Two Guyana bigger picture questions. The first is can you broadly speak to how you see the cost structure of future projects involving you've benefited from the dearth of international project sanctions and low oil services activity.
Now oil service companies on the margin are highlighting some inflection and international activity. How do you how do you see costs evolving for future projects the efficiency side of the equation versus the service cost outlook.
Okay.
So.
If you look at the deepwater offshore service sector.
It continues to be oversupplied, given the extended period of low activity and as you mentioned I think also the industry focus on efficiency and simplification and standardization continues to drive unit costs down. So as a result, we expect to see minimal cost inflation on that front.
Great. Thanks, and then my follow up is on the gas condensate discoveries at high Myra and Puma can you just talked about any update there on the process of determining the timing if at all of a of development and.
How you would see the rates of return there relative to the other options.
No I think you know these these reservoirs will be developed but certainly they won't be part of the first five fpsos that we've discussed.
Getting us to the 750000 barrels a day.
You know bite in 2025 so.
It will be after that.
But there they are still very good reservoirs very good fluid. So they will be developed at some point and our exploration and appraisal program that we're doing this year last of which is a triple tail, which is still under evaluation is going to give us more granularity to sort of give guidance on what the.
Fourth and fifth shipped or potentially a six ship.
In that southeast in.
Turbo hub area. So so I would think next year, we can give more clarity on the phasing of the fourth and fifth ship.
And future ships potentially thereafter.
Great. Thank you.
Your next question comes from the line of Bob Brackett with Bernstein Research your line.
Hi, Good morning, I had a question around the commissioning of light leaves the destiny.
Does the noble Bob Douglas Drillship, what does it do as you get toward commissioning is that going to get re purpose will that standby to drill further wells.
No it'll stay there and just finish out the drilling of both producers and injectors for the Liza field.
So the initial ramp will be a partial set of injectors and producers and then.
Drilling will continue during that kind of three to four month ramp.
Yes, it will.
That makes sense.
Thats all I had thank you.
Your next question comes from the line of Scott Gruber Citigroup.
Yes, good morning.
Morning.
Oh I may have missed it earlier, but.
Any color you can provide on Bakken wells, we brought on line for Q.
In terms of.
There are basically.
The Bakken program in General continues to meet all expectations. We're on track for this 15% on average.
IP 180.
Increased due to the plug and perf, we're on track for the 120 to 125000.
Barrels.
Oil of IP 180.
So so basically all on track there was nothing remarkable necessarily about the third quarter now we did have lower wells online.
But they did outperform in the third quarter.
Got it and just as you consider Bakken Capex for next year that sounds like this year Theres lot of.
General process improvement and.
And efficiency improvement, but as you think about backer backing Capex next year do you anticipate incorporating service cost deflation and any color on order of magnitude.
So we are to your point, Scott, we're not seeing pressure on costs in North Dakota, and obviously with the decline in the rig count that that's that's helped from the cost standpoint. So at this point right now what we are more focused on this is Gregg said earlier arch driving our lean manufacturing and.
Continuing to drive down those well costs with our goal of getting to a 6 million DNC well. So when you're looking at capital next year, we will have some reductions baked in for our efficiencies for those well cost not not really for cost deflation or anything like that just start our lean manufacturing offset by.
With our efficiencies there will be more wells that get drilled next year, just again, as we get better and better drilling to plug and perf. So that's kind of how we're laying out the program for next year and <unk> and remember as John as mentioned earlier, it's six rigs for 2020.
Got it appreciate the color. Thank you.
Your next question comes from the line of Janine weight with Barclays.
Hi, good morning, everyone.
Morning.
Good morning, backend, it's outperforming this year and you just increase the full year production guidance I just wanted to follow up from some of the higher question. So could this outperformance potentially bias that plan to level load at that 200000 barrels a day and I think I heard you say earlier in the call that it could be higher than 200000 barrels a day bye.
I think that was more related to your NGL contract. So I guess, if you think about achieving your target on could you do it on last well then less capex or would you rather kind of let things slow and have higher pacsun and maybe kind of higher free cash so and I know, there's a lot of moving pieces, but kind of inline or what other people have been saying there has been.
A lot of your recent activity suggest that you have a lot of other opportunities and portfolio and I also think theres. Some infrastructure considerations on that 200000, a day. So I wanted to check in on that see if that's all lending factor.
Yeah, well first of all let me say there is no. It there is no into infrastructure constraints at all.
For us to make it to the 200000 barrels a day.
We are still on track.
To deliver 200000 barrels a day in 2021 of six rig program next year and then after that we'll drop the rig count to four and as you suggested in your in your remarks, we will then hold that production flat for a number of years at 200000 barrels a day.
And as a result of dropping four rigs.
We'll be generating significant free cash flow $802 billion.
Free cash flow once we dropped the rig count to four so it becomes a very significant cash flow generator for the company. We do get asked why not go higher than 200000. If you. If you look at the infrastructure required to build for a bigger peak.
It doesn't make economic sense do that so the right thing to do from an overall value standpoint is whole get at 200000 barrels a day and you're right. The pop contracts are going to ebb and flow with with prices.
And what I mentioned was if NGL prices stay chronically low.
We could be above 200000 barrels a day as result of those additional NGL volumes that we would capture.
Okay, Great. That's really helpful and my follow up there is it again, it's on the back and there's been a lot of talk about well cost reductions and performance and in terms of the beef production. We've heard commentary from other operators that making sure that your base is performing well some of the highest return capex you can spend south is better.
Performance on a pdps a component of what's going on with higher Bakken production.
It is I mean the base.
Base continues to hang in there.
Achieving or beating expectations. So we see no problems.
In the base production then of course, you add the new wells, which are doing much better with the plug and perf design that's how we're.
Continuing to overachieve over achieve in the Bakken.
Okay, great. Thank you for taking my questions.
Thank you.
Your next question comes from the line of a room.
With JP Morgan.
Good morning, Greg I was wondering if you could give us your thoughts on.
Whether the oil mix and the Bakken should hold relatively flat.
In the fourth quarter versus the third quarter and it sounds like you still feel remain comfortable in terms of the 2021 outlook of 200 Mboe per day with <unk> with a low 60% oil mix is that correct.
Yes, we do yeah, we're very confident in that number.
As I said, probably what's going to affect fourth quarter mix again is the NGL pricing does that go up or down.
Because always when this oil volumes flux.
Always when this gas percentage fluctuates in the Bakken, it's purely due to the midstream it's increase gaps gas capture and its pop contracts. That's the only thing providing really the variation.
If I look at wellhead GE awards those are staying the same so it's purely a midstream issue and the result of how we consolidate or volumes on the balance sheet.
Okay, but at the 165, you you'd assume it pretty similar.
As a guide I believe.
Yes, and again it all does depend though on the NGL pricing as we go forward. So we have estimated NGL prices going up so little bit less from the pop contracts, but yes, just as Greg said, we believe we can keep this low 60 with can I call. It a normalized NGL price, but I.
I guess the point I think Greg was trying to put it is you don't need to focus really on that right. Our oil production was up 12% quarter on quarter, it's going really strong everything is going really well in the Bakken from an execution standpoint, and a reservoir standpoint, and we will get fluctuations on the gas and the NGL just due to price.
Scene and gas capture.
Great. Thanks, a lot and then just my follow up.
Yeah at Liza one is coming on line a bit early I was wondering if you could help us a better understand.
How long the ramp would be to full productive capacity at 120 and also John maybe you could give us some thoughts on the operating costs.
Once you do get to capacity I think you did lease the vehicle the vessel that or pardon me. So just wondering if you gave us that maybe some broader thoughts on op costs as well per barrel.
Yeah again, it Rune I think you can assume a three to four month ramp.
On Liza one.
To get to that skewed to get to the 120 and again, that's not uncommon for.
First wells in field in the deepwater reservoir, because you really want to see how those wells are performing yield you will gradually increase the chokes.
You may do some shut ins to get some build bumps you really want to understand the dynamic nature of the reservoir again, not uncommon at all and deepwater.
And then a ruin as far as the.
Cost per barrel that will produce obviously, we'll get the full guidance as we go out in January . So, we'll obviously have the ramp right. So you'll have a higher cost per BOE, we as we're doing the ramp period, then as it moves on you're right. We have at least here for a period of time, which is adding $3 ish per barrel on on the.
Costs. So it will be above 10 dollar cash cost per be a week on phase one here on the ramp until that FPSO, which the plan would be later on to be purchased which would drop that $3 off the op cost and and move it to the DNA line, but this will be a good low cost addition.
To our portfolio.
So again, it's part of this plan the phase one will begin to take down our cash cost phase two will even do it more as we get the bigger ship and more production on at that point.
Great. So the cash costs, excluding the leasing costs would be six to $7 per barrel.
No it should be a little it'll be a little bit higher than that number. So it will be a little bit above the $10. So you can do let's just call. It around 12 ish in that type of range and then as you can drop just do a little bit under 10 after the lease.
After the FPSO is purchased but we'll give full guidance as we move into next year.
All right that's super helpful. Thanks.
Your next question comes from the line of Paul chain Scopia Howard.
John .
Some Poland that by 2022, when these a to come on stream I suppose that either 2020 to 23, you guys would be a free cash flow. So on the longer term basis do you have a.
Internally I talk what would be the right ducks and growth rate and free cash flow you combination that you may be targeting.
Well very much we laid this out in our Investor day as our long term a plan out to 2025 were on track to execute that strategy, which is you know 20% cash flow from operations growth, 10% production growth out to 2025, we're on track.
Okay.
Our results this year underpinning our results next year that we forecast underpin it and that's how we really look at.
Any guidance, we would say we put out a long term strategy and we're executing it having said that.
As.
Our cash attentions to continue to generate cash and then.
The Bakken starts becoming a major cash mentioned 2021 and beyond to and Guyana 2022, and by beyond obviously will be a significant free cash flow generator, we see that free cash flow.
Compounding over time and the first call, we'll be continuing to invest in our high return projects as John Riley said, 75% of our Capex in that $3 billion range goes to the Bakken and Guyana, but once we start to generate free cash flow on a recurring basis, our top priority will be.
Starting to return.
Capital to our shareholders on a consistent basis and the first priority there will be increasing the dividend.
I guess my question is down than longer term basis do you have a talk at night.
How much is to cash flow you will we tend to show who does a.
Free cash flow, you would say, 6% by Petsense cycle, and the kind of talking like that you have in mind.
Because because our free cash flow increases over time.
I think the best way to look at it is the majority of that free cash flow.
It will be returned as capital to shareholders. That's I think thats the best way to look at it.
Okay.
And on the.
Maybe this is John on the you have a talk at the cash calls for the corporation, we dropped below and by 2021.
This way now just like 12 to 13 bona a and you just mentioned Oh gosh I know, it's going to be C Corps, yet for the 12, so what is the major component.
Reduction going to be you know the for you to jump that much.
Right so.
Got it call it to the two biggest drivers are as I said, Guyana starts around 12 will buy out that Fps. So because as you know that's part of the plan that would happen in 2021 that will drop that cash costs by $3, they're going on phase. One. So you are under 10 right there with Guy add a and then.
Again, driving up to 200000 barrels a day is a big contributor there to drop that our cash costs down to $10.
Again now with you get he sox coming in very good that's going to be a nice low cost cash add to the portfolio is as Greg mentioned lot of five ramping up. So it's really is a combination of our of our portfolio in total, but with the big drivers being guy at and Bakken.
Uh huh.
John with what is but can you talk in 2021 on the cash calls.
We don't I don't lay out a target per se by asset there, but as I've always said here backings cash cost is below our portfolio average right. Now. So you know the 12 75. It is below that and it's going to continue to drive down with this significant increase in production going to 200.
Some barrels a day.
And do you have a number which is the Hess midstream total capex look like in 2021 in 22.
21, 2020 and 21.
No we have not put those numbers out yet, although I would tell you win.
In the announcement.
That all the midstream transaction they did put some guidance out for 2020, but not 2021.
Okay I find the one this is great for Aesop's, one I know that youre going to give us some additional data.
The next year.
Do you think this is a one we'll have to well program I was on Monday, and also that what's the well.
And then oil and gas mix, we should assume.
Yeah. So I think again evaluation of the well results are still ongoing and and we'll give you a further updates including resource estimate production rate probably early next year. After we have some dynamic production data.
Yeah, we're going to start with the first well.
But we see enough hydrocarbons here that it could take another well to a.
To a evacuated all that we see.
Do you have a oil and gas mix.
No not yet we'll provide that.
Alright, thank you.
Your next question comes from the line of Jeffrey Campbell Tuohy Brothers.
Good morning, and congratulations on a solid quarter.
Oh I want to thank you returned back to that sit back to the Soc Swan just because.
It sounds like it's a really big well and then.
When we maybe even two wells and then when we put that together with the flat 65000 barrels equivalent per day target.
It sounds like I'm wondering how that fits together I mean, it would you.
Choke back to well to stay within the 65, we have a period, where we might have some excessive production because if a well.
These expectations Lucky Sox does wondering also as there are some limit.
Restructure limits.
Embedded in their someplace.
No there's not a mean.
I think you could assume the Gulf of Mexico will be between 65, and 70000 barrels a day really in that range.
There is no infrastructure constraints necessarily we won't choked back wells.
We will maximize production in the Gulf of Mexico.
Okay. Thanks.
Ourselves and I had one Guyana question I, just noted with the interest at a number of these upcoming exploration wells and the Lisa Phase one neighborhood bearing in mind. Thus the earliest project sanctions.
It strikes me is interesting and I was wondering if you could add any color on what the thinking is behind the continued exploration in this area.
Sure I think I think as we've talked about before what really trying to do is is delineate what I call. The eastern seaboard that exists between Turbinen Liza.
And we see a lot of prospectivity kind of in that whole eastern margin. So really what we're trying to do is understand all the volume we have there to inform the cadence of the future vessels.
So that's really the purpose because you get closer and closer to Liza.
Probably higher value in there just because you have a higher.
Oil content on a relative basis and as you get closer Terabit. So you know rent just is really can we delineate as much of that stuff in and around Liza.
For future vessel in that area.
Right I understand it also you wanted to capital efficient as well so thanks for absolutely.
Your next question comes from the line of Michael Hall Heikkinen Energy.
Good morning, Thanks for the time.
Yes, I guess, one a couple of quick ones on my end I'm just curious.
Given all the moving pieces around the pop contracts and now that we saw last quarter and then again this quarter and sounds like there's some of that although less assumes next quarter how much of the increased guide is.
In the Bakken is a function of.
Gas capture exceeding expectations.
And the pop contracts as oppose to.
You know reservoir performance or well timing.
As Greg mentioned earlier.
About 7000 barrels of oil equivalent per day in the third quarter was due to the combination of the increased gas capture and the pop seeking get a feel for that number. There now again, we are forecasting a higher NGL price a lower.
Volumes for the fourth quarter, so you'd have to bake to seven in overall for the year divided by four quarters. So there's an additional 2000 barrels a day coming in through that and then we should get pickup a little bit more gas capture in the fourth quarter as well so nothing specific nothing.
That's driving a significant increase in the production from that but it it is a factor as Greg mentioned.
Okay, sorry to beat the dead horse I just wanted to be CLO.
Appreciate it and then I guess just to think about 2020 to kind of.
Clearly as Youve outlined you've got a big ramp and and free cash flow coming over the next few years, but what is the at the current strip and with all the different moving pieces kind of how do you see the outspend shaping up next year.
So as John has mentioned we have this long term strategy, we laid it out at Investor day, and we continue to execute that and to go along with the strategy. We have a strong financial position to be able to execute that so at the ended the quarter, we have $1.9 billion of cash on hand.
As we mentioned post the closing of the midstream Chen transaction. We also get an additional 275 million and just as a reminder, we still do have the $60 WT I put options in place for 95000 barrels a day for the remainder of the year. So we're in a really good strong financial position to fund our program and we do realize is an investment pro.
Hi, Graham here until phase two comes on.
But looking forward now we've got production from Guy and I starting up in in December So we're going to be picking up some cash flow there now in Guyana and as you mentioned Bakken is becoming significantly cash flow generative and by 2021, as Greg mentioned $802 billion to free cash flow. So we'll use that cash flow from operations will.
Along with the cash on the balance sheet to fund the guy into investment program through lease a phase two and when phase. Two comes on then Diana is generating free cash flow. So all of our assets are generating free cash flow at that point. So we feel we're in a good position to execute that.
Okay, but specific to 2020, I mean, just to kind of.
Help us think about next year any.
On the figures you can provide.
No I did nothing specific obviously commodity prices are going to move.
And so as we get into January will give more guidance on where our production is from that standpoint, we will be using our cash flow from operations. Some of the cash on the balance to funded but again, we feel any good position to get through to two phase two and also with depending upon market conditions, we'll certainly look at.
Adding to our hedge position for 2020.
That that really is going to look to protecting the downside, we think thats proven and we're just being disciplined about how we think about that.
Okay. Thank you.
Your next question comes from the line of Pavle Malkin of Raymond James.
Hey, guys. This is mohammad Glom on behalf of put on will Tonight. Thanks for taking the question.
Do you have any update on the exploration plans for Suriname are you that's still playing drilled there in 2020.
Yeah. So as you recall, there's two blocks in Suriname. So let me talk about each one separately, so and block 40 to believe there is excellent potential there.
And second exploration wells currently being planned for 2021, so there will be nothing on block 42 in 2020 recall Kosmos is the operator there.
Half has a 33.3% interest as does chevron as well as Cosmos third third third.
On block 59 answer Nam recall, the operators Exxon Mobil there.
And the what's going on there is the operators nearing completion of a to the seismic acquisition on the block.
Following that the data will undergo processing.
Then we will shoot a smaller more focus threed survey in and around any prospectivity, that's identified and so the first exploration well will likely be spud in 2022 on that block.
And the other partners or has since that oil each with a third again.
Okay understood and this one's kind of Oh, I know you guys don't focus as much on this segment, but I can you, let's talk a bit about Libya, what's going on there and what are the next steps if there are any.
Yeah look our production continues in Libya, obviously, there's a significant civil unrest there.
So giving more clarity other than that is a hard thing to do its a cash generator not that material, but at the end of the day operations continue but it's subject to disruption.
Based upon political unrest and so far it's been fairly stable.
Okay understood. That's all for me thanks.
Thank you very much. This concludes todays conference. Thank you for your participation you may now disconnect.
Everyone have a great day.
Oh.