Q2 2020 Hess Corp Earnings Call
Good day, ladies and gentlemen, and welcome to the second quarter 2020, Hess Corporation Conference call. My name is let's see I will be operator for today at this time all participants are any listen only mode. Later, we'll conduct a question and answer session. If at any time you require operator assistance. Please press star followed by zero.
And we will be happy to assist you.
As a reminder, this conference is being recorded for replay purposes.
I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.
Thank you, let Keith good morning, everyone and thank you for participating in our second quarter earnings Conference call or earnings release was issued this morning and appears on our website www Dot dot com.
Today's conference call contains projections and other forward looking statements within the meaning of the federal Securities laws.
These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements.
These risks, including those set forth in the risk factor section of passes 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 supplement information provided on our website.
On the line with me today, or John Hester, Chief Executive Officer, Greg Hill, Chief operating Officer.
And John Riley Chief Financial Officer.
As we did last quarter in case, there are any audio issues, we will be posting transcripts of each speaker's prepared remarks on doubly www dot has dot com following the presentations.
Now I'll turn the call over to John Hess.
Thank you Jay Good morning, everyone welcome to our second quarter Conference call. We hope you and your families are all staying well during these challenging times.
Today, I will discuss the steps, we're taking to manage through a sustained period of low oil prices.
Then Greg Hill will discuss our operations and John Wiley will review our financial results.
In response to the pandemic severe impact on oil prices, our priorities are to preserve cash.
Reserve 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.
20000 barrels per day at $60 per barrel Brent.
To maximize the value of our production.
In March and April.
When you watch oil storage was a tank tops, we used our marketing capabilities.
Our Hess midstream infrastructure.
And our firm transportation arrangements to the U.S. Gulf Coast to charter three very large crude carriers are vlccs to store 2 million barrels each of May June and July Bakken crude oil production.
The first be LCC cargo 2 million barrels has been sold at a premium to Brent for delivery in China in September.
The other two VLCC cargoes are expected to be sold in Asia in the fourth quarter.
We further strengthened the company's cash position and liquidity through a 1 billion dollar three year term loan underwritten by JP Morgan Chase. This loan was successfully syndicated during the second quarter.
At the end of June we had $1.6 billion of cash.
A 3.5 billion dollar undrawn revolving credit facility and no debt maturities until the term loan comes due in 2023.
We made major reductions in our capital and exploratory budget for 2020, reducing at 37% from our original budget, a $3 billion down to $1.9 billion.
The majority of this reduction comes from dropping from a six rig program to one rig in the Bakken, which we completed in May.
We also made significant cuts in our 2020 companywide cash costs.
On our first quarter call, we announced a reduction of $225 million.
During the second quarter, we identified an additional $40 million with further reductions anticipated.
A key for us to preserve capability is continuing to operate one rig in the Bakken.
Greg Hill in our Bakken team have made tremendous progress over the years and lean manufacturing.
Which has delivered significant cost efficiencies and productivity improvements that we want to preserve for the future.
In terms of preserving the long term value of our assets, our top priorities, Guyana and extraordinary world class assets.
On the Stabroek block, where Hess has a 30% interest in Exxon Mobil as the operator, we have made 16 significant discoveries on the block since 2015.
The current estimate of gross discovered recoverable resources for the block stand at more than 8 billion barrels of oil equivalent.
With multi billion barrels of exploration potential remaining.
In June we resumed a four rig drilling operation with two of the rigs focused on development wells and two on exploration and appraisal activities.
The lease some phase one development, which has an estimated breakeven price of $35 per barrel. Brent achieved first production in December and is now expected to reaches full capacity of 120000 gross barrels of oil per day in August.
The lease a phase two development with an estimated breakeven price of $25 per barrel, Brent and production capacity of 220000 gross barrels of oil per day remains on track for an early 2022 startup.
The development of the pie our field with a production capacity of 220000 gross barrels of oil per day has potentially been deferred six to 12 months pending government approval to proceed.
Planning for the fourth and fifth F. Fpsos is underway, which will be further optimize by this year's exploration and appraisal drilling results.
Our strategy is guided by our company's longstanding commitment to sustainability, which creates value for all our stakeholders.
Earlier this month, we announced publication of our 20, Threerd annual sustainability report, which details, our environmental social and governance or SG strategy and performance.
In terms of safety since 2014, we have reduced our severe safety incident rate by 36% and achieved a 67% reduction in process safety incidents.
In the critical area of climate change, we have reduced scope, one and scope to equity greenhouse gas emissions by approximately 60% over the past 12 years.
We also work contributing to groundbreaking work by the Soc Institute to develop plants with larger roots systems that are capable of absorbing and storing potentially millions of tons of carbon per year from the atmosphere.
We continue to be recognized as an industry leader for the quality of our FC performance in disclosure and in May were named to the hundred best corporate citizens list for the 12 consecutive year, earning the number one ranking for an oil and gas company and ranking number nine on the list overall.
In summary, our long term strategy has enabled us to build a high quality in diversified portfolio that is resilience in a low price environment and puts us in a strong position to prosper when oil prices recover.
Our portfolio provides long term resource growth with multiple phases of low cost Guyana oil developments that are expected to drive industry, leading cash flow growth over the course of the decade.
As our portfolio generates increasing free cash flow, we will prioritize debt reduction and increasing cash returns to shareholders.
Finally, we want to thank our employees for their continued commitment to operating safely and reliably during this pandemic.
The safety of our workforce in the communities, where we operate will remain our top priority.
I'll now turn the call over to Greg for an operational update.
Thanks, John.
The second quarter, we continued to deliver strong operational performance across our portfolio.
Company wide net production averaged 334000 barrels of oil equivalent per day, excluding Libya.
What is above the top end of our guidance of 310000 315000 barrels of oil equivalent per day.
This is driven both by strong results in the Bakken.
Where advantage infrastructure position enabled us to avoid shutting in production.
And by higher nominations in Southeast Asia.
Where demand is increasing as the economy recovers.
In the third quarter.
We expect company wide net production to be in the range of 320000 to 325000 barrels of oil equivalent per day, excluding Libya.
Reduction from the second quarter.
Reflects planned downtime in the Gulf of Mexico.
Our production guidance for full year 2020.
He is now approximately 330000 net barrels of oil equivalent per day, excluding Libya.
From our previous guidance of approximately 320000 barrels of oil equivalent per day.
In the Bakken.
We've been operating one rig since may down from six rigs earlier in the year.
Operating one rig allows us to maintain key operating capabilities.
We have worked hard to build over the years, both within Hess and among or primary drilling and completion contractors.
In the second quarter.
Our Bakken team once again delivered strong results.
Capitalizing on the success of our plug and perf completion design and mild weather conditions.
Second quarter Bakken net production.
Averaged 194000 barrels of oil equivalent per day and increase at 39%.
From the here go quarter.
And above our guidance.
Approximately 185000 barrels of oil equivalent per day.
Following our successful transition to plug and perf completions.
Further efficiency gains combined with cost reductions across our supply chain.
Allowed us to achieve an average drilling completion costs per well.
Approximately $6 million in the second quarter.
We believe that through the application of technology and.
And lean manufacturing techniques that we can continue to push or DNC costs, even lower.
For the third quarter.
Our guidance for Bakken net production.
Is approximately 185000 barrels of oil equivalent per day.
As announced by Hess Midstream earlier this month, the planned maintenance turnaround tioga gas plant.
Currently scheduled for the third quarter of 2020.
We'll now be deferred until 2021.
To ensure safe and timely execution in light of the covert 19 pandemic.
I always gas plant Express expansion project is well advanced.
And is expected to be completed by the end of 2020.
The resulting incremental gas processing capacity.
We'll be out will be available in 2021 upon completion of the turnaround.
For the full year 2020.
Our guidance for Bakken net production.
Is approximately 185000 barrels of oil equivalent per day up from our previous guidance of 175000 barrels oil equivalent per day.
Moving to the offshore.
In the deepwater Gulf of Mexico.
Second quarter net production averaged 68000 barrels of oil equivalent per day.
The Sox, one well, which came online in February.
Is expected to reach is gross peak rate of approximately 17000 barrels of oil equivalent per day or 9000 barrels of oil equivalent per day net half.
In the third quarter.
And to average approximately 5000 barrels of oil equivalent per day net has in 2020.
No. Other production wells are planned to be drilled in 2020 in the Gulf of Mexico. However, we are participating in the BP operated Galapagos deep expiration well.
With a 25% working interest in this class Cretaceous aged opportunity in the Mississippi Canyon area. The wells spud in May and is still drilling.
In the third quarter.
Guidance for Gulf of Mexico net production.
Is expected to be between 50000 55000 barrels oil equivalent per day, reflecting planned maintenance a third party operated facilities that will shut in Congress and Llano.
For approximately 40 days, beginning August 1st as well as they plan nine day maintenance shut down at the she NZ field.
For the full year 2020, our guidance for Gulf of Mexico. Net production is approximately 65000 barrels of oil equivalent per day.
In the Gulf of Thailand production in the second quarter was 44000 barrels of oil equivalent per day above our guidance of approximately 35 35000 barrels oil equivalent per day.
During April.
Natural gas nominations reflected slower economic activity.
Associated with Koby 19, but nominations began to rebound in the second half for the quarter has restrictions on movement or lifted and economy began to recover.
Our guidance for a third quarter and full year 2020 net production is between 50050 5000 barrels of oil equivalent per day.
Now turning to Guyana.
Production from Liza Phase one commenced in December 2019, and in the second quarter averaged 86000 gross barrels of oil per day or 22000 barrels of oil.
Per day net half.
Further work to commission water injection and increased gas injection is under way.
That's good enable Liza destiny up so to reaches full capacity of 120000 gross barrels of oil per day in August.
The leaves the phase two development, we utilize the Liza unity, yet so what they capacity to produce 220000 gross barrels of oil per day.
The project is progressing to plan.
Approximately 75% or the overall were completed and first oil remains on track for early 2022.
As previously announced.
Some activities for the planned pie or development had been deferred pending government approval.
Creating a potential delay in production startup and 612 months.
The standard Karen.
The noble Tom Madden Drillships resumed work in late May early June respectively.
Stand of care in Reagan.
Recently completed appraisal drilling at yellowtail too.
Located one miles southeast of Yellowtail one.
The well identified two additional high quality Red force, one adjacent to and the other below the yellowtail field.
Further demonstrating the world class quality this basin.
This additional resources currently being evaluated and will help form the basis for potential future development.
The stand of care and we'll next move to the Guy to a block.
In which has holds a 15% working interest.
But the manager one well.
Which is located 46 miles northwest of Lisa.
The noble Don Taylor Spudded, the Redtail exploration well located approximately a mile in a quarter northwest of Yellowtail one on July 13th.
Well, we'll target similar stratigraphic intervals as yellowtail.
Will consist of an original whole inside track and will include an option inducted drill stem test and the future.
Results of Redtail, one and yellow till two will be incorporated into our evaluation of the yellow till area.
In closing, we continue to focus on strong execution across our portfolio.
While ensuring the safety for workforce and the communities, where we operate in the midst of the covert 19 pandemic, we've taken significant steps in response to the low oil price environment.
Position is successfully navigate these challenging times and to prosper when oil prices recover I will now turn the call over to John Riley.
Thanks, Greg.
My remarks today I will compare results from the second quarter of 2020 to the first quarter.
We incurred a net loss of $320 million in the second quarter of 2020 compared to an adjusted net loss of $182 million in the first quarter.
For NP.
In P. incurred a net loss of $249 million in the second quarter of 2020 compared to an adjusted net loss of $120 million in the previous quarter.
The changes in the after tax components of adjusted MP results between the second quarter of 2020, and the first quarter of 2020 were as follows.
Lower realized selling prices reduced results by $115 million.
Lower sales volumes reduced results by $128 million.
Lower DDNA expense improved results by $53 million.
Lower cash costs improve results by $38 million.
Lower midstream tariffs improve results by $16 million all other items improved results by $7 million for an overall decrease in second quarter results of $129 million.
For the second quarter sales volumes were under lifted compared with production by approximately 3.9 million barrels of oil.
Of which 3.7 million barrels of oil was associated with our previously announced the LCC strategy.
Which was implemented to enhance 2020 cash flow and the value of our Bakken production.
As part of this strategy, an additional 2.3 million barrels of Bakken crude will be loaded on VLCC tankers in the third quarter.
At June Thirtyth, the VLCC volumes had total costs of $113 million included in inventory on the balance sheet and a corresponding reduction to marketing expenses on the income statement.
In addition at June Thirtyth, we deferred $85 million of realized gains on derivatives contracts associated with these volumes.
The first VLCC cargo of approximately 2 million barrels of oil has been sold for delivery in China in September at a premium to Brent prices.
As a result income from the sale will be reflected in the third quarter and cash proceeds will be received in the fourth quarter.
The remaining two VLCC cargos containing approximately 4 million barrels of oil are expected to be sold in Asia in the fourth quarter.
Now turning to midstream.
The midstream segment had net income of $51 million in the second quarter of 2020 compared to $61 million in the previous quarter, reflecting lower throughput volumes.
Midstream EBITDA and adjusted basis, and before non controlling interest amounted to $172 million in the second quarter of 2020.
Paired to $193 million in the previous quarter.
Turning to corporate.
After tax corporate in interest expenses were $122 million in the second quarter of 2020 compared to $123 million in the previous quarter.
Now turning to our financial position.
At quarter end, excluding midstream cash and cash equivalents were $1.640 billion and our total liquidity was $5.3 billion, including available committed credit facilities, while debt and finance lease obligations totaled $6.6 billion.
Our fully Undrawn 3.5 billion dollar revolving credit facility is committed through May 2023.
During the second quarter, we successfully syndicated our 1 billion term loan with a maturity date in March 2023.
We have no near term debt maturities aside from the new term loan.
We've hedged over 80% of our remaining crude oil production for 2020 at June Thirtyth. The fair value of open hedge contracts was approximately $450 million, while rely settlements on close contracts. During the first six months of the year were approximately $500 million.
Now turning to guidance.
Our ERP cash costs were $8.81 per barrel of oil equivalent, including Libya and $8.64 per barrel of oil equivalent excluding Libya in the second quarter.
We project N P cash costs, excluding Libya to be in the fourth to be in the range of 10 to $10.50 per barrel of oil equivalent for the third quarter, which reflects the impact of planned maintenance shutdowns in the Gulf of Mexico, and higher production taxes in North Dakota on increasing oil prices.
Full year guidance is expected to be in the range of $9.50 to $10 per barrel of oil equivalent which is down from previous guidance of 10 to $10.50 per barrel of oil equivalent.
Reflecting the increased production guidance and further reductions to costs.
This brings total cost savings to approximately $265 million for 2020, and we continue to look for further cost reduction opportunities.
DDNA expense was $15.45 per barrel of oil equivalent, including and excluding Libya in the second quarter.
DDNA expense, excluding Libya is forecast to be in the range of 16 to $17 per barrel of oil equivalent for the third quarter due to a combination of planned maintenance shutdowns in the Gulf of Mexico higher third quarter production from North Malay Basin, and additional Bakken production related to the deferral of that turn around at the Tioga gas plant.
The next year.
For the full year DDNA expense is projected to be in the range of 16 to $17 per barrel of oil equivalent which is up from prior full year guidance of 15 to $16 per barrel of oil equivalent.
This results in projected total S&P unit operating costs, excluding Libya TV in the range of 26 to $27.50 per barrel of oil equivalent for the third quarter.
And $25.50 to $27 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 third quarter and $140 million to $150 million for the full year, which is down from previous guidance of $145 million to $155 million.
Midstream tariff is projected to be in the range of $220 million to $230 million in the third quarter and $905 million to $930 million for the full year, which is unchanged from previous guidance.
BNP income tax expense, excluding Libya is expected to be in the range of $10 million to $15 million for the third quarter and $20 million to $30 million for the full year, which is unchanged from previous guidance.
Our crude oil hedge positions remain unchanged, we expect option premium amortization will be approximately $70 million for the third quarter and approximately $280 million for the full year, which is unchanged from previous guidance.
For midstream.
We anticipate net income attributable to Hess from the midstream segment to be in the range of $40 million to $50 million in the third quarter and $195 million to $205 million for the full year, which is up from previous guidance of 185 million to $195 million due to the deferral of planned third quarter.
Maintenance turnaround at the Tioga gas plant to 2021.
For corporate.
Corporate expenses are estimated to be in the range of $25 million to $30 million for the third quarter and unchanged for the full year in the range of $115 million to $125 million.
Interest expense is estimated to be in the range of $95 million to $100 million for the third quarter and $375 million to $380 million for the full year, which is at the lower end of our previous guidance of 375 million to $385 million.
This concludes my remarks, we'll 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.
To your question has been answered you would like to withdraw your question press the pound key.
Questions will be taken in the order received.
Please press star one to begin.
Our first question comes from a line of Doug Leggate, Oh Bank of America. Your question. Please.
Thank you good morning, everybody I hope everybody is doing well out there.
I guess my first questions on the Bakken My second one on Guyana.
So group had first on the Bakken can you give us a with a revised guidance give us an update on how you see the exit rate on declining on a one rig program going into 2021.
Yeah, Doug this is Greg.
So did the exit rate is it's going to be somewhere in the range of 170 to 175.
And the reason is because we're projecting a little bit lower pop volumes in the fourth quarter with seasonal NGL prices coming out.
So 170 to 175 as far as 2021, we're still in throws of developing our plans for next year. So we'll give you guidance on that.
In a in January as always.
What I will say those we believe that we can hold production relatively flat.
You know.
With a two rig program, we could hold at relatively flat.
So there will be some decline on a one year, whether one rig program, but we will give you that guidance in January.
Okay. That's that's really helpful. Thank you my follow up with sorry, if I may is on John I'm, not just a couple of things related I guess.
First of all Greg obviously, the election hasn't been resolved yet that's an onshore and wants to handle this one but.
But my understanding was not beaches was still not done with their evaluation. The the quite Yara S.P.S. So is already with the whole is already complete something is 14 months, how the topsides installation.
In other words, there's already running ahead of schedule. So I'm just wondering if you can put some context the runs.
The six to 12 month delay because there seems to be some speculation out there. The payout has been pushed out much later, which was no. My understanding I guess is part one and if I may squeeze apart to its really just if you could speak to the plot to implications of the deeper resource exploration success you part on the early.
Let's see the first tucci for Sps only because it seems to me those platforms are going to be about longer.
Then perhaps you originally had a ton for I'll leave it there. Thank you.
Doug.
Great questions Hope you and your family are well as well.
Look the court of appeal in Guyana is expected to issue a ruling tomorrow.
And we hope the ruling will provide further clarity on the election outcome. Ultimately we expect the will of the Guy in these people will be expressed in this final results I think it's really important to know the leadership of both major political parties.
Has stated support for the state production sharing contract and in terms of Pyra.
And moving the development forward the joint venture is ready to move forward as expeditiously as possible as soon as the government is ready to do so so I think thats the clarity there and you know what the potential impact is on on the ultimate development timing and production.
Timing apply our will be a function of.
US working for with the government, so I wouldn't want to speculate more than that but we're ready to move forward as soon as the government's ready to move forward.
In terms of you know the exploration success that we've had.
The 16 discoveries.
Six of which of.
These exploration wells where spot in 2019, most recently.
They have actually during this time of some of the drilling delays have enabled us to optimize the resource to be developed for ships for and ships five.
And ultimately lowering the cost per barrel and increasing the NPV of these discoveries. So just these six recent exploration discoveries that were spud in 2019.
Where is going to bring value forward.
You're making a good point, which is I think a second point, which is a number of these appraisals that we're drilling.
We'll be tie backs, which will be a value enhancers.
And extend the plateau, you're absolutely right on that so I think it's both points.
Optimizing ship foreign five just because of our recent exploration and appraisal activities, but also a building our inventory of tie backs will also bring value forward and then you know the third point.
I'd say is that you know we have a really exciting world class inventory of future Bull Drillable prospects. Both in the campaign in where most of our discoveries have been made where the developments are currently moving forward, but also deeper horizons, Greg talked about.
One in yellow tail.
And also the deeper San Antonio and and this will really underpin a low cost spiral developments.
For many years to calm sustaining our trajectory of the industry, leading cash flow growth.
From Guyana through the decade, so I think hopefully that provide some context for you in terms of how we think about the exploration potential development potential production potential of the world class asset that we haven't Guyana.
That's terrific thanks to the Phil I'm, sorry, guys appreciate it.
Thank you. Our next question comes on the line of Arone Xyrem.
JP Morgan your question please.
Yeah good morning.
Sorry, you haven't three penetrations in the early Cretaceous at least a deep triple pill deep and now yellowtail deep.
Gregor I was wondering if you could discuss some of the key conclusions thus far in the San Antonio and just broader thoughts on yellowtail moving into the development Q and perhaps you could also just kind of set the stage for red tail.
Greg Greg wanting to go ahead on the.
Early returns on some of the deeper opportunities for how we feel about the prospectivity overall as a ruinous asking yeah you bet. So rune as you mentioned we have.
Several penetrations in the Stabroek block and then of course, you know on the neighboring block answer Nam with Apache.
We have penetrations, there as well.
So we obviously remain are very excited about the potential of the San Antonio.
As I've mentioned previously she's to and older River system.
It looks very similar.
Seismic you know.
Liza type deltaic environment.
Now obviously, it's early days.
So we've got to get a lot more penetrations in the San Antonio into understand it.
And that will be the big you know will be a big part of the exploration and appraisal program going forward in the next couple of years, but we remain very excited.
Now, if we turn to yellowtail and kind of the Redtail area as I mentioned in my remarks at Redtail is going to target basically the same stratigraphic intervals as yellowtail.
And the combination of yellowtail, one yellowtail tier two and Redtail is really going to form the basis of eight another Fps So development.
The partnership is looking at all you know the cadence in the development of which is going to be phase four in which is going to be phase five yellowtail is looking very promising.
And of course, it's got some higher value than hammerhead, because it's got a higher quality oil.
So the potential for it.
Jumping the Q and being much earlier in the queue is certainly.
So a lot higher given what we've seen in yellow tail to you and what we expect to see and Redtail as well.
Could it support the larger ship size called to 20 or yes, you early to say, yes. It's good okay, great and just my follow up is just on Liza one you guys talked about getting to call. It that 120 sometime in August.
Could you discuss the potential of the facility to run above nameplate and I also wanted to bring John Riley into discussion if he could discuss we did observe a weaker realization in the quarter for the leaves accrued and just thoughts on how do you expect world pricing in Guyana to trend relative to Brent.
Yeah.
Yeah, Greg why don't you take the first one and John Wiley will take the second what's your thanks.
Yeah. Thanks Rune smooth. So you know currently the focus remains on on the commissioning work that I talked about my opening remarks. So.
That's getting further and gas injection capacity and also water injection capacity that work is ongoing and we expect.
We can ramp to full capacity.
During the month of August of the 120000 barrels a day or so.
Beyond that the operator is evaluating de bottlenecking options.
You know, we don't know exactly how much additional capacity that's going to add yet because the studies are ongoing.
But what I, what I will say is that that de bottlenecking work will most likely occur in the first half of 2021, So we hope that.
In a in the first half that we'll be able to get more capacity out of leaves the phase one.
But will quantify that amount in the future once weve chosen or not.
Great.
And then a rune on pricing for Liza crude Liza crude.
Was pricing at brand and we continue to guide that it will be pricing at parity to Brent. So what you saw in the second quarter was that we had two liftings, but both of those priced and delivered early in the quarter. When Brent prices were very low so when you're going to see our third quarter realizations will reflect the quarter and quarter improvement in.
Prices.
Great. Thanks, John share.
Thank you. Our next question comes on the line up Paul It, saying Oh Scotiabank. Your line is open.
Thank you good morning, guys morning, I know, yes.
Andy maybe that.
John can you maybe I missed that from a direction standpoint on 2021 Capex versus 2020, we expect to be up down or roughly the same.
Sure Paul I mean, as you said it is early and we will discuss our guidance as usual in January but.
Where we are right now we expect our 2020 when capital spend to be flat to down compared to 2020.
And the big moving parts is will have lower spend in the Bakken continuing with the one rig and then that will be offset by higher spend in Guyana.
Okay, and secondly that.
And that would be FCC can you tell us that once it's there's always shipping and interest expense calls related that 6 million, though I.
I mean, we note that you get a pet supplies me on my station when you sold union or Asia, but that wasn't the incremental cost to get there.
So for as you said, so we have the first cargo and it was sold in China as as I mentioned at a premium to November Brent prices.
And I think I mentioned this last quarter, but we locked in the contango in the Brent market by obviously, capturing the difference between the near month prices and prices at the expected sales day.
And then now as I mentioned, plus we are receiving an uplift in price step differential selling at a premium to Brent in Asian market versus a significant discount that we would have had to w. T. I in the second quarter. So basically the combination of those two benefits more than offsets the cost of storing and transporting those those.
Volumes to the Asian market.
So again, we're not being specific each VLCC is different but the way we locked it in and contango and then obviously picking up to better differential is making it a very profitable trade for our Bakken crude.
John Youre, maybe that you don't want to shed because of commercial reason was the actual cost can you tell us that what is the net improvement you expect.
Dose 6 million barrel comparing to give you said it sounds good.
The Gulf Coast.
So let me let me put it this way because it gets to a hypothetical calculation because as you know Paul trying to move and sell barrels in the second quarter Spis, especially in May.
We don't even know if we could have sold those barrels and if we did sell those barrels would it have been even more than a discount we were seen in the market. So I think the best way to look at it is as I said.
Move from W. Ti to Brent and locking in that Brent contango took care of all the costs.
You probably saw in May the differentials on Wi Fi down a Gulf Coast say 14, $15 under W. tea.
And now we're picking up a premium to Brent. So you can apply that difference in that discount plus the premium to all those barrels. So you can you can see for us it it it one as we talked about we didn't want to shut in production. This allows us to sell these barrels in the same here versus if you shut in production.
You'd never would have gotten those barrels sold and got that cash flow plus it allowed us to enhance the value of the Bakken crude.
Okay.
And Ah onto cats and turn the wrong.
I'm actually I nuclear supplies that you guys see besides just the Lady it gets done.
But the longest relatively weak this yen hopefully next year would be better.
And the prices stay will hopefully next year, we'd be better.
And say, maybe a cash for use or you think I mean, we said that we really want to see later.
Got planned turned alarm.
It Greg will answer this but the it's all about safety and the welfare of our employees and contractors as a community where we do business.
So it was a safety decision of caution when we absolutely no. We did the right thing there.
But Greg do you want to elaborate at all and then John can talk about any other financial impacts.
No I think John you pretty much answered I mean, we saw a spike in tioga.
That was not only some local workers, but also some of the people that we were going to bring in from the Gulf coast for the turn around.
You know there was spikes going on in that part of Texas as well. So we we just made eight a.
Conscious decision that you know for the safety for our employees and for the safety of our community a up there in Tioga that we did not want to introduce the potential for additional koby cases.
So again it was purely a safety based decision.
And then from a financial standpoint, obviously, we're picking up on an annual basis about 5000 barrels a day of added production.
From it mostly.
Natural gas and Ngls actually all that natural gas and Ngls.
From that and then we'll have obviously less costs in the third quarter associated with the maintenance. So all that is moved to next year, but again, Paul as everybody said this was related to co vid and safety of the employers fleece contractors in the local community.
Thank you.
Thank you. Our next question comes from a line of Bryan singer.
Goldman Sachs. Please go ahead.
I wanted to go back to tick Guyana, if a if I can and go back to the yellowtail reservoirs can you add any additional color on whats defining.
The high quality reservoirs from a sickness oil quality perspective, and you added some take away is on more of the deeper reservoirs given multiple penetrations from industry and yourselves can you add any more color on the implications of the adjacent reservoirs and then.
In an earlier question you mentioned earlier response, you mentioned that.
You're optimizing the resource development.
For ships, four and five lowering the cost per barrel, increasing the present value.
Is that a function of the better quality reservoirs that you're seeing or is there something that you're dealing with regards to the underlying.
Cost structure.
For future development. Thank you yeah, Greg will pick up on this a great question, Brian you know a drilling in evaluation is still underway.
In yellowtail, so some of the specificity you're asking for we can just talk and text really not specifically.
But happy to do that and Greg will also shed some light in terms of the prospectivity that it's a higher quality oil more likely so and aerial extent in connectivity it looks very encouraging for a bigger ships. So yeah, Greg you want to elaborate.
Yeah sure. So you know Brian I mean, that's pretty much what we saw was the same quality of reservoir or is it runs yellowtail, one and as John mentioned.
You know those reservoirs are very much leaves alike, so very high quality oil very high quality reservoir.
And then as we went over to yellowtail too.
No as I mentioned my opening remarks, you know we saw continuity within existing very large.
You know aerial extent in yellow tail, and then also a lower LOE.
If you will but also had very high quality pay in very high quality oil and it. So you know the result of that as you know the yellowtail complex is just getting much bigger.
And given the quality the oil and the quality reservoir.
You know it makes a lot of sense to move that development forward.
Hey, because higher capacity and again, it's got a much higher quality.
Both crude oil and reservoir, then then say hammerhead right.
And of course, Redtail moving over again, it's a mile in a quarter way.
You know, we expect that that would further expand you know the aerial extent of those reservoirs and so far looks like good continuity.
Between everything so.
So that just bodes well for an extremely good development again at that higher capacity.
Great. Thank you and then my follow up John you started the call talking about positioning the company to perform well in a sustained low oil price environment, and I wondered whether that free cash flow as future phases.
But if that is sufficient to meet your cash preservation goals or if you see the need for asset sales or equity linked issuance to reduce leverage.
Thanks, Brian.
What we're planning to be a plan first of all that we put in place as John said to preserve cash preserve capability preserve long term valley value is in this low price environment. We wanted to get all the way through two phase two in Guyana and being a position then picking up I'm just going to say approximately 60000 barrels a day upfront.
Based production coming into the portfolio. So once we can get to that phase two and then obviously power comes on and Phase four we believe we can fund our way through that cycle and fund our investments in Guyana with our current positions that we have now obviously we have.
This liquidity as I mentioned earlier, but what we are looking at right now that even with a low oil price environment that we're not going to add.
Debt to our balance sheet. During this period and again, we think we put a plan in place that gets us through to that phase two.
Yeah, and specifically no we have no plans to issue equity Brian and.
We're always looking to optimize our portfolio and if there are a sums noncore assets that we can monetize.
To bring some of that cash forward you can assume that we'll do that as we've done in the past.
Great. Thank you.
Thank you aren't next question comes on the line of Jemima way of Barclays.
Question. Please.
Hi, good morning, everyone.
Turning.
Morning Marni.
Hi, my questions or regulatory and.
Policy related and I guess, the first one in terms of senses federal exposure and the potential risks within November election, and the Gulf of Mexico can you discuss what Optionality you haven't our management gentle, how many deanna hand, and what optionality he might have leases.
No there wasn't any well anyway.
<unk>, but we're just trying to understand.
What what potential you have areas some kind of Dan share Yeah, No fair question the Janine.
I I think two points I'd like to make their first you know we have less than 2.5% of our acreage in North Dakota on federal lands and.
With significantly reduced Gulf of Mexico activity through 2021, you know, we don't anticipate any significant near impacts to house.
From any potential regulatory changes from a new administration.
But I think the second point, which is a very important one.
Is that.
You know 23% of U.S. productions on of oil is on federal lands about two thirds of that oil production is offshore Gulf of Mexico, and any proposals that would restrict our country's ability to explore develop and produce that oil.
It's going to be very bad for us jobs very bad for the U.S. economy, and very bad for our National security. So we hope when people are thinking about future policy when it comes to federal lands reason prevails.
Which would be in the interest of all oil U.S. taxpayers and consumers.
Okay, great. Thank you answer to that financing.
And I guess my second question would be on dapple seeking so today on the potential shutdown and take line can you discuss how much capacity you have seen in capital barrels.
Thank you Werent means and I know I should say advantage with the fact that you have several railcar.
Optionality there, but can you address and Ashley Smith for example barrels that are means and is there any any specific logistical issues associated with getting that production.
Rail or whatever you have.
Sure excellent question look into the status of dapple.
You know we continue to transport volumes on DAP, all while we wait for a decision on the state from the District Court of Appeals, we have 55000 barrels a day of firm transportation on dapple.
If dapple is shut in a we have the capacity to move all of our Bakken production because of the flexibility provided.
By our marketing capability of our Hess midstream.
Infrastructure, and our long term commitments to multiple markets.
And specifically.
You know if the Apple were interrupted you know rail would feature a plus other pipeline systems that we move oil on currently would feature so it would not have a major impact on moving all of our production if the Apple were shut in and the cost to us would be a few dollars per barrel.
Okay, great. Thank you very much thank you.
Thank you. Our next question comes from Roger read of Wells Fargo. Please go ahead.
Yeah. Thank you good morning morning Marni.
Yes, a couple of questions get into one kind of tying back to maybe Brian's question earlier about leverage and all that how do you think about.
The hedging which is obviously a big success. This year as you look into 21 would you want to hedge again.
You can't get quite the prices we had this year. So on the forward curve, that's just not attractive enough right now, but I just curious how you're thinking about that in the overall managing cash flow and capex.
Yes, Roger that is Thats clearly part of our plan to hedge in 2021, because as we were talking about earlier. We know we are bridging to that phase two in Guyana, and obviously, we've done a reduction in our in our capital spend we've got the term loan we did as.
As you said have a strong position hedge position here for 2020, so as we move through the year, we like to keep with our our strategy of using put options. So you can expect us to put put options in the fourth quarter. Like you said right now from just the volatility and the time value of the put options.
Putting them on right now would be too expensive. However, as we get into the fourth quarter and get closer to 2021, you should expect us to to put on hedges and and to put on a significant hedge position similar to that what we did in 2020.
Okay. Thanks, and then my other question more operational we know about the issues that you had.
Surface equipment at lives I was just curious how the wells have been performing or what you can give us there I mean, obviously talking about how get yellow tell is from a reservoir standpoint similar to lies and I'll. Just curious how have you seen enough at this point, where you you would say.
Expectations are being that might reality here.
Yeah, Greg.
Form and fly zone.
Absolutely I mean, the wells or these are amazing wells are awesome wells, and they're meeting or beating all of our expert expectations. So great wells no issue with wells whatsoever.
Okay. Thank you.
Thank you. My next question comes from Bob Brackett of Bernstein Research Your question. Please.
Good morning, I had a question around Guyana, and I'm curious about where the hospital one prospects, it's falling out it looks to be the largest at least area under closure prospect remaining in the inventory like fund was going to be drilled that at some point this year could I get an update on that.
Greg Yes, Bob So the plan is that we do hope to us, but that well before the end of the year.
It's it's the next in queue on the expiration order so.
You know hopefully the noble Don Taylor will be able despite that well before the end of the year, It's working right, it's going obviously and bread tail and it's going to do some phase two.
Producers.
And then we'll go to Haas after that so depending on how long all that takes we should get its buck but ended the year.
Okay. Thanks for that.
Thank you.
Thank you next question comes from David Deckelbaum Cowen Your line is open.
Morning, guys. Thanks sort of time today. Thank you.
Just a question that you talked about before.
Requiring two rigs to hold the buckets flat I know the the intention is to spends less next year on overall, assuming a one rig program.
Is there a move in commodities that would cause you to look at maintaining buck in volumes or is this strategy now to just accrete that cash to the balance sheet to maximize liquidity.
Yeah, No you know, we would want a Wi fi to be in the range of $50 for us to consider to bring a rig back and our focus is to maximize cash flow generation for sure and that's going to be a dynamic between price the outlook for prices and.
Keeping our liquidity strong so I again, when we get to the ended the year, we'll be able to give more clarity on what our plans for the Bakken are.
Right now, it's one rig and as we go into next year, a will make the decision according to where the market outlook has.
I appreciate that.
Just the last one from me just I know, it's kind of trying to put a.
Bow around pay or when you originally guided the six to 12 months potential deferral.
I guess, how how is the political political process lining up with your expectations and I guess.
What do we need to see happened in order to be able to adhere to that that same guidance yes.
Newly elected government needs to be.
Put in place.
And as soon as it is.
Our joint venture will work closely with.
With the government to move the development forward.
Just for conservatism, we're talking about a six to 12 month delay.
As a function of how it works out with this newly elected government will be able to be more specific on the exact timing once we get the development approved which we anticipate a getting eventually.
I appreciate that as well thank you guys.
Our next question comes from Jeffrey Campbell of soy <unk>, sorry toward brothers. Your line is open.
Thank you and good morning.
First the first I thought to ask why you chose to invest and the BP Gulf of Mexico, well rather than.
Well on your own tie and targets of with GE Sox, one was such a great success.
Greg you want to talk about our exploration strategy and you know we haven't position in the Cretaceous and joint venturing and sharing risk with BP was the appropriate thing to do it's not just set as BP. It's also helps but anyway, Greg will provide some perspective on our activities in the Gulf. Yeah. You bet. So you know again.
In the Gulf of Mexico is a key part land for us great cash engine.
Plus we have the proven capability not only on the exploration side, but also on the project.
Delivery, which includes drilling and.
Development of top side.
Well, obviously you know it remains a key for us and.
And in the last five years, we've acquired 60 leases in the Gulf of Mexico, you know for Grand total of $120 million. So.
Very good price them, you know for all those leases.
And you know, it's really composed of three things.
Hey, ilex kind of near near infrastructure opportunities be Miocene greenfield of opportunities.
And then thirdly, you know the Cretaceous.
Play, which really get de risk by the Norphlet right because.
Everyone thought the north Norfolk was going to be tombstone and of course, you know shell and Chevron found.
Not only very high quality sands, but very thick fans and the Cretaceous sandwiched between the Miocene.
And the Norphlet, so obviously in order for crude to make it from the source.
Rock all the way to them I see that had to pass through both and were put in Cretaceous.
So to the prospects that are in the Cretaceous, which we got a good position as John said, we also.
Have a position that has you know partners so we de risk it.
But these are very large.
Hub class opportunities. So you know BP had galapagos into Q.
In 2020, given it's a large prospect.
Again sandwiched between the Norphlet and my seen in the Mississippi Canyon area. We said, we will go ahead and drilling.
So it's purely just a matter of where it came in the queue because again, we like all three opportunity sets we have ilex.
You know my scene and in this Cretaceous play.
Obviously, if crude prices move up we'll want to get back to work you know in the Gulf of Mexico on her on her own things and you know first in the queue is gonna be some of those ilex opportunities like you know a second well it he sox, but again, we need to see a little bit higher crude price before we do that.
We did galapagos because it if the opportunity was now so yes.
When you pick Galapagos prospect. The it was purely you know a a time issue and when we say preserve cash preserve capability preserve long term value of assets, obviously galapagos fits in that latter category, but there was a time constraint there.
At the same time, you know and displacing environment, we're going to focus on preserving the cash and our activity levels in the Gulf of Mexico are not anticipated.
To be very high until we get more visibility on oil prices and the oil market stabilizing and strengthening.
Okay, Great that was a very helpful explanation I appreciate it.
And then my other question was just.
Sounds good asset sales with yellowtail, expanding and seemingly exceeding expectations and jumping ahead of hammerhead acute.
'cause this supports selling down it enters and lower quality Guyana assets of the prize is right or is there no such thing is a guy on assets, it's going to be for sale.
Well you know our company is always looking to optimize the value of our portfolio, but you know one of the lowest cost highest return investments in the industry.
It is our position in Guyana.
We see a lot more running room there.
And it's actually something if we could get more of it we'd like more of it.
So no we don't have any interest in selling down.
So high return and low cost nothing competes with it in the industry.
Great. Thank you appreciate it.
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Thank you want to next question comes from Ryan Todd Semmens Energy Your question. Please.
Great. Thanks, maybe just a couple of quick.
Numbers related ones.
Just on.
On Capex, the second quarter, Capex is a little bit lower versus.
Guidance, despite a pretty solid number well completions in the Bakken.
What do you see non leading edge drilling and completion costs in the Bakken versus what you anticipated in your full year budget.
Oh.
Greg do you want me to take that yeah sure John Yeah, Okay. So from a well cost standpoint. If you saw we did DNC, we did drop our DNC cost is $6 million in the quarter. It was our goal to get there by the ended the year. So we did achieve that a bit.
Earlier, so we are getting some nice reductions there in the Bakken from that standpoint.
Cited that you know I think it's just the normal efficiencies Greg and his team are continuing to drive that down yes backing from within our original billion nine and what we guided from the last quarter is down a bit more from from the last quarter because of the efficiencies there.
But overall with the portfolio billion nine were seeing a little bit more now with the rigs back operating in Guy and it just a little bit more in the Guy N.S. So it's a nice offsetting keeps us at EUR <unk> billion nine capital spend.
Thanks, and then maybe just a quick one I mean, you mentioned when you provided guidance on that on cash Opex.
Our really really strong I'm a quarter this.
Is this primarily just a mixture of volume be issue or are there. Some there's some underlying downward pressure that you're seeing on cash cost.
Well so for the.
Q2, I mean production did come in approximately 20000 barrels a day above guidance, we really good performance across the portfolio from a production standpoint, and our costs on an absolute basis came in 10% lower than guidance and that was across the portfolio. So nothing in particular, but look in this environment day in day out we're looking.
To take more and more costs out and like we said earlier, we're continuing to look for further cost reductions and look to to add to that 265 million that I mentioned earlier.
Great. Thank you.
Thank you. Our next question comes from Devon Mcdermott of Morgan Stanley. Your question. Please.
Hey, good morning, Thanks for squeezing me in no Devon, Thanks, a lot.
I just had had a quick one to follow up actually on the last point it relates to some of the Bakken well cost reductions and looking at the 6 million. The you achieved the quarter over quarter changes is more on the completion side with the question specifically is when you look at the driver that reduction and meeting your year end target early is that more supply.
Why chain deflation driven based on what's going out on the industry or they are true structural improvements and efficiencies that you're you're finding and driving into the cost structure earlier than expected I'm trying to get to what's structural change your cost versus IP Gregg said, yeah sure. So.
Getting down to that 6 million two thirds of that with supply chain and one third is.
You know efficiencies further efficiencies.
I'm now as we look forward you know, there's probably going to be minimal supply chain.
Section so most of that we've already realized but as we look forward through further lean manufacturing applications and also technology. You know, we think we can get that cost down lower so we think next year there will be a five handle and the number first this is fixed.
Great I'll leave it there was one of the thanks, so much we all alone.
Thanks, a lot.
Thank you. Our next question comes from Apple mocking <unk> of Raymond James Your line is open.
Thanks for taking the question just one question for me a bit high level, though you talked about kind of avoiding moving some personnel from Texas to North Dakota as a precautionary measure more broadly, though can you just paint a visual picture of why you have been good.
Going to enforce.
Social distancing.
Your Bakken assets as well as in the Gulf of Mexico, obviously to two different facets of the portfolio. Yeah. There's significant protocols that are in place and we're very proud of our team to be operating safely and reliably during the Cove it.
I'll break, but Greg do you want to talk about the steps we've taken yeah sure. So you know certainly in the Bakken has the advantage of.
Being very spread out right.
But certainly we limit the size we people are allowed to gather in the same room.
And then what we're doing work. So for example on the on the Tioga expansion.
When we're doing work were confining the work.
Pot workers that are typically anywhere from six to 10 people.
And those people stay together and so we keep social distance between pods and organize the works that's that you don't expose.
You know I'm large numbers of the people right to each other.
So that's the way that we've approved to work that's we're very effectively.
The very well.
And the one.
Little Spike do we did see in Tioga was one pack and it was confined completely that part because of the practices.
That we used on the Gulf of Mexico, you know we require testing and then of course, you know a extended hitches offshore again to minimize you know exposure.
And also for crew changes or or kind of blitz, they used to be staggered.
But now there's one single crew change so that will you minimize exposure.
Well.
So as a result measures we've taken.
Where field operations are continuing to produce.
It would be appropriate safeguards.
So so far so good.
Thanks very much.
Thank you.
Thank you very much. This concludes todays conference. Thank you for your participation you may now disconnect have a great day.
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