Q2 2019 Earnings Call
My name is Amanda and I'll be your operator for today.
At this time all participants are in a listen only mode.
<unk>, we will conduct a question and answer session.
If at any time you require operator assistance. Please press star zero, and we'll 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 Amanda good morning, everyone and thank you for participating in our second quarter earnings Conference call.
Our earnings release was issued this morning and appears on our website www dot have stock comp.
Today's conference call contains projections and other forward looking statements within the meaning of the federal Securities laws.
These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements.
These risks include those set forth in the risk factor section of <unk> annual and quarterly reports filed with the FCC.
Also on today's conference call, we may discuss certain non-GAAP financial measures.
A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided provided on our website.
Now as usual with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and Sean Reilly, Chief Financial Officer, I'll now turn the call over to John Hess. Thank you Jay welcome to our second quarter Conference call I will provide a strategy update Greg Hill will then discuss our operating performance and John Reilly will review our financial results.
In the second quarter, we continue to execute our strategy and deliver strong operational performance with our full year production now expected to come in at the upper end of our guidance range and our capital and exploratory expenditures projected to come in under our original guidance.
Our portfolio, which is a balance between our growth engines in Guyana, and the Bakken and our cash engines in the deepwater Gulf of Mexico in the Gulf of Thailand is on track to generate industry, leading cash flow growth with a portfolio breakeven that is expected to decrease to less than $40 per barrel Brent by 2025.
A key driver of our strategy is our position in Guyana.
The 6.6 million acres, Stabroek block, where Hess has a 30% interest and Exxon Mobil is the operator.
Is a massive world class resource that is uniquely advantaged by its scale reservoir quality cost rapid cash paybacks and strong financial returns.
In April we announced our 13th discovery on the Stabroek block at Yellowtail.
The yellow toil number one well encountered approximately 292 feet of high quality oil bearing sandstone reservoir and is the fifth discovery in the turbo area, which is expected to become a major development hub.
Total discoveries on the Stabroek block to date have established the potential for at least five floating production storage and off loading vessels or f. dsos producing over 750000 barrels of oil per day by 2025.
Drilling an appraisal activities were completed at their hammerhead too and hammerhead three wells with encouraging results, including a successful drill stem test in July .
These results are being evaluated for potential future development.
Exploration and appraisal drilling continues on the block at the Triple tail prospect in the greater turbo area and that the Ranger discovery, where a second well is under way.
As a result of this year's discoveries and further evaluation of previous discoveries. We have increased the estimate of gross discovered recoverable resources for the stabroek block to more than 6 billion barrels of oil equivalent.
Up from the previous estimate of more than 5.5 billion barrels of oil equivalent and we continue to see multibillion barrels of additional exploration potential.
In terms of our developments lease a phase one continues to advance on July 18, the Lisa Destiny, Fps, So which has the capacity to produce up to 120000 gross barrels of oil per day.
Set sail from Singapore and is expected to arrive in Guyana in September .
First production is expected by the first quarter of 2020.
Phase two of the lease of development, which was sanctioned in May we'll use a second fps. So the Lisa unity with production capacity of up to 220000 gross barrels of oil per day startup is expected by mid 2022.
Planning is underway for a third phase at Pike, <unk>, which will use a F.P.S. so with the capacity to produce between 180000 to 220000 gross barrels of oil per day.
First production is on track for 2023.
In the Bakken, we have a premier acreage position and a robust inventory of high return drilling locations. We plan to continue operating six rigs.
Which is expected to grow net production to approximately 200000 barrels of oil equivalent per day by 2021, along with a meaningful increase in free cash flow generation over this period.
Now.
Turning to our financial results in the second quarter, we posted a net loss of $6 million or two cents per share compared to a net loss of $130 million or 48 cents per share in the year ago quarter.
On an adjusted basis, we posted a net loss of $28 million or nine cents per share compared with an adjusted net loss of $56 million or 23 cents per share in the second quarter of 2018.
Compared to second quarter 2018, our improved financial results, primarily reflect increased us crude oil production and reduced exploration expenses, which were partially offset by lower realized selling prices and higher DDNA expenses.
Second quarter net production averaged 273000 barrels of oil equivalent per day, excluding Libya.
Up from 247000 barrels of oil equivalent per day in the year ago quarter.
For the full year 2019, we forecast net production will average between 275000 280000 barrels of oil equivalent per day, excluding Libya, which is also at the upper end of our previous guidance range.
Second quarter net production in the Bakken averaged 140000 barrels of oil equivalent per day up 23% from 114000 barrels of oil equivalent per day a year ago.
For the full year 2019, we now forecast that the Bakken net production will average between 140000 to 145000 barrels of oil equivalent per day at the upper end of our previous guidance range.
Before closing I would like to note that we published our annual sustainability report earlier this month for the 22nd year, we believe sustainability practices create value for our shareholders and position us to continuously improve our business performance. Our sustainability report is available on our company website at Www Dot Hess dotcom.
In summary, we are successfully executing our strategy, which will deliver increasing and strong financial returns visible in low risk production growth and significant future free cash flow.
I will now turn the call over to Greg for an operational update.
Thanks, John I'd like to provide an update on our progress in 2019, as we continue to execute our strategy.
Starting with production in the second quarter net production averaged 273000 barrels of oil equivalent per day, excluding Libya.
Which was within our guidance for the quarter of 270000 to 280000 barrels of oil equivalent per day.
Strong performance across our operated portfolio.
Was partially offset by unplanned downtime at the shell operated into lot of facility in the deepwater Gulf of Mexico.
Which reduced our second quarter net production by approximately 4000 barrels of oil equivalent per day.
In the third quarter, we expect net production to average between 270000 and 280000 barrels of oil equivalent per day, excluding Libya.
As continued ramp up of the Bakken is expected to be partially offset by planned maintenance at our JV asset in southeast Asia, and the impact of Hurricane Barry in the Gulf of Mexico in early July .
Based on our year to date performance and our expectation of a strong production growth from the Bakken deepwater Gulf of Mexico, and Southeast Asia in the fourth quarter.
We now forecast full year 2019, net production to average between 275000 and 280000 barrels of oil equivalent per day, which is at the upper end of our previous guidance range.
Turning now to the Bakken.
Capitalizing on the success of our new plug and perf completion design, we delivered a strong quarter.
Second quarter Bakken net production averaged 140000 barrels of oil equivalent per day.
Which was at the top end of our guidance range of 135000 to 140000.
Net barrels of oil equivalent per day, and approximately 23% higher.
In the year ago quarter.
For the third quarter, we forecast our Bakken net production will average between 145000 and 150000 barrels of oil equivalent per day.
For full year 2019, we now forecast Bakken net production will average between 140000 and 145000 barrels of oil equivalent per day, which is also at the upper end of our previous guidance range.
In the second quarter, we brought 39, new wells online.
And then the third quarter, we expect to bring approximately 45, new wells online.
For the full year 2019.
We still expect to bring approximately 160, new wells online.
Moving to the offshore.
In the deepwater Gulf of Mexico.
Net production averaged approximately 65000 barrels of oil equivalent per day in the second quarter.
Reflecting planned maintenance activities at tubular bells and bold paid.
As well as an unplanned shutdown at the shell operated enchilada facility in the deepwater Gulf of Mexico.
Which resulted in a 22 day shut in of production and are Konger field.
In line with our strategy of investing in high return opportunities.
We are pleased to report that the Llano five wells in the Gulf of Mexico, where Hess has a 50% working interest.
Was successfully brought online in July .
And is expected to reach a gross production rate of between 8010 thousand barrels of oil equivalent per day in the fourth quarter.
Well was drilled and completed an approximately 60 days to weeks ahead of schedule.
In Southeast Asia.
Net production averaged approximately 59000 barrels of oil equivalent per day in the second quarter.
Reflecting a successfully completed planned shutdown for maintenance activities at North Malay basin.
As I mentioned earlier, we also completed a planned two week shutdown at the JV a last week and production is now back to pre shutdown levels.
Now turning to Guyana.
Our exploration success on the Stabroek block continues.
With three new discoveries so far in 2019 at Columbia.
Hi, Mara and yellowtail.
Bringing the total number of discoveries on the block thus far to 13.
We completed drilling operations on the hammerhead, two and three wells in June and July respectively.
Which included a successful drill drill stem test on hammerhead three.
And we're currently evaluating the results for potential future development.
The noble Tom Madden Drillship is currently drilling the intermediate section of one of the Liza Phase one development wells.
And we will then return to finish drilling the triple tail, one well with results expected in October .
The standard Karen Drillship recently commenced drilling of the range or two appraisal well.
Let's say follow up to the successful Ranger one exploration well.
Which in January 2018, established a large oil bearing carbonate structure.
Located approximately 60 miles northwest of the Liza field.
And extensive logging coring program as well as the drill stem test are planned for range or two.
Now turning to our Guyana developments.
Visa phase one is progressing as planned.
The Liza das in the FPSO, where the gross production capacity of 120000 barrels of oil per day.
Has departed Singapore and is expected to arrive in Guyana in September .
Drilling of the phase one development wells by the noble Bob Douglas Drillship.
Is proceeding to plan and the installation of subsea Umbilicals risers and flow lines is approximately 70% complete.
The project is on track to achieve first oil by the first quarter of 2020.
Liza phase II.
Sanctioned in May.
We utilized the Liza unity FPSO, where fabrication activities are currently underway.
Leaves the unity will have a gross production capacity of 220000 barrels of oil per day.
And we'll develop approximately 600 million barrels of oil.
First oil is expected by mid 2022.
A third phase of development at Pandora.
<unk> is expected to have a gross capacity of between 180000 and 220000 barrels of oil per day.
With first oil on track for 2023.
In closing.
Our offshore cash engines continue to generate significant cash flow.
The Bakken is on the strong capital efficient growth trajectory 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 for many years to come I will now turn the call over to John Reilly.
Thanks, Greg.
In my remarks today I will compare results from the second quarter of 2019 to the first quarter of 2019.
On an adjusted basis, which excludes items affecting comparability of earnings between periods, we incurred a net loss of $28 million in the second quarter of 2019.
Turning to S&P.
The price and volume variances between the second quarter and first quarter were immaterial.
The other changes in the after tax components of adjusted S&P earnings between the second and first quarter of 2019 were as follows.
Higher production and severance taxes decreased earnings by $7 million higher seismic expense in Guyana decreased earnings by $9 million.
Changes in foreign exchange decreased earnings by $8 million all other items decreased earnings by $12 million for an overall decrease in second quarter earnings of $63 million.
Turning to midstream.
The midstream segment had net income of $35 million in the second quarter of 2019 compared to $37 million in the first quarter of 2019.
Midstream EBITDA before non controlling interest.
Amounted to $127 million in the second quarter compared to $129 million in the previous quarter.
For corporate.
After tax corporate and interest expenses were $109 million in the second quarter compared to $114 million in the first quarter of 2019.
Turning to our financial position.
At quarter end cash and cash equivalents were $2.2 billion excluding midstream.
And total liquidity was $6.1 billion, including available committed credit facilities.
While debt and finance lease obligations totaled $5.7 billion.
During the second quarter, we entered into a new fully undrawn.
$3.5 billion revolving credit facility maturing in May.
2023, which replaced our previous credit facility that was scheduled to mature in January 2021.
Net cash provided from operating activities was $675 million, while cash expenditures for capital and investments were $640 million in the second quarter.
Changes in working capital increased operating cash flows by $115 million in the second quarter.
Now turning to third quarter and full year 2019 guidance for S&P.
Our S&P cash costs were $12, an 11 cents per barrel of oil oil equivalent including Libya.
And $12.72 per barrel of oil equivalent excluding Libya in the second quarter.
Our full year 2019 cash costs, excluding Libya are now expected to be $12.50 to $13 per barrel of oil equivalent which is down from previous guidance of 13 to $14 per barrel of oil equivalent.
DDNA expense, excluding Libya is forecast to be in the range of 18 to $19 per barrel of oil equivalent in the third quarter of 2019 with full year guidance unchanged at 18 to $19 per barrel of oil equivalent.
This results in projected total LP unit operating costs, excluding Libya to be in the range of 31 to $33 per barrel of oil equivalent for the third quarter and in the range of $30.50 to $32 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 $50 million to $60 million in the third quarter and full year guidance to be in the range of 200 million to $210 million, which is in the lower end of our previous guidance.
The midstream tariff is projected to be approximately $185 million for the third quarter.
With full year guidance expected to be $740 million to $750 million.
The increase in the third and fourth quarter tariff expense is due to an anticipated increase in midstream volumes driven by growing has production and increasing third party throughput with the startup 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 third quarter and for the full year.
Our crude oil hedge positions remain unchanged, we have 95000 barrels of oil per day hedged for calendar 2019 was $60 Dwt I put option contracts, we expect option premium amortization to be approximately $29 million per quarter for the remainder of the year.
NP capital and exploratory expenditures are expected to be approximately $800 million in the third quarter and $2.8 billion for the full year, which is down from original guidance of $2.9 billion.
For the midstream.
We anticipate net income attributable to Hess from the midstream segment to be approximately $40 million in the third quarter and in the range of 170 million to $175 million for the full year.
Turning to corporate for the third quarter of 2019 corporate expenses are estimated to be in the range of 25 million to $30 million and full year guidance to be in the range of 110 million to $115 million.
Interest expense is estimated to be in the range of 75 million to $80 million for the third quarter and full year guidance to be in the range of 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.
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.
Questions will be taken in the order received please press star one to begin.
Morning.
I Wonder if I could ask a couple in Guyana, and then just one on the Bakken.
On Guyana, Greg is probably for you the the what could you give us a little bit more color on the hammerhead appraisals, obviously there.
Kind of scan detailed in the release, but what does this mean for the potential.
I guess, an accelerated development I think that had been alluded to in the past, but to put both your exploration assets and then not bring forward a development seems.
A little bit unusual so.
Enough. The related question is when you described the yellow till turbo loan pool area as a major development hub, one assumes that doesn't relate to a single Sps or so it seems that we're kind of stocking up development visibility here I just wonder if you could offer any color on why we still haven't seen an uplift to the greater than 750 guidance for 2025.
Yeah.
Thanks, So let me take your.
First question so.
First of all the.
Hammerhead.
Well results for both hammerhead too and hammerhead three really demonstrated three things first of all both had high quality reservoirs.
The DSP on Hammerhead three showed very good mobility.
And finally, a very good count conductivity in the conductivity.
Uh huh.
Is actually between all three wells. So all three wells are in pressure communication, so that bodes well.
We are we are rolling all the data in earnest into into the studies as we speak.
Regarding your second question you are right, we do have a lot of volume now.
Underpinned really between the Liza complex and the turbo complex.
And we're also in earnest doing development studies on that area.
We're going to do some more exploration drilling really along that northeastern part.
The stabroek block between turbot or south eastern block between.
Between turbine and Lisa.
And we will drill.
Probably three potentially for.
Thanks for the clarity Greg My follow up is hopefully a quick one of you guys process a lot of third party volumes I believe on a payment in kind system in the Bakken.
My question really relates to the oil mix.
Relative to.
Excuse me, we should read through any material change to your expectations rolled mix going forward and your development area and I'll leave it there. Thanks.
In our mix going forward. So let me just talk first at a high level, our Bakken asset it is doing really well and it's in terms of I'll call. It production overall production capital and costs and specifically oil production.
So what we had during the quarter April and May were tough weather months and well availability was low but June was really strong end July has been really strong. So what we can tell you is we've always said we're in this low to mid Sixtys oil cut. So let me just take say 60, 364% you can feel comfortable using that number on our third quarter production guidance that we gave for Bakken and you can see there that we're going to have a very strong oil production increase from the second to the third quarter.
So all else being equal I would have said our overall production would have been in the 136 to 137 area within oil cut percentage in that 63% to 64%.
But now it gets to your.
I'll call it payment in kind on the on the gas processing fee. So we do have a percentage of our contracts at the tioga gas plant debt or percentage of proceeds or pop contracts and so what happened obviously between the first and second quarter with lower NGL and gas price gas prices, we receive more volumes for those contracts. So all else being equal we probably picked up three to 4000 barrels a day of Ngls and gas if you want to call. It barrels in the second quarter. So thats why the oil cut is showing where it is but let me just say going forward. We've always said, we're going to maintain this low to mid 60% oil cut all the way up to 200000 barrels a day. So we are right on track for the 200000 barrels a day the Bakken asset team is executing really well and the plug and perf wells are doing really well. So we're excited about the asset and the third quarter looks good.
Thank you and our next question comes from the line of Bob Brackett of Bernstein Research. Your line is open.
Good morning quick question on the east prospect in the gum can you give us an update on the status of that.
Yeah, Bob So we are poised to begin drilling that.
In the third quarter, so we will spud that well.
In the third quarter and Thats a tie back if successful that will be a tie back to tubular bells.
Great and then a follow up on Ranger too can you talk about what the purpose of the appraisal is it looks like that wells is pretty high up on the structure as opposed to the edge of the structure are you looking at sort of the reservoir quality or what are you testing for.
Well I think Bob you know the Ranger run well was drilled on the Leeward side.
It was drilled in a relatively safe position from a drilling standpoint.
The range or two well, we're actually going to move to the Windward side.
Of the historic carbonate reef, so we expect.
Higher prosody, because that's the portion of the reef fits that's was subjected to wave action and also.
Rainwater et cetera. So we're looking for reservoir quality, there, we want to do a DSP and that will help us.
Also establish connectivity.
Great. Thank you for that.
Thank you and our next question comes from the line of Roger read of Wells Fargo. Your line is open.
Yes. Thank you good morning.
I just wonder if we could come back to the change in the Capex guidance and maybe give us an idea of where the efficiencies are flowing through the roughly $100 million decline.
Roger I wish I had an easy just one off for you, but it really is across our portfolio. So it's been good execution. So this is this is in Bakken. It's in southeast Asia, Guyana costs have been have been quite good. So it really is across the portfolio same thing on the cash cost the reduction there from the 13 to $14 per BOE down to the 12 50 to $13 be a week, we're seeing it across the portfolio I guess, probably on the capital the biggest piece would be the Bakken, but it really is across the portfolio.
So, let's just call it a potpourri or something like that.
Yes, that's it.
That's a good thing.
All right and then.
Kind of like the rest of the crowd here I guess, let's let's talk Guiana.
As you think about the continued M&A process alongside the development.
I mean should we think about you being able to achieve as you go out I believe to 2025 for the exploration program being able to achieve everything you want on exploration with the existing rig fleet or do you think we'll see expansions there as.
Continued execution on the original five Sps says that are highlighted and then the ability to achieve all the exploration.
Yes, so Roger we do plan to add.
Hey, fourth drillship to the theater and that will be initially focused on exploration on the stabroek block.
In the in the fourth quarter.
Obviously as we begin to get into.
Phase two drilling et cetera, there will be a couple of rigs drilling development wells at that point in time, but these rigs are going to be flexible theyre going to move from M&A work, depending on success might move over to developments for well come back to in a so we are developing a great plan to get everything we want to get done from an M&A standpoint.
In time.
Before.
Exploration of the block. So we are we are developing a plan to do all of that.
All right. Thank you.
Thank you.
Next question comes from the line of Brian singer of Goldman Sachs. Your line is open.
Thank you good morning.
Good morning.
Just a couple of additional follow up questions on Guyana, and the first does relate to the exploration you meant you Matt you mentioned that some of the wells.
That are going to be drilled or in the southeast corner.
Upcoming can you just talk a little bit more beyond Ranger and there if you see any.
Step out locations that you plan to drill with this with this fourth rig or otherwise over the next year and and specifically away from the.
Either between Ranger and leaves or.
A step out away from away from Ranger into potentially new new structures covenants or not.
No. So let me just again lay out the the kind of drilling sequence for the next six months. So first of all we're going to drill the range or two appraisal well.
And then follow that with an extensive logging coring program and DST. So the rig will be on that location for a fair amount of time.
The next rig, we'll see but go back to the triple tail well, so that's going to be the first.
Exploration well.
In the second half of the year and then beyond that we anticipate two or three additional exploration wells to have but before the end of the year.
With as I mentioned earlier, the focus really being on drilling out the southeast part of the block.
Between.
Between.
Turbot and Liza so really defining that.
Southeastern corner or the block and obviously that.
Is so that we can plan or developments down there how many ships and how do we sequence them.
Et cetera, and then looking beyond that of course.
In 2020 will will but.
Well in tighter block as well.
And then also on the health side, we will have a block 42, well in Suriname in 2020 also.
But I think it's important that we continue to add to the inventory of exploration prospects on the block that represent multibillion barrels of upside so theres going to be an extensive DNA program over the next several years in Guyana for sure.
Thats, great and my follow up is with regards to some of the discoveries that at least initially ship gas condensate that you've made like high Mark can you just talk about any.
New debt or planning that you've seen and how you think about monetization there.
Oh, I think that that's being rolled into our overall block development plans and.
When and how high Maura plays in.
Not not sure yet it certainly in the queue.
But as far as sequencing not clear yet and part of it is we want to appraise some more.
And explore some more in and around that.
Hi, Mara hub.
And the next 18 months will say.
Great. Thank you.
Thank you and our next question comes from the line of Paul Sankey of Mizuho. Your line is open.
Hi, good morning, everyone.
Greg I guess that was a very much a variation on on on the same in terms of the exploration success in the.
Sort of luxury problem you have in Guyana is there a point at which the simply too much inventory.
And as you change plans accordingly, or is the very long term potential nature of this development really mean that.
Levels of activity that you've really quick clearly outlined.
A fairly.
Stable and really anticipating major discoveries the full.
Plans don't change.
Yeah, Paul a excellent question no. We're taking a phased approach here, which we think is the most capital efficient one and it will.
Maximize our financial returns so so actually from a financial return perspective, the roadmap that we've laid out which is you know getting Lisa to on in mid 2022. After at least a one which actually is running ahead of schedule.
On in the first quarter of 2020 that will be followed by pie Yara in 2023, and then you know the exploration and appraisal program that Greg is talking about is going to give us further definition about a fourth ship, which would probably be a year. After pie, our NFS ship, which would probably be a year after that one and that really gives you. The line of sight for the five ships. The exact sizing of the fourth and fifth ship is the reason we are doing the exploration and appraisal program. So we're very comfortable about the financial requirements for that and we're very excited about the financial returns. We are getting from that obviously further exploration drilling may have an impact on those ships in terms of sequencing.
And also identify further ships, but it's very manageable formal financial perspective, and we and Exxon and seen oak are totally aligned about maximizing value from this opportunity that we have.
Thank you John .
If I could ask a follow up we've heard a little bit of volatility and so in this process regarding oil markets can you just update us on your latest thoughts for how Diana will impact.
Gulf Gulf oil markets, given how things have changed over the past couple of years. Thank you.
Well.
No I think Guyana being a very low cost development with the first ship, having a breakeven Brent price of $35, a barrel and the second ship, having a breakeven price of $25 a barrel, they're going to be very well situated to fit into the world oil market. The world oil market. As you know is very much determined by demand and supply.
The headwinds that we've had and GDP growth worldwide are obviously, having an impact on demand growth demand still growing but at a slower rate as GDP grows at a slower rate and then how shale how these new developments and how OPEC oil intersect to keep the market balanced to have a price high enough for investment.
And low enough for demand growth is obviously something thats unfolding. So volatility is something we have to live with and obviously, that's why we want to build a portfolio that has a low cost for barrel. So we have resilient returns in almost any price environment.
Thank you Joe.
Thank you and our next question comes from the line of Paul Cheng of Scotia, Howard Weil. Your line is open.
Hey, guys good morning.
Hey, Paul.
Couple questions.
I know, it's still early but the one to look at the preliminary outlook for 2020 Capex.
I suppose that we should see.
The Bakken expense to be up.
On the food yield to six rate.
And then also that the guy in the spending puppy, we'd be up.
Given that the phase two spending is going to ramp up probably pay to substantially. So maybe John you can help what's that to look that in those items that are how that delta is going to change.
Sure Paul.
Obviously, we will give our guidance.
For 2020 as poor as per our normal practice in late 2019 or early 2020, but I think you can go back to our Investor day in December 2018, and we laid out the plan that John just talked about as well.
So based on that we do expect that capital and exploratory spend for 2020 to be approximately $3 billion as we head had laid out to your specific question. So Bakken, what's going to happen with Bakken, we have six rigs this year in Bakken and we'll have six rigs next year and then we go down to the four rigs that we talked about in 2021 and generate that billion dollars to free cash flow. So the activity level is the same from that standpoint.
So we're not expecting any any big increases.
They're in the Bakken and obviously as we talked about we've been getting some nice efficiencies there.
Guyana, Yes, that's as you know were coming in at 2.8 billion. This year. That's what we had expected per the Investor day that there would be some increase in Guyana and that will be the AD and we're perfectly comfortable with that exactly as John has just laid out and the timing of that with.
Phase two coming on in mid 2022 so.
Everything is going along according to plan Bakken is executing well the 200000 barrels a day, we're a quarter closer to starting up in Guyana, and so you can expect that type of guidance when we get to 2020.
Okay on to.
A quick one on one.
Thing you opened leaf spine 6000 Boe per day, maybe I missed it in your prepared remarks, once to earning and cash flow contribution for the quarter and second the Jonas you.
That integrate mico need that.
With the phase one coming on stream next year.
And so from that standpoint.
And with.
Say you have a pretty strong balance sheet at this point.
Is it really necessary for us to have the hedging.
What is the future hedging strategy going to look like.
Sure So just starting with the.
Overlift.
You can probably tell by our tax line at one of the big over lifts was was in Libya. So overall, we had about let me just call. It 200000 barrels a day for in Libya, We had 200000 barrels a day in Denmark, and we also had a 200000 barrels a day overlift with J.D.A. offset by North Malay basin being under 200000 barrels. So what happened is just from an overall earnings standpoint, it was immaterial since Libya and Denmark driving that.
Overlift. So so nothing material there then as far as as we're looking on yes with.
Our.
Our program that we have going forward, we do intend to to put hedges on for 2020, we just think it's a prudent thing to do as we just discussed are John has just discussed the oil price volatility. So it's just something that we want to do from an insurance standpoint to make sure that we execute it we can execute this great program that we have so you can expect us to to.
Subject to market conditions to adding hedges for 2020.
On that.
The only comment I would make is that.
Seems like everyone. Most Monday over the long haul again hedging so I'm not sure what that is really for the benefit for the shareholder.
Anyway. Thank you.
Thank you and our next question comes from the line of and Shahram of JP Morgan. Your line is open.
Yes. My first question is for Greg Greg I was wondering.
You did 39 wells in the Bakken in Twoq and I was wondering if you guys have tested.
Some of the areas such as Goliat, the red Sky or some of the areas perhaps outside of your core.
Development area keen et cetera.
Yes so.
First of all let me say that we have and we don't have a lot of wells out there yet.
But what I will say is that the wells drilled to date.
In those areas are meeting expectations.
Thats with returns in the order of 40% to 50% it at $60 a barrel.
Our plan for those areas in 2019 is to drill about 25 wells.
And we're going to be testing kind of different completion designs and well spacing in order to try and further optimize our development in these areas.
As you recall, we've got at least a 15 year inventory of wells that exceed 50% are ours at $60 a barrel.
And I expect with the optimization that we're going to do this year.
In those areas like the Lion and Red Sky that I expect that inventory is probably going to grow.
As a result of that optimization.
Great. Thanks, a lot and this one for John Reilly, John You gave us some great color.
On.
On overall production guidance and as well as your thoughts on the Bakken oil mix could you help us.
With your thoughts on a range of oil production versus the B.B. OE total for Q3 and Q4.
So if you were looking at where we were kind of the first two quarters and you are saying overall production. We we had our oil was 52% of our production in the first quarter was 52% in the second quarter. So I would I would say are you doing and this is overall I'm talking about overall right total company guidance. So for the third quarter I would expect it to go up.
Slightly driven by good Bakken oil production growth.
Fair enough and just sneak one more in the Yano is it the number five well.
Can you remind us what kind of production impact that will be on a net basis.
Yeah. So on a gross basis it will be between eight and 10000 barrels a day in the fourth quarter and we have half of that so that would be half of that.
Great. Thanks, a lot.
Thank you and our next question comes from the line of Jeffrey Campbell of Tuohy Brothers. Your line is open.
Good morning.
The press release mentioned improved well performance in the Bakken I was just wondering was this anticipated from the shift to plug and perf or was this something in addition to that.
No I think this was really referencing the the shift to plug and perf.
And those are delivering again about a 15% increase in IP 180.
And a five for 5% to 10% increase in you are versus our previous sliding sleeve design and.
And our whole program for 2019.
On average eurs are going to be about a million barrels might be one eightys between 120 125.
And the our hours, it's fixed fee between 60 and 100% for the program this year so.
Very strong program and we're extremely pleased with the results in the Bakken is is doing very well.
Okay, Thanks, and referring to the slide 21 of the main presentation discussed tighter well spacing for higher Bakken.
Net present value.
For the drilling acreage.
I was just wondering have you settled on optimal spacing in your core areas are you still testing closer spacing in certain areas.
No I think I think that the nine and eight configuration in the core.
We're pretty settled on I think the optimization that could occur.
Because as you get down to do you know.
Tier two acreage all call it although it's all really good acreage.
You might actually widen spacing as you get out there and why do I say that because our objective is to maximize the issue in PV.
So it's going to be that equation of proppant loading well spacing et cetera to basically maximize the two NPV. So you might change the well spacing you may not be as tight as you go out into the into the other acreage.
Okay. If I sneak one last one on there just going back to hammerhead real quick I was just wondering are there any further hammerhead tests and the current plans or the three wells that you've discussed sufficient to determine next steps.
Yeah, I think I think we've got enough well data and evaluation data to determine next steps.
Okay, great. Thanks.
Appreciate it.
Thank you and our next question is from the line of Cavallo Mckinnell of Raymond James Your line is open.
Thanks for taking the question, it's not a huge part of your US production mix, but you did have 17 bcf of gas last quarter and in that context with Henry hub.
Now hovering around two box, obviously Bakken pricing is below that what's the point, where you might resort to shutting in wells.
No we don't see us shutting in wells there so.
So again, you know a lot of what we have is associated gas with our with our Bakken wells. So we wouldn't be shutting in anything also you have to remember.
The Bakken gas stream has probably three times the amount of liquids in it.
Than most other shale wells, so as a consequence, I and the rest of the country. We were in a pretty good position positioned to optimize our netbacks, even though the natural gas price and NGL prices are down theres still accretive to our overall netbacks.
Okay and in that same context.
What's your stance on on flaring and the latest status update on that.
Yeah, we are we are well within.
Regulatory requirements and I think in particularly as LM for South of the river gas plant comes on or joint venture with target.
Which is actually imminently.
On.
That will substantially drop our flaring south of the river and we will be substantially below regulatory requirements at that point in time. So flaring is not an issue for us is not a problem for us.
Particularly we halen for.
Okay.
Appreciate it.
Thank you very much. This concludes today's conference. Thank you for your participation you may now disconnect.
Have a great day.