Q4 2020 Hess Corp Earnings Call
Good day, ladies and gentlemen, and welcome to the fourth quarter 2020, Hess Corporation Conference call.
My name is Andrew and I will be your operator for today.
At this time all participants are in a listen only mode. Later, we will conduct a question and answer session. If at any time you require operator assistance. Please press star followed by zero and we'll be happy to assist you.
As a reminder, this conference is being recorded for replay purposes.
I'd now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.
Thank you Andrew Good morning, everyone and thank you for participating in our fourth quarter earnings Conference call.
Our earnings release was issued this morning and appears on our website www Dot Hess Dot com.
This 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 factors section of Hess is annual and quarterly reports filed with the S. E C.
Also on today's conference call, we may discuss certain non-GAAP financial measures a reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.
As we have done in recent quarters, we will be posting transcripts of each speaker's prepared remarks on our website following the presentation.
As usual on line with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Reilly, Chief Financial Officer, I will now turn the call over to John Hess.
Thank you Jay.
I would like to welcome everyone to our fourth quarter Conference call I Hope you and your families are well and staying healthy during these challenging times today I will review our continued progress in executing our strategy then Greg Hill will discuss our operations and John Riley will review our financial performance.
Our strategy has been and continues to be to grow our resource base have a low cost of supply and sustained cash flow growth. Our differentiated portfolio is balanced between short cycle and long cycle assets with our focus on the best rocks for the best returns.
The Bakken deepwater Gulf of Mexico, and Southeast Asia are our cash it.
In Guyana is our growth engine.
Guyana becomes a significant cash engine as multiple phases of low cost oil developments come on line.
Which we believe will drive our company's breakeven price to under $40 per barrel, Brent and provide industry, leading cash flow growth over the course of the decade.
As our portfolio generates increasing free cash flow, we will first prioritize debt reduction.
And then increased cash returns to shareholders through dividend increases and opportunistic share repurchases.
Turning to 2020, we achieved strong operating results overcoming difficult market conditions and the challenges of working safely in the pandemic.
I am extremely proud of our work force for delivering production in line with our original guidance, despite a 40% reduction in our capital and exploratory expenditures.
In response to the pandemic severe impact on oil prices, our priorities have been to preserve cash preserve our operating capability and to preserve the long term value of our assets in.
In terms of preserving cash we came into 2020 with approximately 80% of our oil production hedged with put options for 130000 barrels per day at $55 per barrel West, Texas intermediate and 20000 barrels per day at $60 per barrel Brent.
To enhance cash flow and maximize the value of our production last March and April when U S. Oil storage was near capacity, we chartered three very large crude carriers, a real C. CS to store approximately 2 million barrels each of May June and July Bakken crude oil production.
The first VLCC cargo of 2.1 million barrels was sold in China at a premium to Brent in September.
And the second and third VLCC cargoes have been sold at a premium to Brent for delivery in the first quarter of 'twenty 'twenty one.
We reduced our capital and exploratory spend for 2020 by 40% from our original budget of $3 billion down to $1.8 billion. The majority of this reduction came from dropping from a six rig program in the Bakken to one rig we also reduced our 2020 cash operating costs by two.
$275 million.
In 2020, we strengthened the company's cash and liquidity position through a $1 billion three year term loan initially underwritten by J P. Morgan Chase.
In addition, we have an undrawn $3 5 billion revolving credit facility and no material debt maturities until 2023.
During the fourth quarter, we closed on the sale of our 28% interest in the Shenzhen field in the Gulf of Mexico for a total consideration of $505 billion, bringing value forward in the low price environment.
In terms of preserving capability a key for us in 2020 was continuing to operate one rig in the back.
Greg Hill at our Bakken team have made tremendous progress over the past 10 years, it lean manufacturing capabilities and innovative practices, which have 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.
<unk> with its low cost of supply and industry, leading financial returns remains our top priority.
On the Stabroek block, where Hess has a 30% interest and Exxonmobil is the operator 'twenty 'twenty was another outstanding year.
Three oil discoveries during the year at Wawa Red tail, one and yellow tail to brought total discoveries on the stabroek block to 18.
The estimate of gross discovered recoverable resources on the block was increased to approximately 9 billion barrels of oil equivalent and we continue to see multibillion barrels of future exploration potential remaining.
In December production from Liza Phase one reached its full capacity of 120000 gross barrels of oil per day.
The Liza phase two development is on track to achieve first oil in early 'twenty 'twenty two with a capacity of 220000 gross barrels of oil per day.
Another key Twenty-twenty milestone was the sanctioning of our third oil development on the Stabroek block in September at the pie or a field.
<unk> will have a capacity of 220000 gross barrels of oil per day and is expected to achieve first oil in 2024.
Turning to our plans for 'twenty and 'twenty one to protect our cash flows we have hedged a 100000 barrels per day with $45 per barrel W. T. I put options and 20000 barrels per day with $50 per barrel Brent put options.
Our 'twenty 'twenty, one capital and exploratory budget is $1.9 billion of which more than 80% will be allocated to Guyana and the Bakken.
Our three sanction to oil developments on the Stabroek block have breakeven Brent oil prices of between 25 and $35 per barrel.
World class by any measure.
Front end engineering and design work for our fourth development at the yellow tail area is underway.
And we hope to submit the development plan to the government for approval before year end.
We continue to see the potential for at least five F. P. S owes to produce more than 750000 gross barrels of oil per day by 2026 and longer term for up to 10 F. P. S owes to develop the current discovered recoverable resource base.
We will continue to invest in an active exploration and appraisal program in Guyana in 2021 with 12 to 15 wells planned for the block.
The horse has a number one exploration well recently encountered approximately 50 feet of oil bearing reservoir in deeper geologic intervals, although the well did not find oil in the primary shallower target areas. The haso well results confirm a working petroleum system.
And provide valuable information about the future exploration prospects for this part of the block.
In the Bakken, we plan to add a second rig during the first quarter, which will allow us to sustain production in the range of 175000 barrels of oil equivalent per day for several years and protect the long term cash flow generation from this important asset.
As we continue to execute our strategy our board our leadership team and our employees will be guided by our long standing commitment to sustainability and the Hess values. We are proud to have been recognized throughout 2020 by a number of third party organizations for the quality of our environmental social and governance.
<unk> performance in disclosure and.
In December we achieve leadership status in Cdp's annual global climate analysis for the 12th consecutive year and earned a place on the Dow Jones sustainability Index for North America for the 11th consecutive year.
In summary, our priorities will remain to preserve cash preserve capability and preserve the long term value of our assets by investing only in high return low cost opportunities. We have built a differentiated portfolio of assets that we believe will provide industry, leading cash flow growth for over the course of.
The decade as our free cash flow grows we will first prioritize debt reduction and then return of capital to shareholders. Both in terms of dividends and opportunistic share repurchases I will now turn the call over to Greg for an operational update.
Thanks, John I also hope that everyone on the call is well and staying safe.
2020 marked another year of strong performance and strategic execution for Hess, despite the challenging conditions on many fronts in.
In particular, I would like to call out several operational highlights from the year.
First across our company we.
We have implemented comprehensive COVID-19 health and safety measures.
Including health screenings, and testing extended work schedules and offshore platforms and social distancing initiatives, all based on government and public health agencies guidance I'm truly grateful to our enhanced response.
<unk> team and our global work force.
Their commitment to keeping their colleagues and our communities safe during this pandemic.
Second.
In the Bakken despite dropping from six rigs to one in May.
Our full year net production came in well above our original guidance for the year and 27% above that of 2019. These.
These results reflect the strong performance of our plug and perf completions increased natural gas capture.
And the quality of our acreage position.
Third in Guyana.
We made significant advances on all three of our sanction developments on the Stabroek block.
With Liza phase one.
Its full production capacity in December Liza phase two remaining on track for first oil early next year.
And pay our sanctioned in September with first oil expected in 2024.
Continued exploration and appraisal success increase the gross recoverable resource estimate for the block to approximately 9 billion barrels of oil equivalent.
Now turning to our operations.
Proved reserves at the end of 2020 stood at 1.17 billion barrels of oil equivalent.
Net proved reserve additions in 2020.
<unk> totaled 117 million barrels of oil equivalent.
Including negative negative net price revisions at 79 million barrels of oil equivalent which resulted in an overall 2020 production replacement ratio of 95 per cent and finding and development cost of $15.25 per barrel of oil equivalent.
Excluding price related revisions.
Our production replacement ratio was 158% with an F&D cost of $9.10 per barrel of oil equivalent.
Turning to production.
In the fourth quarter of 2020 company wide net production averaged 309000 barrels of oil equivalent per day, excluding Libya.
Above our guidance of approximately 300000 net barrels of oil equivalent per day, driven by higher natural gas capture in the Bakken and higher natural gas nominations in southeast Asia.
For the full year 2021.
We forecast net production to average approximately 310000 barrels of oil equivalent per day, excluding Libya for.
For the first quarter of 2021, we forecast net production to average approximately 315000 barrels of oil equivalent per day.
Excluding Libya.
In the Bakken.
Fourth quarter net production averaged 189000 barrels of oil equivalent per day, an increase of approximately 9%.
Above the year ago quarter and above our guidance of 180000 to 185000 net barrels of oil equivalent per day.
For the full year 2020.
Bakken net production averaged 193000 barrels of oil equivalent per day, an increase of approximately 27%.
Compared to 2019, and well above our original full year guidance of 180000 barrels of oil equivalent per day, despite dropping from six rigs to one in may.
We have a robust inventory of more than 1800 drilling locations in the Bakken.
Can generate attractive returns at current oil prices, representing approximately 60 rig years of activity.
With W. T. I price is now in the range of $50 per barrel.
We will add a second operated drilling rig during the first quarter.
A two rig program.
It will enable us to hold net production flat at approximately 175000 barrels of oil equivalent per day and will sustain strong long term cash generation from this important asset.
In 2020.
Our drilling and completion costs per Bakken, well averaged $6 $2 million.
Which was $600000 or 9% lower than 2019.
In 2021, we expect D&C costs to average below $6 million per well.
Over the full year, we expect to drove 55 gross operated wells.
And bring approximately 45, new wells online.
This compares to 71 wells drilled and 111 wells brought online in 2020.
In the first quarter of 2021.
We expect to drill approximately 10 wells and bring four new wells online.
Bakken net production is forecast to average approximately 170000 barrels of oil equivalent per day.
For both the first quarter and for the full year 2021.
For your forecast reflects the impact of a planned 45 day shutdown from the Tiger gas plant in the third quarter.
Which is expected to reduce full year net production.
By approximately 7500 barrels of oil equivalent per day predominantly affecting natural gas production.
During the shutdown, we will perform a turnaround and tying the plant expansion project completed in 2020.
Which will then increase capacity to 400 million cubic feet per day from.
From the plants current 250 million cubic feet per day capacity.
Now moving to the offshore.
In the deepwater Gulf of Mexico, net production averaged 32000 barrels of oil equivalent per day in the fourth quarter and 56000 barrels of oil equivalent per day for the full year 2020.
Fourth quarter net production came in below our guidance of 40000 barrels of oil equivalent per day due to the early closing of the chassis sales.
And extended Hurricane recovery downtime at two third party operated production platforms.
In 2021, no new wells are planned in the deepwater Gulf of Mexico, and we forecast net production from our assets to average approximately 45000 barrels of oil equivalent per day.
This includes the impact of planned maintenance shutdowns in both the second and third quarters.
The deepwater Gulf of Mexico remains a very important cash engine for the company as well as a platform for future growth.
In Malaysia, and the joint development area in the Gulf of Thailand, where Hess has a 50% interest.
Net production averaged 56000 barrels of oil equivalent per day in the fourth quarter.
52000 barrels of oil equivalent per day for the full year 2020.
Fourth quarter production was above our guidance of 50000 barrels of oil equivalent per day because of higher natural gas nominations.
For the full year 2021.
Net production from Malaysia, and the J D a.
Our cash to average approximately 60000 barrels of oil equivalent per day.
Turning to Guyana.
Where hess has a 30% interest in the Stabroek block and Exxonmobil is the operator.
In 2020, we announced three new discoveries, bringing the total number of discoveries to 18 and increasing our estimate of gross discovered recoverable resources to approximately 9 billion barrels of oil equivalent.
And we continue to see multibillion barrels of exploration upside on the Stabroek block and we are planning an active exploration program in 2021.
In March.
The operator will bring a fifth drillship the standard drill Max into theater and in April 6th Drillship, The noble Sam Croft.
We plan to drill 12 to 15 exploration and appraisal wells in 2021 day.
It will target a variety of prospects and play types.
These will include lower risk wells near existing discoveries.
Higher risk step outs.
Several penetrations that will test deeper lower campaigning and San Antonia and intervals.
This ramped up program will allow us to accelerate exploration in the block and enable optimum optimum sequencing future developments.
In addition, the emerging deep play, which we believe has significant potential needs further drilling to determine its commerciality and ultimate value.
Over the next several months, we will participate in two exploration wells and two appraisal wells on the state book block.
The next exploration well to be drilled as cocoa VB one.
Which is located approximately 16 miles northeast of Liza.
This well will target Liza type campaigning aged reservoirs.
And is expected to spud in February using the Stena Carron drillship.
In March we expect to spud the long tailed three appraisal well.
Which will provide additional data in the turbot long tail area, and we will drill a deeper section that will target lower campaigning and San Antonia and geologic intervals.
Standard drove Max we'll drill this well.
Moving to April.
We expect to spud the war room, two appraisal well utilizing the noble Don Taylor drillship.
Success here and it May go too, which will be drilled later this year could move the Mako one area of forward in the development queue.
Then in May we plan to spud the whip tail, one exploration well located approximately 12 miles east of Liza.
This well will test campaigning and San Antonia and aged reservoirs and will be drilled by the strength by the standard drill Max.
Turning now to our Guyana developments.
In mid December the Liza Destiny floating production storage and Offloading vessel achieved.
Achieved its nameplate capacity of 120000 gross barrels of oil equivalent per day and since then has been operating at that level or higher.
During 2021, the operator intends to evaluate and pursue options to increase nameplate capacity.
For 2021, we forecast net production from Guyana.
We will average approximately 30000 barrels of oil per day with planned maintenance and optimization downtime being broadly offset by an increase in nameplate capacity.
The Liza phase two development remains on track for first oil in early 2020 to the.
The overall project, including the <unk>, so drilling and subsea infrastructure is approximately 85% complete.
We anticipate that the Liza unity, <unk>, which will have a capacity of 220000 gross barrels of oil per day.
Sales from the Keppel shipyard in Singapore to Guyana by mid year.
<unk>, our third sanctioned development on the Stabroek block.
<unk> will utilize an F BSO with a gross production capacity.
220000 gross barrels of oil per day with first oil expected in 2024.
The whole for the prosperity BSO is complete.
Top site construction activities are underway and we expect the integration of the hull and top sites to begin at the Keppel yard in Singapore by year end.
Front end engineering and design work is ongoing for our fourth development at yellow tail. This.
This work will continue through 2021, and we anticipate being ready to submit a plan of development to the government of Guyana for approval in the fourth quarter.
In closing our execution continues to be strong the.
The Bakken and our offshore assets in the deepwater Gulf of Mexico, and Southeast Asia are performing well and continue to generate significant cash flow.
In Guyana continues to get bigger and better all of which positions us to deliver industry, leading cash flow growth and significant shareholder value over the course of the next decade I will now turn the call over to John Reilly.
Thanks, Greg in my remarks today, I will compare results from the fourth quarter of 2020 to the.
Third quarter of 2020 and provide guidance for 2021.
We incurred a net loss of $97 million in the fourth quarter of 2020, compared with a net loss of $243 million in the third quarter of 2020.
On an adjusted basis, which excludes items affecting comparability of earnings between periods, we incurred a net loss of $176 million in the fourth quarter of 2020 compared to a net loss of $216 million in the previous quarter.
Fourth quarter results include an after tax gain of $79 million from the sale of our interest in the <unk> field.
Turning to E&P.
On an adjusted basis E&P incurred a net loss of $118 million in the fourth quarter of 2020 compared to a net loss of $156 million in the previous quarter. The after tax changes in adjusted E&P results between the fourth quarter and third quarter were as follows.
Higher realized selling prices improved results by $18 million.
Higher sales volumes improved results by $11 million.
Lower DD&A expense improved results by $40 million.
Lower exploration expenses improved results by $12 million.
Higher cash costs, driven by Workovers and hurricane related maintenance costs in the Gulf of Mexico reduced results by $41 million.
All other items reduced results by $2 million for an overall increase in fourth quarter results of $38 million.
Our E&P operations were overlooked it compared with production in the fourth quarter by approximately one 6 million barrels, resulting in an increased after tax income of approximately $15 million.
Turning to midstream.
The midstream segment had net income of $62 million in the fourth quarter of 2020 compared to net income of $56 million in the previous quarter midstream.
Midstream EBITDA before non controlling interests amounted to $198 million from the fourth quarter of 2020 compared to $180 million in the previous quarter.
Turning to corporate.
After tax corporate and interest expenses were $120 million in the fourth quarter of 2020 compared to an adjusted after tax expense of $116 million in the previous quarter.
Turning to our financial position at quarter end, excluding midstream cash and cash equivalents were approximately $1 $74 billion and our total liquidity was $5 4 billion, including available committed credit facilities, while debt and finance lease obligations totaled.
Six $6 billion.
Our fully Undrawn $3 5 billion revolving credit facility is committed through May 2023.
In November 2020, we completed the previously announced sale of our 28% working interest in the <unk> field in the deepwater Gulf of Mexico for net proceeds of $482 million.
Net cash provided by operating activities before changes in working capital was $532 million in the fourth quarter of 2020, compared with $468 million in the previous quarter, primarily due to higher crude oil sales volumes.
In the fourth quarter net cash provided from operating activities. After changes in working capital was $486 million compared with $136 million in the prior quarter.
Proceeds from the September sale of the first VLCC cargo of $2 1 million barrels of oil were received in October.
We have entered into agreements to sell the second and third VLCC cargoes totaling $4 2 million barrels of oil in the first quarter of 2021.
We expect to recognize net income of approximately $60 million in the first quarter from these sales, including associated hedging gains and costs.
First quarter 2021, net cash provided by operating activities. After changes in working capital is expected to include approximately $150 million of cash flow from these sales.
For calendar year 2021, we have purchased WT I put options for 100000 barrels of oil per day that have an average monthly floor price of $45 per barrel and Brent put options for 20000 barrels of oil per day that have an average average monthly price floor price of $50 per barrel.
Now turning to guidance.
First for E&P.
We project E&P cash costs, excluding Libya to be in the range of $10 50.
To $11 50.
Per barrel of oil equivalent for the first quarter and for the full year 2021.
DD&A expense, excluding Libya is forecast to be in the range of 12 to $13 per barrel of oil equivalent for the first quarter and for the full year 2021.
This results in projected total E&P unit operating costs, excluding Libya to be in the range of $22 50 to $24 50 per barrel of oil equivalent from the first quarter and for the full year 2021.
Exploration expenses, excluding dry hole costs are expected to be in the range of $30 million to $35 million in the first quarter and $170 million to $180 million for the full year 2021.
The midstream tariff is projected to be in the range of $265 million to $275 million in the first quarter and one point <unk> nine to 112 billion for the full year 2021.
E&P income tax expense, excluding Libya is expected to be in the range of $30 million to $35 million for the first quarter and $80 million to $90 million for the full year 2021.
As highlighted earlier, we have purchased crude oil hedge positions for calendar year 2021 weeks.
We expect non cash option premium amortization, which will be reflected in our realized selling prices to reduce our results by approximately $37 million per quarter.
Our E&P capital and exploratory expenditures are expected to be approximately $425 million in the first quarter at approximately $1 9 billion for the full year 2021.
From midstream.
We anticipate net income attributable to Hess from the midstream segment to be in the range of $70 million to $80 million in the first quarter and $280 million to $290 million for the full year 2021.
For corporate corporate expenses are estimated to be in the range of $35 million to $40 million for the first quarter and $130 million to $140 million for the full year 2021.
Interest expense is estimated to be in the range of $95 million to $100 million for the first quarter and $380 to $390 million for the full year 2021.
This concludes my remarks, we will be happy to answer any questions I will now turn the call over to the operator.
Thank you ladies and gentlemen, if you have a question. Please press star followed by one on your phone.
If your question has been answered or you would like to withdraw your question press pound.
Questions will be taken in the order received please press star one to begin.
Our first question comes from the line of Janine way with Barclays.
Hi, Good morning, everyone. Thanks for taking my question good morning.
My questions are on Guyana, My first one is the Stena Carron drillship completed appraisal work at the Red Hill, well do you have any color on the appraisal results and I think it was supposed to include a drill stem test, but I'm not sure on the status of that.
Yes, Greg.
Thank you Janine first of all the results of the.
Red tail, well and the standard path for very positive and so what it does is it really confirms.
Our excitement about the large.
Volume of very high quality.
Reservoir and reservoir fluids in and around what I call the greater to yellow tool area and that's that's a big reason why yellow tail now is going to be the focus of the <unk> development, which we said in our remarks, we hope to.
Submit a plan of development to the <unk>.
These government by the fourth quarter of this year, so very exciting results and very exciting developments coming forward.
Okay, great. Thank you and my follow up is also on Guyana I loved all the details about where you're going for exploration and appraisal. This year you mentioned the results depending on the results of the appraisal that Mako that that could get moved up in the queue.
I was just wondering what youre seeing at Mako that puts it ahead of maybe some of the other potential development areas. Thank you.
Okay, Greg Yeah sure Janine So you know.
What we said was that assuming good results at <unk>.
At Mako and Wawa route to.
Remember as is very close to Liza two and it's kind of in between the yellow tail and Liza two so we know that the reservoir quality and the and the crude quality is going to be very high in that region. So that's why it will move.
Further in the queue because if its what we think it is that will be very high value barrels that will want to move forward.
Okay. Thank you for that that could potentially be thank you and that could potentially be the fifth ship share basically yep.
Thank you our net.
Question comes from the line of Doug Leggate with Bank of America.
Thanks, Good morning, happy New year, guys I appreciate your questions.
Greg Let me, let me start with Hasan on.
Somewhat.
Description John gave of the deeper horizons, you've talked about the possibility of this on pony and in a number of other tests and extending the life of some of the early phases. So I'm just wondering.
Is this a continuation of that some podium trend as you saw in Hasan if so why would you describe it.
I guess, how would you describe it as a successful wells I'm unsuccessful, well Hello have you reported from the government.
Well I think look well the hospital well one didn't encounter commercial quantities of hydrocarbons in the primary campaign objective as we mentioned dug in her opener it did encounter.
<unk> 50 net feet of pay in the deeper sand Tony in section.
So further evaluation of those deep results are going to be incorporated in our future exploration developed the lands for the area and will provide some very useful calibration for prospects and developments in the surrounding areas. So the petroleum system is working.
We found 50 net feet of good oil.
In the San Antonia and so now we need to process on what that means but I think it's a very positive sign.
For the San Antonio.
So it would not be reported as a discovery then they go.
No.
Because the wells are still under evaluation.
Okay Alright.
So John Reilly, you've obviously booked in some protection can you talk about the I don't know if I missed that in your prepared remarks.
Amortization schedule on.
Most really behind my question is it looks to us that youre going to be pretty close.
Cash breakeven, including dividends this year, how would you.
Tries out statement does that sound reasonable to you with what you know to day.
So what is the incremental priority for cash.
Free cash in terms of where you want the balance sheet to be so so basically it's a free cash flow question and a balance sheet question for John.
Go ahead Joshua.
So I think first you were saying for the hedges themselves for our 100000 barrels a day of <unk> put options that we have that $45 and then the 20000 barrels a day for a Brent.
Production that we have at $50 the amortization of that is going to be $37 million per quarter. So we like it we've got nice protection on the downside because obviously again this is a big year for us just to kind of complete the.
The development of Liza Phase two and as you know when Liza Phase two comes on book, It's approximately 60000 barrels a day of Brent based production.
The cash cost of that Liza phase two is going to be more around $10 pre any purchase of the EF PSL versus the first one being at $12 just from the economies of scale. So you can put any.
Brent price in there and take out the $10 cash cost and you can see there's going to be a significant inflection for us on cash flow once phase two comes on.
So for this year, Doug from a cash flow stand well, what we what we'll be looking to do so the first thing we were looking to do was to get the the hedges in place. So we have insurance on the downside.
Coming into the year effectively as I mentioned, we have $1 $74 billion of cash at year end and as I said in my remarks, we're going to complete the sales of the two vlccs and it's going to give us cash flow of approximately $150 million in the first quarter. So on a pro forma basis, we basically have $1 nine.
Cash going into the year, so what I want to say I mean, I don't want to guess on on oil prices, but we've got the downside protected we're coming in with a very strong cash balance here from that standpoint, and therefore, you know at these higher prices. Obviously this helps with our funding program here for Guyana, So when.
Phase two comes on depending where prices are with our insurance now we know we're going to have a nice cash cushion at that point and then we're going to be in the significant inflection point of getting much higher cash flow and depending on prices. There. The portfolio can just continue to generate free cash flow or for some reason prices go back down.
In that period as I said, Diana will still be generating free cash flow even at very low prices. Once phase two comes on like $40 type prices and then when <unk> comes on if it was really low prices, we'd still be generating free cash flow. So we've put ourselves in a good position with a very strong cash position.
Protection should be a nice year with prices at this level and then a big inflection with phase III starts.
John just to complement what John saying you know the priority once we get to that free cash flow inflection is to pay down our term loan and then after that the majority of the free cash flow will increase cash returns to our shareholders prioritizing the dividend first.
So John let's deliver the question.
Youre happy with about a $5 billion.
He is on vacation.
With when if we pay down that term loan debt yes.
As we pay down that term loan our debt to EBITDA when that Diana.
S Tso's keep coming on we're going to drive under our two times target fairly quickly. So, yes, that's where we'd like to be right to get that term loan paid off and then as John said, then we start increasing dividends and opportunistic share repurchases.
Sunday Thanksgiving us.
Thank you.
Our next question comes from the line of Jay around with JP Morgan.
Yeah, Good morning, Gents morning, John.
Yeah, John I wanted to start off with your thoughts on the evolving regulatory landscape post the election.
And maybe get your per perspective on potential implications to Hess.
From the anticipated executive orders later today on canceling the lease sales and.
If the government takes a more restrictive stance on permits are post the 60 day moratorium and perhaps as well to John Reilly.
Thoughts on <unk>, and how I know you have a pretty material NOL balances, but just thoughts on risk to IDC as well.
No Arun Great question, obviously, we also understand the president will make an announcement later today on federal lands and also some point. So I think about climate I think it's important for everyone to realize that only about 2% of our Bakken acreage is on federal lands. So this pronounce it will.
Not have an impact on our Bakken activities and in the deepwater Gulf of Mexico is.
Greg say.
Earlier that we have no drilling planned for this year in the deepwater Gulf and it remains to be seen.
What he's going to say about existing acreage and drilling permits for the deepwater, but we have no drilling plan. This year I think the most important point here is that the administration.
As it.
<unk> makes these decisions to address climate change that day.
<unk> have to be not only climate literate, but energy literate and they they have to realized that oil and gas are a strategic engine for the U S economy, especially at a time that we're trying to recover the economy from Covid.
And that importance is in jobs.
We have over 12 million direct and indirect jobs in terms of low energy costs for working class families. Our power cost in large part because of shale gas are half what they are in Europe and in terms of national security, where where energy independent in large part because of shale oil and shale gas so.
No. It's just a question of finding the balance here.
And hopefully as the administration moves forward they will extend our hand as well we need to find common ground to make sure. We do everything we can to address climate change, but also that oil and gas play a key role in the economy's recovery.
And John you want to talk about the I D CS.
Sure. So yes, you're right Arun you know for us. So obviously, they they change what they're doing with the ITC. There there will be an alternative period of recovery you know I don't know over how many years youll P or a different.
Year term.
For us, though while it's negative for U S oil supply in general, it's not going to have a material impact to us due to our NOL position, we do have a significant net operating loss position here so far.
<unk> pain.
Cash taxes anything in the near term regarding to the IDC that will not change our profile.
Great and my follow up is.
John Reilly, the cash cost guide was a little bit lower.
This year then our model. So I was wondering if you could maybe get us oriented on how or where your expectations are for Liza one.
Cash operating costs I think you still are paying the rental fee on the DSO, but would love to hear what those costs are and any expectations around Liza two with the bigger boat.
Go ahead, yes, so for Liza phase one.
$12 per barrel basically at now we're at full capacity here, that's the cash cost per about while were in the rental period and you are correct. We have it in our numbers for the whole year post an F. DSO purchase it'll drop down into the eight to $9 type range for Liza phase one.
As I mentioned Liza phase two actually the cash costs will be approximately $10 per barrel, while the CSO is being leased and then it's going to drop to 7% to $8 per barrel post the purchase of the CSO. So again for US every time an S. PSL comes on line, it's going to.
Our cash costs and it's also by the way you're going to help our DD&A rates. So right now Liza phase one the current DD&A rate is below our portfolio average.
Due to the low F&D costs.
So when Liza phase two comes on ultimately when it's up and running here and you get to the full scale again that F&B is very low and that's going to continue to drive our DD&A down. So again, we look forward for every every F DSO to come on in.
<unk>.
Thanks, John.
<unk>.
Thank you.
And our next question comes from the line of Brian singer with Goldman Sachs.
Thank you good morning.
I wanted to start on the on the Bakken you've highlighted that the beat on production on a BOE per day basis has come from in part from gas capture and then some of the impacts net of pricing on NGL contracts in percentage of proceeds contracts on a forward looking basis I Wonder if you could provide some color on what you expect oil the oil.
And outlook to be in the first quarter and the full year.
And in terms of gas flaring and what the upside could be from further gas capture.
Greg.
Yeah. So let me start with flaring, Brian So, we're we're well below the 9% required by the state.
In 2020.
We achieved that.
Particularly in the fourth quarter and that's why.
Our gas capture volumes increased.
This year, we plan to gather more gas and get our flaring down even lower so as part of our.
Continued focus on sustainability, we want to drive that gas flaring as low as possible. Obviously, so you will see us continue to add infrastructure with our partner in the midstream.
Together as much gas as we possibly can.
Now if we talk about the oil filter.
The decline in oil is purely related to the wells on line. So in Q3, we had 22 wells online in Q4, we had 12 wells online and in Q1, we only added in Q1 of <unk>.
This year, we will only put four wells on line, so naturally youre going to get some oil decline associated with that however is that second rig kicks in.
You really see the effects of the <unk>.
Second half of the year, that's when oil will begin to stabilize and be flat.
From then on with that second rig so again, it's really just a mix issue of gas.
The changes youre percentage on a on a total company basis and then the oil is purely a function of the wells on line, but that will stabilize the company will stabilize and 175000 barrels a day flat for a number of years.
Great. Thanks, and then.
Question goes back to Guyana, now that you've gotten phase one ramped up to the 120000 barrels a day and it seemed like.
You are hinting that that capacity could actually be raised this year.
Can you talk about how Youre planning phase two and the potential speed at which that can be ramped up to full capacity.
Knowing some of the lessons of 2020.
In terms of gas capture et cetera.
Greg.
Yeah, Brian Thanks for that certainly I would expect.
The ramp up of phase II to go faster.
Because as you say all of those learnings.
Have been incorporated into the ramp of <unk> into phase III. So I would expect it to go much smoother.
Remember all of our issues were associated with the gas system and those those who have been fixed and phase two.
Great. Thank you.
Yeah.
Thank you and our next question comes from the line of Josh Silverstein with Wolfe Research.
Hey, good morning, guys just a warning.
Hi, Good morning, just as a follow up question the box I'm, sorry, if I missed this but when do you guys start to stabilize around the 175000 range.
Range or around there.
Does the production mix look like or does it still kind of a change on a quarterly basis just based on some of.
The Weld County.
Greg.
So of course, you'll always get.
There's two factors going on one which I mentioned, which is yes. It is a function of when wells come on line. So you get some minor changes associated with that but then of course, the bigger thing when I'm talking about total production on a barrel equivalent basis is really all of the gas gathering, including third party volumes, which remember.
A portion of that is subject to the percentage of proceeds contracts. So a lot of times when you see those numbers moving around particularly on the percentage of oil versus gas, it's all related to that gas gathering, including third party and NGL prices, which affect your pop contracts, but oil will be flat.
With a two rig program.
And then.
For the whole company, the 175000 barrels a day equivalent would be flat with the two rigs.
Got it understood thanks for that and then.
I'm just curious on the balance sheet and asset sales. Obviously, you sold <unk> late last quarter to help support the cash balance there and got in development.
I know some of this will be opportunistic, but these are cash flow and engines of the company.
Wondering how much of the remaining portfolio.
They wanted to divest or.
Maybe market right now I know in the past day market that would be like that it was an asset for sale. So I'm just curious if there will be some ongoing divestiture program as Guyana ramps up.
Yes, you know obviously in the normal course of business as we've shown.
We always look to optimize our portfolio, where we see.
Value opportunities, where there are opportunities to sell assets that meet our value expectations. Obviously that was the case in shensi and there are maybe a few cases, where there's some assets other assets as you mentioned.
That may meet that criteria as well so if they meet our criteria for value expectations will move forward, but more commenting more than that would be inappropriate.
Got it understood. Thanks, guys.
Thank you.
And our next question comes from the line of Ryan Todd with Simmons energy.
Okay. Thanks.
Maybe one follow up on the Bakken button to start moving can you provide any additional color on the expected trajectory at least in general production in the Bakken over the course of the year should we expect some amount of modest decline during the first half but.
But for the second rig stabilize production and then an exit rate.
Closer to the 175000 barrels a day of long term target.
Yeah, Greg I think yes, I think that's fair, yeah, because really the impact of the second rig.
It does not kick in until the second half of the year. So you will have some very moderate decline in oil and then as I mentioned before on a total production basis will be a function of NGL prices right.
We fully expect NGL prices to normalize.
In the second quarter, So you get some pickup.
And the second third and fourth quarter as NGL prices normalize.
Okay.
Thanks, and then maybe.
One in Guyana, I know it may be early but given the differences in both.
Development plan and capital budget for.
Phase II and phase III development in Guiana can you talk a little bit about expectations for EFT BSL four.
Whether resource density and our infrastructure requirements were kind of lean more one way or the other in terms of implications for the capex budget going forward.
Yes, Greg you.
You might talk about I'm, sorry go ahead of the war and oil quality their share and the attractiveness of the economics, Yeah. So and then I'll then I'll give the capital put John Reilly, but.
Yellow tail.
Again very high quality reservoir.
And we would expect it to be between Lisa too and power in terms of its breakeven oil price right. So somewhere between that 25 and $32 breakeven is where we anticipate yellow teo will come across because again. This is an extremely high quality reservoir.
And very high quality fluids. So that's one of the reasons, it's jumping forward.
In the Q and really being.
Kind of the next the net.
GAAP off the rank if you will because it's very high value.
Development, Brian I wanted to add one thing to my Bakken comment last time.
Also remember in the third quarter, we have the Tioga gas plant turnaround.
You will see a dip in production in the third quarter, but thats all gas primarily oil is going to be rocking along just fine.
Okay.
Perfect. Thanks, Greg.
Yeah.
Thank you and our next question comes from the line from Roger read with Wells Fargo.
Yes. Thank you good morning.
Morning, John.
Just wanted to ask one question on Guyana in reference to the expectation that phase one can maybe move above nameplate.
I know earlier in 2020, there were some surface issues and so as you look at the ability to go above can you kind of give us an idea of how much of this is subsurface outperformance how much of it is surface debottlenecking and maybe just a more broad sort of understanding of how the wells themselves.
Performance.
Greg Yeah. So.
Thanks for the question.
First of all the wells are.
Performing extremely well I mean, these reservoirs are some of the best in the world.
The wells continue to do as good or better than we thought so any constraints. If you will that have occurred in 2020 has purely been as a result of the top sides.
Now for the last week, we've been operating around 127000 barrels a day pretty steady.
In phase one and as you mentioned the operator now is conducting studies too.
Put projects in place to further increase that capacity.
Plans are to do that.
In the third quarter. So we'll have a shutdown period to be able to do that that's gonna be piping changes and basically just kind of debottlenecking. Some tight spots that you might have in that facility.
So that's why our forecasted volumes.
For the year 2021, or 30000 barrels of oil net to us.
Because you'll get some pickup from that optimization that the operator is planning to do offset a little bit by the shut downtime required to do it but this this vessel will definitely.
Have higher throughput next year.
Okay, great. Thank you.
Meaning this year and next year right, great I'm, sorry, 'twenty, one sorry, John got me again, the kind of thing.
Our next question comes from the line of Paul Cheng with Scotia Bank.
Hi, Thank you good morning, guys, Hey, good morning, Paul.
Alright, thank you.
That you're talking about the yellow tell you its a good quarter and not that that's wonderful.
Can you make some preliminary expectation what the unit development cost is that comparable to Liza two or more like pie overlap.
No.
Said, Paul I think this development is probably going to fall between <unk>.
And and phase two so somewhere closer to we believe we would be closer to home.
Two phase III.
And so you could you could.
Whom development costs be very similar somewhere between phase II Empire. These are very good reservoirs.
Very high deliverability very high quality crude oil, that's where that breakeven is in between the two it really comes down to just how much infrastructure will you need.
But wont need as much by our may need a little bit more than phase II.
Okay.
And you mentioned the budget to break the Bakken program two question on their first.
What is the oil production that you would be able to do based on day I mean, we understand that gas with swing due to the capture way, but you're saying that oil would be pretty steady. So what's that number that you expect.
And with that that based on what you see today.
We need that the program that you expect for the next several years that even with a change in the commodity prices, how does that impact that program.
Well.
Let me start with your second question first Paul.
As we've said our plan is to hold two rigs through 2021 now.
Assuming oil prices improve in the future.
What we'd like to do is eventually get the rig count to four in the Bakken by getting the rig count before will not only generate significant amount of cash flow, but will also be able to hold production.
Production in the Bakken broadly flat at around 200000 barrels a day.
Equivalent.
For almost 10 years.
Why would we want to do that because we have 1800, well locations left that at current prices generate very high returns.
And then if I look at this year's program in particular from.
Remember I'm going to bring 45 wells online this year.
The program is very similar to last year and that the IP 180 <unk>.
Will be the same as last year 120000.
Barrels of oil IP 180, very good wells and at current returns if you look at them.
The IRR of that program. This year of those 45 wells, it's 95% rate of return.
And so I've got another after this year I'll have another 17 to 150 wells that are that are in those very high returns that of course, I want to get I would like to develop.
But I think as we've said before Paul the role of the Bakken in the portfolio is to be a cash generator. So the rate at which we invest in the Bakken will be a function of corporate cash flow needs, but you can see the pent up potential in the Bakken is very large with some very good return opportunities and to be clear.
One out of the fall in the oil cut at the wellhead really not has not changed what the oil.
Oil cut changes is downstream how much gas we capture how many wells, we're bringing on line and what the NGL prices are so so low the quality of oil at the wellhead is the same that percent hasn't changed now what changes in the corporate accounting is due to what happens downstream as I mentioned.
Yep.
Hey, Craig So what is that oil production that you expect that to win program can do.
Well I think broadly what.
Once this levels out I think broadly you can expect oil around 90000 barrels a day.
In the.
In the third and fourth quarter.
Okay and the next one is for John <unk>, John Your D D and E expectation for the year, yes. The diesel campaigns from your fourth quarter. Your fourth quarter <unk>, you, probably do close to $16.
We're expecting it's going to be at 12 to 13 for the first quarter as well.
Full year. So we are we seeing that the jaw.
Unit <unk>.
Sure John.
Thanks, John.
The driver of this is the increase in our year end 2020 proved developed reserves. So you saw our reserve replacement, but I guess another aspect of this is that our proved developed reserves are up to about 70% of our proved reserves. So it's up 13%.
Over a year on year, excluding the asset sales.
You've got Bakken, obviously proved developed reserves adds still net even after price revisions you have Guyana again picking up proved developed reserves here is as more and more wells and the performance from phase two and then you've got a good amount of transfers from pods that moved in.
Into proved developed reserves.
Approximately 100 million barrels there and it's offset obviously by current production.
So it's really the driver of proved developed reserves increasing significantly from last year and then you have a combination of year over year production mix. So as I mentioned, Guyana and right now it is below our portfolio average and so Guyana as production is increasing so that's going to overall.
Drive down the DD&A rate and again Bakken DD&A rate.
While still higher is is coming down from.
From 2020, just due to the proved developed ads. So again, a good year for free reserve adds.
A final question on the Gulf of Mexico.
Many permit that you currently have.
John.
If you have any.
Paul We don't we don't need any permits this year at all or not though I havent. That's we're not planning any quick I understand that you're not going to do anything but I just want to see that if you have any permit in hand, given that the permanent cannot split two years.
And then no simple definitely extensive let's see where the president comes out on what is drilling regulations are.
And then right now we don't have any permits in hand, because we don't have any need for the next year right.
Okay. Thank you.
Thank you and our.
The next question comes from the line of Bob Brackett with Bernstein Research.
Good morning, all our operating Bob El risk a bit of a long winded question. So the Liza F. P. S. O Destiny had a mid year 2019 departure from Singapore, and a single installation campaign, which resulted in first oil on December 20th of 2019, the same here.
You've mentioned that Liza unity <unk> has a mid year 2021 departure from Singapore. It has two installation campaigns and obviously more risers and umbilical how should I contrast, the timeline of hookup integration commissioning and then ultimately the shape of the production ramp for unity vs Destiny.
Yeah, So Bob you're right I mean, there's two installation programs.
That's why officially first oil is.
Early 2022 now.
Now because of those two programs there is still some contingency in the project. So if everything goes right you could maybe get that.
Get that best one just a little bit earlier right.
So.
All going very well as I said in my remarks project is 85% complete.
Vessel due to sail away.
Early in the summer get it on location and then do that very active hook up program that will put us squarely with first oil in the early part of 2022 now the ramp as I mentioned earlier, we anticipate that ramp will go much smoother.
Of course, then.
He is one and that's because all of the learnings, which we're in the gas system and remember all of the learnings have been applied.
Two the gas system on phase two because with very similar equipment equipment is in phase one so very much expect to ramp.
Lee would occur over say, a three month period, because youre going to you bring things on and you measure dynamics, you've got vibration sensors everywhere, that's a pretty normal cadence.
To bring something like that on us over a three month period.
Great Thanks for that.
Thank you.
Thank you very much. This concludes today's conference. Thank you for your participation and you may now disconnect.
Have a great day.
And there's no more loans.
Good day.
Your line.
Yes.
[music].