Hess - Q1 2021
April 28, 2021
Transcript
Speaker 0
Good day, ladies and gentlemen, and welcome to the First Quarter 2021 Hess Corporation Conference Call. My name is Catherine, and I'll 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. 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.
Speaker 1
Thank you, Catherine. Good morning, everyone, and thank you for participating in our Q1 earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward looking statements Within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties In the Risk Factors section of Hess' annual and quarterly reports filed with the SEC.
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 As we have done in recent quarters, we will be posting transcripts of each Speakers' prepared remarks on our website following their presentations. On the line with me today are John Hess, Chief Executive Officer Greg Hill, Chief Operating Officer and John Reilly, Chief Financial Officer. I'll now turn the call over to John Hess.
Speaker 2
Thank you, Jay. Welcome to our Q1 conference call. We hope you and your families are all well. Today, I will review our continued progress in executing our strategy. Then Greg Hill will discuss our operations, and John Reilly We'll then review our financial performance.
Let's begin with our strategy, which has been and continues to be to grow our resource base, Have a low cost of supply and sustained cash flow growth. By investing only in high return low cost opportunities, We have built a differentiated portfolio that is balanced between short cycle and long cycle assets, with Guyana as our growth engine And the Bakken, Gulf of Mexico and Southeast Asia as our cash engines. Guyana is positioned to become a significant cash engine As multiple phases of low cost oil developments come online, which we expect will drive our portfolio breakeven Brent oil price below $40 per barrel by the middle of the decade. As our portfolio generates increasing free cash flow, We will first prioritize debt reduction and then cash returns to shareholders through dividend increases and opportunistic share repurchases. Even as we have seen oil prices recover since the beginning of this year, our priorities continue to be To preserve cash, preserve our operating capability and preserve the long term value of our assets.
In terms of preserving cash, at the end of March, We had $186,000,000,000 of cash on the balance sheet, a $3,500,000,000 revolving credit facility, Which is undrawn and was recently extended by 1 year to 2024 and no debt maturities until 2023. We have maintained a disciplined capital and exploratory budget for 2021 of $1,900,000,000 More than 80% of this year's capital spend is allocated to Guyana, where our 3 sanctioned oil developments have a breakeven oil price of between $25 $35 per barrel and to the Bakken where we have a large inventory of future drilling locations that generate attractive financial returns at $50 per barrel WTI. To manage downside risks, in 2021, we have hedged 120,000 barrels of oil per day With $55 per barrel WTI put options and 30,000 barrels of oil per day with $60 per barrel Brent put options. To further optimize our portfolio and strengthen our cash and liquidity position, we recently announced 2 asset sales. In March, we entered into an agreement to sell our oil and gas interest in Denmark for a total consideration of $150,000,000 effective January 1, 2021.
This transaction is expected to close in the Q3. On April 8, We announced the sale of our Little Knife and Murphy Creek non strategic acreage interests in the Bakken for a total consideration of $312,000,000 effective March 1, 2021. This acreage is located in the southernmost portion of our Bakken position And it's connected to Hess Midstream Infrastructure. The sale of this acreage, most of which we were not planning to drill before 2026, Brings material value forward. This transaction is expected to close within the next few weeks.
During the quarter, we also received $70,000,000 in net proceeds from the public offering of a small portion of our Class A shares in Hess Midstream LP. The Bakken remains a core part of our portfolio. In February, As WTI oil prices moved above $50 per barrel, we added a second rig, which will allow us to sustain production and Strong cash flow generation from our largest operated asset. In terms of preserving the long term value of our assets, Guyana, with its low cost of supply and industry leading financial returns, remains a top priority. On the Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator, we have made 18 significant discoveries to date With gross discovered recoverable resources of approximately 9,000,000,000 barrels of oil equivalent, and we continue to see Multi billion barrels of future exploration potential remaining.
We have an active exploration and appraisal program this year on the Stabroek Block. Yesterday, we announced the discovery at the Waru II well with encouraging results that further define the large aerial extent of this accumulation, Underpinning a potential future oil development. In addition, drilling activities are underway for appraisal at the Long Tail 3 well And for exploration at the Coebi 1 prospect. Production from Phase 1 ran at its full capacity of 120,000 Gross barrels of oil per day during the Q1. In mid April, production was curtailed for several days After a minor leak was detected in the flash gas compressor discharge silencer, production has since ramped back up And is expected to remain in the range of 100,000 to 110,000 gross barrels of oil per day until repairs to the discharge silencer Following this repair, production is expected to return to or above Liza Destiny's nameplate capacity of 120,000 barrels of oil per day.
The Liza Phase 2 development is on track to achieve 1st oil in early 2022 with a capacity of 220,000 gross barrels of oil per day. Our 3rd oil development on the Stabroek Block at the Payara field is expected to achieve 1st oil in 2024, Also with a capacity of 220,000 gross barrels of oil per day, engineering work for Yellowtail, A 4th development on the Stabroek Block is underway with anticipated start up in 2025, pending government approvals and project sanctioning. We continue to see the potential for at least 6 FPSOs on the block by 2027 And longer term, for up to 10 FPSOs to develop the discovered resources on the block. As we execute our company's strategy, We will continue to be guided by our long standing commitment to sustainability and are proud to be an industry leader in this area. We support the aim of the Paris Agreement and also a global ambition to achieve net 0 emissions by 2,050.
As part of our sustainability commitment, our Board and our senior leadership have set aggressive targets for greenhouse gas emissions reduction. In 2020, we significantly surpassed our 5 year emission reduction targets, Reducing the operated scope 1 and scope 2 greenhouse gas emissions intensity by approximately 40% And flaring intensity by approximately 60% compared to 2014 levels. We recently announced our new 5 year mission reduction targets for 2025, which are to reduce operated scope 1 and scope 2 greenhouse gas Our next question comes from the line of Katherine McCarthy. Please go ahead. In addition, we are investing in technological and scientific advances designed to reduce, capture and store carbon emissions, Including groundbreaking work being conducted by the Salk Institute to develop plants with larger root systems That according to the Salk Institute, are capable of absorbing and storing potentially billions of tons of carbon per year from the atmosphere.
In summary, Our company is executing our strategy that will deliver increasing financial returns, visible and low risk production growth And accelerating cash flow growth well into this decade. As we generate increasing free cash flow, we will first prioritize debt reduction And then the return of capital to our shareholders through dividend increases and opportunistic share repurchases. I will now turn the call over to Greg for an operational update.
Speaker 3
Thanks, John. Overall, in the 1st quarter, we demonstrated strong execution and delivery across our portfolio. Company wide net production averaged 315,000 barrels of oil equivalent per day, excluding Libya, which was in line with our guidance. The Bakken experienced extreme weather conditions and higher NGL prices during the quarter, both of which led to lower volumes. However, The higher NGL prices resulted in significantly higher net income and cash flows.
Bakken net production in 1st quarter averaged 158,000 barrels of oil equivalent per day, which was below our guidance of approximately 170,000 barrels of oil equivalent today. Of this shortfall, approximately 8,000 barrels per day was due to the significant increase in NGL prices In the quarter, much of our 3rd party gas processing from our operated production is done under percent of proceeds or POP contracts, Where we charge a fixed fee for processing wet gas, but take NGL barrels as payment instead of cash. This increase as they did in the Q1, it takes fewer barrels to cover our gas processing fees. Hence, our reported NGL production was But again, the higher NGL prices resulted in significantly higher earnings and cash flow. The other factor that affected Bakken production in the quarter was related to winter storm Yuri, which brought Power outages and average wind chill temperatures of minus 34 degrees Fahrenheit for 2 weeks in February.
These extreme temperatures were below safe operating conditions for our crews and led to higher non productive time on our drilling rigs, Significantly higher workover backlogs and lower non operated production. As discussed in our January earnings call, We added a second rig in the Bakken in February. In the Q1, we drilled 11 wells and brought 4 new wells online. In the Q2, we expect to drill approximately 15 wells and bring approximately 10 new wells online. And for the full year 2021, we expect to drill approximately 55 wells and to bring approximately 45 new wells Thanks to the continued application of lean technology, our drilling and completion costs are expected to Average approximately $5,800,000 per well in 2021, which represents a 6.5 Percent reduction from $6,200,000 in 20.20 and a 15% reduction from $6,800,000 in 2019.
For the Q2, we forecast that our Bakken net production will average Approximately 155,000 barrels of oil equivalent per day and for the full year 2021 Between 155,000 and 160,000 barrels of oil equivalent per day. This forecast reflects the residual weather impacts, Higher NGL strip prices, the sale of our non strategic Bakken acreage and the planned turnaround at the Tioga gas plant in the Q3. We expect net production to build in the second half of the year and forecast a 2021 exit rate of between 170,000,175,000 barrels of oil equivalent per day. Moving to the offshore. In the Deepwater Gulf of Mexico, 1st quarter net production averaged 56,000 barrels of oil equivalent per day, Reflecting strong operations following hurricane recovery in late 2020.
In the second quarter, We forecast that the Gulf of Mexico net production will average approximately 50,000 barrels of oil equivalent per day. For the full year 2021, we maintain our guidance for Gulf of Mexico net production to average approximately 45,000 barrels of oil In the Gulf of Thailand, Net production in the Q1 was 64,000 barrels of oil equivalent per day as natural gas nominations Continue to increase due to strong economic growth. 2nd quarter and full year 2021 net Production are forecast to average approximately 60,000 barrels of oil equivalent per day. Now turning to Guyana. Our discoveries and developments on the Stabroek Block are world class in every respect.
And with Brent breakeven oil prices of between $25 $35 per barrel represents some of the lowest project breakeven oil prices in the Production from Liza Phase 1 averaged 121,000 gross barrels of oil per day We're 31,000 barrels of oil per day net to Hess in the Q1. As John mentioned, production at the Liza Destiny was curtailed for several days following the detection of a minor gas leak in the flash gas compressor's discharge silencer on April 11. Production is currently averaging between 110,001 100,000 gross barrels of oil per day And is expected to stay in that range, while repairs are made to the silencer. Upon reinstallation and restart of the flash Gas Compression System expected in approximately 3 months. Production is expected to return to or above Nameplate capacity of 120,000 barrels of oil per day.
For the 2nd quarter, We now forecast net production to average between 20,000 to average approximately 30,000 barrels of oil per day. SBM Offshore has placed an order For an upgraded flash gas compression system, which is expected to be installed in the Q4 of 2021. Production optimization work is now planned in the Q4, which will further increase the Liza Destiny's progression capacity. I think it's important to note that the overall performance of the subsurface in Liza 1 has been outstanding. We have seen very strong reservoir and well performance That has met or exceeded our expectations.
Once the flash gas compressor is replaced, we are Confident that we will see a significant improvement in uptime reliability. At Liza Phase 2, the project is Progressing the plan with about 90% of the overall work completed and First Oil remains on track for early 2022. The Liza Unity FPSO with a production capacity of 220,000 gross barrels of oil per day Is preparing to sail from the Keppel yard in Singapore to Guyana midyear. Our 3rd development, Payara, Is also progressing the plan with about 38% of the overall work completed. The project will utilize the Liza Prosperity FPSO, So which will have the capacity to produce up to 220,000 gross barrels of oil per day.
The FPSO hull is complete and topside's construction activities has commenced in Singapore. First oil remains on track for 2024. Front end engineering and design work continues for the 4th development on the Stabroek Block At Yellowtail, the operator expects to submit a plan of development to the government of Guyana in the second half of this year. Pending government approval and project sanctioning, the Yellowtail project is expected to achieve first oil in 2025. The Stabroek Block exploration program for the remainder of the year will focus on both Campanian, Liza type reservoirs And on the deeper Santonian reservoirs.
In addition, key appraisal activities will be targeted in the southeast portion of the Stabroek Block to inform future developments. In terms of drilling activity, as announced yesterday, the successfully appraised the Wahra Run discovery and also made an incremental discovery in deeper intervals. The well encountered approximately 120 feet of high quality oil bearing sandstone reservoir And was drilled 6.8 miles from the discovery well, implying a potentially large aerial extent. The Standard Drill MAX is currently appraising the long tail discovery. An additional appraisal is planned at Mako And in the Turbot area, which will help define our 5th and 6th developments on the block.
Stanakaran has commenced exploration drilling at the Coedi-one well and an exploration well at Whiptail is planned to spud in May. Further exploration and appraisal activities are planned for the second half of twenty twenty one With a total of approximately 12 wells to be drilled this year. The Noble Tom Madden, the Noble Bob Douglas and the Noble Sam Croft, Which recently joined the fleet will be primarily focused on development drilling. Now shifting back to production. Company wide second quarter net production is forecast to average between 290,000,295,000 barrels of oil Full year 2021 net production is now also expected to average between 290,000 And 295,000 barrels of oil equivalent per day compared to our previous forecast of approximately 310,000 barrels of oil equivalent per day.
This reduction reflects the following: approximately 7,000 barrels of oil equivalent per day due to lower entitlements resulting from the increase in NGL strip prices. Again, this will be accretive overall to earnings and cash flow. 2nd factor is approximately 6,000 barrels of oil equivalent per day was related to the sale of our interest in Denmark And non strategic acreage in North Dakota for which we brought full value forward. The balance Primarily reflects short term weather impacts in the Bakken from which we expect to catch back up over the course of the year And again forecast a 2021 Bakken exit rate of between 170,000 175,000 barrels In closing, our team once again demonstrated strong execution and delivery Across our asset base under challenging conditions, our distinctive capabilities and world class portfolio
Speaker 4
Thanks, Greg. In my remarks today, I will compare results from the Q1 of 2021 to the Q4 of 2020. We had net income of $252,000,000 in the Q1 of 2021 Compared to an adjusted net loss of $176,000,000 which excluded an after tax gain of $79,000,000 from an asset Sales in the Q4 of 2020. Turning to E and P. E and P had net income of $308,000,000 in the Q1 of 20 Of adjusted E and P results between the Q1 of 2021 Q4 of 2020, worst follows.
Higher realized Crude oil, NGL and natural gas selling prices increased earnings by $192,000,000 Higher sales volumes increased earnings by $99,000,000 lower DD and A expense Increased earnings by $88,000,000 lower cash costs increased earnings by 39,000,000 All other items increased earnings by $8,000,000 for an overall increase in first quarter earnings of $426,000,000 Excluding the 2 VLCC cargo sales, our E and P sales volumes were over lifted Compared with production by approximately 300,000 barrels, which improved after tax results by approximately $10,000,000 The sales from the 2 VLCC cargoes increased net income by approximately $70,000,000 in the quarter. The impact of higher NGL prices improved 1st quarter earnings by approximately $55,000,000 And reduced Bakken NGL volumes received under percentage of proceeds or POP contracts by 9,000 barrels of oil equivalent per day compared with the Q4 of 2020. Now turning to Midstream. The Midstream segment had net income of $75,000,000 in the Q1 of 2021 compared to $62,000,000 in the prior quarter. Midstream EBITDA before non controlling interest amounted to $225,000,000 in the Q1 of 2021 compared to $198,000,000 in the previous quarter.
In March, Hess received net proceeds $70,000,000 from the public offering of 3,450,000 Hess Owned Class A Shares in Hess Midstream. Now turning to our financial position. At quarter end, excluding Midstream, Cash and cash equivalents were approximately $1,860,000,000 and our total liquidity was $5,500,000,000 Including available committed credit facilities, while debt and finance lease obligations totaled $6,600,000,000 Our fully undrawn $3,500,000,000 revolving credit facility is now committed through May 2024, Following the amendment executed earlier this month to extend the maturity date by 1 year. In the Q1 of 2021, Net cash provided by operating activities before changes in working capital was $815,000,000 compared with $532,000,000 in the Q4 of 2020, primarily due to higher realized selling prices. In the Q1, net cash provided from operating activities after changes in working capital was $591,000,000 compared with $486,000,000 in the prior quarter.
The sale of our Little Knife and Murphy Creek acreage in the Bakken for Total consideration of $312,000,000 is expected to close within the next few weeks and the sale of our interest in Denmark for total Consideration of $150,000,000 is expected to close in the Q3 of this year. Now turning to guidance. Our E and P cash costs were $9.81 per barrel of oil equivalent, including Libya And $10.21 per barrel of oil equivalent excluding Libya in the Q1 of 2021. We project E and P cash costs excluding Libya to be in the range of $12 to $13 per barrel of oil equivalent for the 2nd quarter, primarily reflecting the timing of maintenance and work overspend. Full year E and P cash costs are expected to be in the range of $11 to $12 per barrel of oil equivalent, Which is up from previous full year guidance of $10.50 to $11.50 per barrel of oil equivalent Due to the impact of updated production guidance, DD and A expense was $11.83 DD and A expense excluding Libya is forecast to be in the range of $11.50 to $12.50 per barrel of oil equivalent for Q2 and full year guidance of $12 to $13 per barrel of oil equivalent is unchanged.
This results in projected total E and P unit operating Excluding Libya to be in the range of $23.50 to $25.50 per barrel of oil equivalent for the 2nd quarter And $23 to $25 per barrel of oil equivalent for the full year of 2021. Exploration expenses, excluding dry hole costs, are expected to be in the range of $40,000,000 to $45,000,000 in the second quarter And full year guidance of $170,000,000 to $180,000,000 is unchanged. The midstream tariff is projected to be in the range $260,000,000 to $270,000,000 for the 2nd quarter and full year guidance of $1,090,000,000 To $1,115,000,000 is unchanged. E and P income tax expense, Excluding Libya, it's expected to be in the range of $25,000,000 to $30,000,000 for the 2nd quarter and $105,000,000 to $115,000,000 for the full year, Which is up from previous guidance of $80,000,000 to $90,000,000 due to higher commodity prices. We expect Non cash option premium amortization will be approximately $65,000,000 for the 2nd quarter and $245,000,000 for the full year, which is up from previous guidance of $205,000,000 reflecting additional premiums paid to increase strike price on our crude oil hedging contracts.
In the second quarter, we expect to sell 2 1,000,000 barrel cargoes from Guyana, whereas we sold 3 1,000,000 barrel cargoes in the Q1 and we expect to sell 5 1,000,000 barrel cargoes over the second half of the year. Our E and P capital and exploratory expenditures are expected to be approximately $500,000,000 in the second quarter And the full year guidance of approximately $1,900,000,000 remains unchanged. For Midstream, We anticipate net income attributable to Hess for the Midstream segment to be in the range of $60,000,000 to $70,000,000 for the 2nd quarter And the full year guidance of $280,000,000 to $290,000,000 remains unchanged. For corporate, Corporate expenses are estimated to be in the range of $30,000,000 to $35,000,000 for the 2nd quarter and full year guidance $100,000,000 for the Q2 and full year guidance of $380,000,000 to $390,000,000 is unchanged. This concludes my remarks.
We will be happy to answer any questions. I will now turn the call over to the operator.
Speaker 0
Your first question comes from Neil Mehta with Goldman Sachs. Your line is open.
Speaker 4
Thanks guys. Congrats on a good John, you talked about accelerating returns back to shareholders when you get net debt to EBITDA sub two times. It seems like between Liza II and the forward curve, you're going to get there inside of 1 year. So how do you think about what to do with the excess cash And the optimal allocation of that to shareholders. Thanks, Neil.
Yes, now with we've had a strong Q1 And we're seeing market conditions favorable for oil right now. It is still our plan, our strategy, as Phase 2 comes on And it's 220,000 barrel a day ship. So we'll get our entitlement there will significantly drive our cash flow inflection And therefore, our debt to EBITDA will begin to get under 2 as we take that excess cash flow than we have and pay down the Term loans. So the first thing that we're going to do with excess cash flow is pay down the $1,000,000,000 term loan. Once we have that paid off and that We will be under 2 times debt to EBITDA for our balance sheet and then we'll be in that position to start increasing returns to shareholders.
And we've been consistent about it. What the first thing we'll do is increase our dividend. We'll start to increase the dividends. And then As our cash flow continues to grow with Payara coming on and then Yellowtail and as like we said, we expect Now up to 10 FPSOs while the significant cash flow growth will begin to do opportunistic share repurchases after the dividend increase. Clear.
Thank you. And the follow-up is just about the long term value of the Guyana resource. So much has been said about long term risk to oil demand. And I'm just curious how do you think about the value of Some of the projects in the FPSOs that come in post-twenty 26 as electric vehicles start to accelerate and some of the competitive threats Start to be there for traditional transportation demand. And does that change in any way the way you think about prosecuting This project including the potential to monetize some of the acreage earlier in order to pull forward the value to mitigate some of the long term demand
Speaker 2
Yes. Great question, Neil. Thank you. A couple of points we'd like to make. Look, the world has 2 future challenges.
One is, how do we provide more energy supply, 20% more energy supply by 2,040? And how do we get to net 0 emissions by 2,050? I think the best resource to provide insights Into these challenges is the World Energy Outlook of the International Energy Agency and under their sustainable development scenario, Which says that even if all the pledges of the Paris Climate Accord were met, Oil and gas would still be 46% of the energy mix in 2,040. So it's not just about climate literacy, it's also about Energy literacy. Oil and gas are still going to be needed 20 years out.
The key to all of this because none of us can call oil price, there's always going to be volatility and Some of the pressures you're talking about, obviously, are going to be a factor in that. The key will be having a low cost of supply. And we believe that We're uniquely positioned in that regard with a growing resource, a low cost to supply That positions our company with a differentiated portfolio of assets that we have with a growing resource at low cost of supply To deliver sustainable and industry leading cash flow growth and financial returns for our shareholders. And when you talk about the longer term, I think it's important to realize that Guyana isn't as longer term. We're bringing forward almost every year, First in 2022 with Liza II, then in 2024 with Payara, then Yellowtail in 2025.
The payouts are very quick and returns are very high. So we are going to be bringing Value forward, and you can look at a cadence most likely of bringing on one of these low cost developments about every year thereafter. So we are bringing the value forward and with low cost of supply, we think we're going to be uniquely positioned to provide Sustainable and industry leading cash flow growth.
Speaker 5
Thanks, Chad.
Speaker 0
Thank you. Our next question comes from Arun Jayaram with JPMorgan. Your line is open.
Speaker 6
Yes, good morning. Good
Speaker 2
morning. Good morning.
Speaker 5
Good morning.
Speaker 6
Yes. Greg, I was wondering if you could provide an update on the debottlenecking project at Liza Phase 1 and maybe discuss how the repair activities On the flash gas compressor impact the timing of that project. And also wanted to see if you could provide a little bit more color. You mentioned that SBM may be replacing the flash gas compressor, so maybe a little bit more color around that.
Speaker 3
Yes, sure. So Let me take it in 2 pieces. So first, let's talk about the Flash Gas Compressor. As John and I both mentioned in our opening remarks, We had a couple of days of downtime associated with that, where production was curtailed for a couple of days. That flash gas compressor is now back in Houston, being torn down, looked at with the expectation that it will be restored Within the next 3 months, right?
So once that happens, then we'll get back to that 120,000 barrels a day plus, So say that's July. Then the next
Speaker 5
increment, as you
Speaker 3
mentioned, is the debottlenecking project, Which now is going to occur in the Q4. And that will take Lees at Phase 1 up another incremental production. Now they're still in Final engineering phases of that, so I can't give you an exact number as to what that's going to be, but that will come in the 4th quarter. Also in the Q4, Exxon is going to replace the existing flash gas compressor With some of the components that have been redesigned. So that shutdown in the Q4 about 14 days We'll accomplish those two things.
It will be the debottlenecking and also the installation of a new redesign flash Gas compressor for Phase 1.
Speaker 6
Great. And my follow-up is perhaps for John Reilly. John, how does the improvement in oil prices Impact yours and Exxon's thinking on the purchase versus lease decision on the FPSO from a timing perspective?
Speaker 4
Aruna, right now Exxon is in discussions with SBM. They're having commercial discussions on the purchase So it is ongoing. The oil price itself doesn't really have a factor in there, but they're just they're going through these Discussions, we expect to have that information later in the year and we'll provide the guidance on the timing of the FPSO purchases when we get that information.
Speaker 6
All right. Fair enough. Thanks.
Speaker 0
Thank you. Our next question comes from Doug Leggate with Bank of America. Your line is open.
Speaker 5
Thanks. Good morning, everyone. Good
Speaker 6
morning, Doug.
Speaker 5
So, Greg, Iara, 38% complete, At least on the whole SCM is telling us 12 months to 14 months is the standard So the top side installation for these standardized units, which would put you middle of next year for a completed FPSO. Can you walk me through how you get from the middle of 2022 to 2024 for first oil when the vote is ready middle of next year?
Speaker 3
Well, I mean, Doug, as you know, Payara does have a very extensive drilling and SURF Program, in particular, the surf requires 3 open water Seasons, if you will, to get all that subsea kit in. So look, Payara is going well. There is still contingency built into the project, which I think is prudent at this point, given that significant And amount of surf work that has to be done, but ExxonMobil is executing extremely well. Hopefully, You know, Payar will come on earlier in 2024. So we'll see, Doug.
There's a lot of work left to do yet. Okay.
Speaker 5
We're going to get an in person dinner, Greg. I'll take a small bet with you that we see a 23 increment of that at some point. Okay. My follow-up is on the exit rate in the Bakken. How have you been able to lose 7,000,000, 8000 barrels a day of NGLs on the pulp contracts, but on the 4th quarter, You also guided to an exit rate of about 175,000,000 has been reasonable even with the second rig.
So can you just walk us through what's going better there allow you to stick with the same guidance. I'll leave it there. Thanks.
Speaker 3
John, do you want to answer the POP contract question, John Rylit?
Speaker 4
Yes, sure. So first I can just start with the way the POP contracts work. The amount for the full year In our guidance, you saw that it's about a 7,000 barrel a day reduction from original guidance. Now it's a little higher In the first, second and third and a little bit lower in the 4th. So we're not hit with as high a number on that pop in the 4th quarter.
That pop does have impact to it. And I'll start with Greg, but the well performance It's good. The wells that we're bringing on, we're seeing very good initial production. We're seeing better than expectations. Now you got to remember, We had 12 on in the 4th quarter, only 4 in the first.
We're just beginning now to pick up from the second rig and that will really pick up in the 3rd Q4. So we see the performance from those wells will pick that up and give us that ability to get back to that exit rate of 1.70 to 1.75. Greg, I don't know if there's anything else you want to add.
Speaker 3
No, I think you nailed it, John. Yes.
Speaker 5
No, that's really helpful, guys. Thanks very much indeed. Thank you.
Speaker 0
Thank you. Our next question comes from Jeanine Wai with Barclays. Your line is open.
Speaker 7
My first question is on Guyana. The latest well, the Waru-two, You indicated it encountered newly identified intervals below the original discovery well. Can you provide just any color on the commerciality of those zones? And Have you seen them elsewhere in the block? And do you plan to test them elsewhere this year?
Speaker 2
Go ahead, Greg.
Speaker 3
Yes. Thanks, Janine. So Again, Waru II was a great result, right? We had high quality oil sands, 120 feet. I think the most significant part about Waru was that it was 6.8 miles from Waru 1, which Demonstrates a very large aerial extent for the Huarua reservoir itself.
And Yes. As you said, we did discover a deeper zone. It's in the lower part of the Campanian and that does have read through to other parts The block, but certainly, the reason we didn't call it a 19th discovery is in this particular location, It's clearly not as significant as the other 18, right?
Speaker 5
But it does have some
Speaker 3
read through to other parts of the block. Okay.
Speaker 2
So the key is that the appraisal is very encouraging results. You have excellent reservoir characteristics. You have high quality oil. And given that Waru 1 versus Waru 2 is 6.8 miles away, it shows the potential for large aerial extent of a highly prolific high quality reservoir.
Speaker 7
Okay, got you. That's really helpful. Thank you. My second question is maybe just going back to the debottlenecking And Arun's question, lease loan capacity going up in Q4, we'll find out what to level later. But in terms of Future potential opportunities, are there debottlenecking opportunities built into the 220 nameplate capacities for the upcoming ships?
It just seems like that's pretty standard for a lot of these major capital projects including FPSOs. And at least when we do the math, if you do any kind of Moderate to bottlenecking, it really pulls forward a lot of NAV there. So just wondering kind of potential for that for the 2 20 ships.
Speaker 3
Yes. Janine, I think you could assume that there would be debottlenecking potential on all those ships. What typically happens is you will bring these facilities up to their nameplate and then you gather a lot of dynamic data And you really need that data. So you need fluids running through the facility at full capacity to determine Where are my pinch points? Where are my bottlenecks?
And what can I do to increase that capacity? And that's why you typically see these debottlenecking projects occur A year after that operating experience on the vessel because the key piece of data that you have to have It's the dynamic data of how is that vessel really operating under dynamic conditions. So but I think you can expect Every one of those will get debottlenecked above their nameplate in the future.
Speaker 7
Great. Thank you very much.
Speaker 0
Thank you. Our next question comes from Paul Cheng with Scotiabank. Your line is open.
Speaker 8
Hey, guys. Good morning.
Speaker 4
Good morning, Paul.
Speaker 8
I think several questions. First, John, the net debt to EBITDA less than $2 and at a $60 plus debt doesn't seem to be very conservative number. I Assuming it's just a near term, so what is the longer term expectation? I mean, the EBITDA changed a lot Due to the commodity prices?
Speaker 4
Yes. You're right. I mean, let alone our EBITDA is going to change, 1 from commodity prices and 2 as each FPSO comes on in Guyana, obviously, our EBITDA is going to jump with each ship coming online. So for us, what we did was set that to as kind of a max. And once we got to that Net debt to EBITDA being under 2, that's when we would start with the returns to shareholders.
Now, we have no intention of Increasing debt during that future time period because now we'll be generating free cash flow. So what we will have with each ship coming on as EBITDA goes up, that the EBITDA is going to drive down and is going to drive under 1. So look, we're going to have a very strong balance sheet And obviously be in a position for beginning to increase dividends first and then because of that free cash flow position doing opportunistic share
Speaker 8
Do you have a net debt target at all?
Speaker 4
So really short term, as we said, it is debt 2 times. And then after that, it's just going to be a function of our free cash flow driving it. So quite frankly, I'd love to have that Keep it underneath 1, and we have the portfolio to do it. We're just unique. Each FPSO coming on, I mean, I'll let you put your own Brent assumptions in there, but for the amount of production that we get, all Brent based production, we're just going to have significant EBITDA growth And therefore, that's going to put our balance sheet in a very strong position.
And so we'd like to keep that debt to EBITDA very low From that standpoint and what we do with that excess cash, as John said earlier, is we'll return it to shareholders through dividend increases and share buybacks.
Speaker 8
John, the Q1 working capital was a big use of cash. And in the second quarter, Any kind of guidance that you can provide?
Speaker 4
So let me just do the Q1 first and I'm going to give the normal recurring and there were 2 non So the basic driver of the $220,000,000 draw was an increase in Receivables of $150,000,000 which we're happy to have. Obviously, oil price is going up, so our receivables went up From that standpoint, and then we did have you saw the lower cash cost, the lower capital numbers, so we did have a reduction in payables $70,000,000 So that $150,000,000 $70,000,000 was the draw in working capital. We did have 2 non recurring items. 1 was the As we increase the strike prices on our hedges, so we had premiums paid there, but we also had the reduction in inventory from our VLCC sales. So they net against each other.
So as you move into the Q2 with receivables that should balance out now with the prices, now prices You'll still see that potential increase in receivables. And then we should be building, as We mentioned in our guidance on capital. So I would expect the payables to be, let's just call, flat. So not Forecasting a draw per se in the Q2.
Speaker 8
Okay. Thank you. Great, if I could have a quick question on Bakken, I think in the past that the expectation is that you will get to about 200,000 barrels per day and saw a plateau Forward that for a number of years. So is that still the medium term objective for Bakken? And then finally, on Liza, on the debottleneck, Can you tell us where's the critical path or that what is the unit that in the Liza 1 Your debottleneck allow you that to get a higher production capacity from that ship?
Thank you.
Speaker 3
So let me take the second one first. So again, Paul, the engineering is still underway on Liza Phase 1 optimization project or There is nothing remarkable in it. It's piping changes, etcetera, just to eliminate reduce the friction Flowing through the facility on the topsides. So we can get more color As the engineering of that project gets done. Now regarding the Bakken, now again the primary role of the Bakken And our portfolio is to be a cash engine.
And so as such, the decision to add any rigs in the Bakken It's going to be driven by corporate returns and corporate cash flow needs. Now, if prices remain strong in the second half of This year, we're considering the addition of a 3rd rig in the Q4 of 2021. And then as you indicated, our medium term or long term objective, again, going to be driven by returns And, Drew, my corporate cash flow would be to get the Bakken back to 200,000 barrels a day. That would probably require a 4th rig. And by doing so, at $60 WTI, The Bakken would be a $1,000,000,000 a year free cash flow generator at 200,000 barrels a day.
The other nice thing about the 200,000 barrels a day is it optimizes efficient use of the infrastructure that we have So it's sort of the ultimate sweet spot for the Bakken. But again, whether we add that 4th rig or the 3rd rig is going to be driven by
Speaker 0
Thank you. Our next question comes from Ryan Todd with Simmons Energy. Your line is open.
Speaker 9
Good. Thanks. Maybe a quick one on Guyana. As you think about your drilling program over the rest of the year and maybe into the first half of next year, What are the key issues that you're looking to address or the key questions that you're looking to answer over the next 6 to 12 months? Yes, Greg.
Speaker 3
Yes. Sure, Ryan. So there's really three objectives of The exploration and appraisal program this year with the 3 drilling rigs. The first one is to Praise existing discoveries, and that's really to underpin the 5th and the 6th ship, in Guyana. You know, Waru was 1st cab off the rank, if you will, Long Tail is next.
Tervit will be after that. We'll also do Mako as well. So we want to get those understood with appraisal wells and some DSTs To really inform where is Ship 5 and where is Ship 6 going to go since Yellowtail is number 4. The second objective is to continue to explore the Campanian, to really fill out that patchwork quilt of prospectivity, if you will, between And you'll see in our investor pack, there was a number of polygons there that we'd like to get drilled this year as well. And then the third objective was, is can we get some deeper penetrations in the Santonian?
Certainly, the Santonian has the potential to be a very large In addition to the recoverable resources in Guyana, now remind everyone we've had 4 penetrations coupled with Apache's results. We see that as very positive, but we've got a lot more drilling to do to understand it. And that is another key objective this year, To get some more penetrations in that, so we can begin to piece the puzzle together on the Santonian.
Speaker 9
Thanks, Greg. That was really helpful. And Maybe, John, one for you on a higher level issue. As we Hess has always been active on the ESG related front, Including efforts as you talked about earlier to reduce Scope 1 and 2 emissions. I guess as you step back and consider the ongoing energy transition and look a little further down the line, Are there other roles in which you think Hess may be able to participate?
Or is the best use of your Time and capital are really just going to be bringing on low cost of supply barrels?
Speaker 2
Yes. No, our strategy remains to be focused on growing our resource. The oil resource is going to be needed in the next 20 years. Key is having a low cost of supply and putting ourselves in a position To generate sustainable and industry leading cash flow growth, that's how we're going to maximize returns and value for our shareholders. Having said that, Climate change is real, the greatest scientific challenge of the 21st century.
I'd recommend everybody to read Bill Gates' book, How do we avoid a climate disaster? Because it really talks about the technological challenges ahead of us, The innovation needed, there are no easy answers. The energy transition is going to take a long time, costs a lot of money And need major technological breakthroughs to be able to provide more energy to the world, as I talked about before, But also get on a track to net 0 emissions, greenhouse gas emissions by 2,050. And One way that we are going to lead in that, be part of that is obviously get our own carbon footprint down for Scope 1 and Scope To emissions, the targets that we've set for 2025 actually get us on a trajectory Better and superior to the OGCI or the oil industry standards that have been set, Number 1. And number 2, we are looking at groundbreaking research, and we think nature offers of that opportunity to really make a difference in the work we're doing at the Salk Institute, we're very enthusiastic about Where most people don't realize, but there's more carbon in the soil than there is in the atmosphere.
And if we can Figure out by supporting the great research at the Salk Institute to capture and store carbon in the soil At a much higher rate and a much higher density than currently is being done, that could be a potential game changer and So we're trying to play our role, but the first, second and third priority is to maximize value for our shareholders.
Speaker 9
Great. Thanks, John.
Speaker 0
Thank you. Our next question comes from David Deckelbaum with Cowen. Your line is open.
Speaker 10
I just wanted to just follow-up on some of the Bakken conversations. You had a really attractive disposition earlier in the quarter. I think some of the ideology behind that was the production wasn't hooked up to some of the Hess Ned's dream. Are there still remaining assets up there that fit similar profiles that would be amenable to pruning right now?
Speaker 2
No. The majority of our inventory, very high return locations, Really underpinning, if you assumed a 4 rig program of 15 year drilling inventory, that's intact. This is the southernmost part that, Quite frankly, the returns there weren't as attractive as our current inventory. It wasn't accretive and strategic to Hess Midstream. I would say that was more of a one off unique opportunity where we brought value forward.
The rest of our acreage, we're very excited to have. And again, as Greg said before, the key role of the Bakken is to generate cash flow and free cash flow for the company, and we're going to be guided by returns In terms of what our rig program is.
Speaker 10
I appreciate that. And then just a follow-up for me is just you talked earlier about sort of the optimal level Of Bakken production and really how it becomes like a cash cow now and that's really its role in the portfolio. How do you think about Gulf of Mexico along the same Dane, as it relates to sort of maintaining volumes, are there attractive exploration targets there at high backs that you're looking at beyond 21, that sort of makes sense here or how does the gum fit in right now?
Speaker 2
Yes, Greg, I think it would be great if you would just talk about The role that the Deepwater Gulf plays in terms of being a cash pension as well, but it does have some growth opportunities.
Speaker 3
Absolutely. So the Gulf of Mexico is like the Bakken. It remains an important cash engine and a platform For high return opportunities for Hess. So our minimum objective is to hold it flat. And we have an inventory of tieback opportunities that we believe we can hold Flat.
In the short term, 3 to 4 years probably, once we get back to work with some of the tieback opportunities. First of these high return opportunities, LON-six, which we're currently evaluating with Shell. And If we sanction that, it could quickly add production, with expected first oil 4 months from spud. And then we also have a large number of exploration blocks. So during the downturn, as you recall, When everybody was focused on the Permian, we stayed focused on the offshore, and we acquired 60 new leases in the Gulf, existing leases, So they won't be affected by the Biden moratorium, particularly on new leases.
And in that, we see some very good hub class Opportunities as well, both in the Miocene and the emerging Cretaceous, forefoot play. So, we'd like to get back to work on a hub class opportunity. The first one is likely going to be a well called Huron, Which is a very large, Miocene opportunity. So we've got the inventory to, as a minimum, hold it flat and then Potentially, even grow it. But like the Bakken, investment in the Gulf of Mexico is going to be a function of returns and cash flow needs of the corporation.
Well, we certainly got the inventory to do it and would like to get back to work as soon as we can.
Speaker 10
Thanks for the update, guys.
Speaker 0
Thank you. Our next question comes from Roger Read with Wells Fargo. Your line is open.
Speaker 6
Hey, good morning. Thanks.
Speaker 11
Good morning.
Speaker 6
Just two things, I guess, to follow-up on kind of on the smaller side of things, at least the first one. But as you Talked about the improvement in CapEx per well in the Bakken. I was just curious over the 2019, 2021 period, Is that truly apples to apples with the wells? In other words, kind of similar completion methods And what you're seeing in terms of production per well? In other words, is there an efficiency above and beyond what you're seeing on the CapEx side?
And then my other question was going to be on NOLs and the possibility of a change tax rate,
Speaker 4
how you think about that affecting
Speaker 2
Yes. Greg first and then John.
Speaker 3
Yes, sure. So on the Bakken, No, those wells, let's say, the last 3 years, we've been drilling the same types of wells, really for the past 3 years. There's no differences in, say, like shorter laterals or anything like that. So the trajectory of well costs coming down It's purely lean manufacturing and technology gains along the way. And so the wells that we are drilling this year have been the same.
They've been a 1,200,000 barrel Recoverable, IP 180s of about 120, which was the same as last year. And I think importantly, IRRs Averaging nearly 90% at current oil prices. So again, a great inventory. Got a lot of confidence on my team, Just as we showed with plug and perf or a sliding sleeve, we're doing the same with plug and perf. Through lean manufacturing and technology, we just continue to drive those well costs down and improve productivity As well.
Speaker 4
And then Roger on the tax policy. So it's It's a little early for me to be able to comment on them because from what's been released is more headlines and there's just not that much detail On these areas now, to your point, we do have a significant net operating loss carry forward, which will mitigate The effects of increased tax rates or changes in depreciation methods. So we'll just have to wait for more detail.
Speaker 3
All right. Thank you.
Speaker 0
Thank you. Our next question comes from Bob Breckett with Bernstein Research. Your line is open.
Speaker 11
Good morning all. Thanks for taking my question at the end here. I had a question. As you return to the southeast part of the block and explore, Sounds like the targets are going to be those deeper penetrations in the Pantonian. Can you talk about, one, is there a double Opportunity there?
Are there still ways to drill wells to hit Campanian plus Santonian? And maybe a broader question About the future of exploration, are there big perhaps riskier prospects that you could target in future years That could be somewhat game changers that could move up the queue in terms of the development plan.
Speaker 2
Yes. Thanks, Bob. Greg?
Speaker 3
Yes. So Bob, look, no, the Santonian really underlies the entire lease of complex. So I don't want to imply You know that the southeast portion of the block is the best area for the Santonian. It really underlies all of the Campanian. Now having said that, we need more penetrations to understand it.
And we'll get a number of penetrations this year Through both ways that you suggested, one is through deepening deeper tails on Campanian Exploration Wells, But also, some standalone, Santonian penetrations as well. So we'll get a good sense. With the 4 that we have under our belt, Coupled with Apache's results, we're pretty excited about the Santonian, but we've just got more drilling to do. But again, The areal extent of the Santonian reservoir system is as big or bigger than the Liza complex. So there I wouldn't pick any areas being particularly the sweet spot yet.
Speaker 2
Yes. And Bob, to your other point, we still see significant exploration prospectivity on this block As we drill more and get more seismic definition on drilling opportunities, some of it's going to be Campanian, some of it's It's going to be Santoni and some of it's going to be further out. Obviously, we have this aggressive and active program this year. There's more to come. And our partner ExxonMobil, I think, in their Investor Day made it pretty clear that there's potential to double the discovered resource on the block, And we would stand by that in terms of the exploration upside that still remains.
Speaker 5
Thanks for that.
Speaker 0
Thank you. Our next question comes from Vin Lovaglio with Mizuho. Your line is open.
Speaker 11
Hey, guys. Thanks for taking my question. First one on cash return. Different operators have kind of laid out different Strategy is, I think, based on business mix, but mainly centered around percentage of operating cash flow or percentage of This cash flow generated back to shareholders. You guys are in a unique spot with Guyana.
Just wondering if the asset kind of pushes you in one direction or the other as far as Percentage of operating cash flow or percentage of free cash flow back to shareholders or maybe something entirely different? Thanks.
Speaker 2
Yes. Those formulas are mainly for shale producers. That's For an assembly line of cash flow generation, we have sustainable and industry leading cash flow growth. So percentages, I don't think, are as relevant to us. But what we've been very clear on, as we generate free cash, As John Reilly said, the first priority is to pay down the term loan.
And then after that, the majority of our free cash flow will go back as cash returns to shareholders, first increasing the dividend and then, opportunistic share repurchases. So the word majority is the
Speaker 11
Great. Thanks. And maybe just to Guyana quickly, you had outlined basically a one FPSO Per year, kind of starting with Payara in 2024. In the release, you did mention at least Six FPSOs by 2027, maybe reading a little bit too deep into it here, but just wondering if there's any factors or variables that we should be considering or that you guys are considering that could potentially accelerate the FPSO deployment schedule Longer term.
Speaker 2
Thank you. Yes. Look, our exploration appraisal program this year is to really help define what the 5th ship will be and potentially the 6th Chip in terms of development, and I think the cadence of about 1 ship a year is the one we're aiming at In terms of design 1, build many, being capital disciplined, bringing value forward, ExxonMobil, as Greg said before, is doing an Standing job of project management on building these ships and bringing them into theater. Obviously, debugging Liza 1, but we'll benefit for Liza 2 in terms of that. And it's basically this cadence of about 1 ship a year and The exploration appraisal program is to give definition to those future developments.
Speaker 5
Thanks, guys. Appreciate it.
Speaker 0
Thank you. Our next question comes from Monroe Helm with Borrow Handley. Your line is open.
Speaker 12
Thank you very much for getting me in the queue. Congratulations on continuing to execute on your game plan, which is Differentiated asset base and the market is starting to recognize
Speaker 3
it. Thank you, Bob.
Speaker 12
We had My questions are kind of follow on to the questions on the Santonian. Greg, can you be more specific about which well any of the wells that you've identified To drill my first half of the year, targeting this Antonia, and I was kind of curious along that line as whether or not the What the Long Tail sidetrack is about?
Speaker 3
Yes. So there will be Monroe, certainly in the early first part of the year, First half of the year, Long Tail 3 will have a tail on it that will dip down into the Santonian and Whiptail will as Well, so recall Whittail is kind of the next Campanian exploration prospect in the queue right after So both of those will have Santoni and tails on them. And then there will be other ones in the second half of the year. We're still trying to define the exact drilling order in the second half of the year, but those are to be the first the next 2.
Speaker 12
And I think you said that there will be specific to the Santonian test. Is that correct?
Speaker 3
There will be, yes, at least one that will be aimed at the Santonian
Speaker 12
My second question is, Exxon says that there's is he double the reserves of the exploration program? Does that include this, Antonio?
Speaker 4
Yes.
Speaker 12
Okay. Thank you very much.
Speaker 3
Thank you. Thank you.
Speaker 0
Thank you very much. This concludes today's conference call. Thank you for your participation. You may now disconnect. Everyone, have a great
Speaker 3
day. Thank you.