Hess Corp

NYSE:HES

Earnings Call Transcript 2021-Q1

[Operator]

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. [Operator Instructions] 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.

[Jay Wilson, VP, IR]

Thank you, Catherine. Good morning, everyone, and thank you for participating in our first quarter 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 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’ 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 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 their presentations.

On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer.

I’ll now turn the call over to John Hess.

[John Hess, CEO]

Thank you, Jay. Welcome to our first quarter 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 Rielly will 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 sustain 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 on line, 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 $1.86 billion of cash on the balance sheet, a $3.5 billion revolving credit facility, which is undrawn and was recently extended by one year to 2024, and no debt maturities until 2023.

We have maintained a disciplined capital and exploratory budget for 2021 of $1.9 billion. More than 80% of this year’s capital spend is allocated to Guyana, where our three sanctioned oil developments have a breakeven oil price of between $25 and $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 two asset sales. In March, we entered into an agreement to sell our oil and gas interests in Denmark for a total consideration of $150 million, effective January 1, 2021. This transaction is expected to close in the third quarter. On April 8th, we announced the sale of our Little Knife and Murphy Creek nonstrategic acreage interests in the Bakken for a total consideration of $312 million, effective March 1, 2021. This acreage is located in the southernmost portion of our Bakken position and is not 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 million 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 billion barrels of oil equivalent, and we continue to see multibillion barrels of future exploration potential remaining. We have an active exploration and appraisal program this year on the Stabroek Block. Yesterday we announced a discovery at the Uaru-2 well with encouraging results that further define the large areal extent of this accumulation, underpinning a potential future oil development. In addition, drilling activities are underway for appraisal at the Longtail-3 well and for exploration at the Koebi-1 prospect.

Production from Liza Phase 1 ran at its full capacity of 120,000 gross barrels of oil per day during the first quarter. 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 are completed in approximately three months. 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 first oil in early 2022 with a capacity of 220,000 gross barrels of oil per day. Our third oil development on the Stabroek Block at the Payara Field is expected to achieve first oil in 2024, also with a capacity of 220,000 gross barrels of oil per day.

Engineering work for Yellowtail, a fourth development on the Stabroek Block, is underway with

anticipated startup 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 longstanding 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 zero emissions by 2050. 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 five-year emissions reduction targets, reducing 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 five-year emissions reduction targets for 2025, which are to reduce operated Scope 1 and Scope 2 greenhouse gas emissions intensity by approximately 44% and methane emissions intensity by approximately 50% from 2017 levels.

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.

[Greg Hill, COO]

Thanks, John.

Overall, in the first 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 the first quarter averaged 158,000 barrels of oil equivalent per day, which was below our guidance of approximately 170,000 barrels of oil equivalent per day. Of this shortfall, approximately 8,000 barrels per day was due to the significant increase in NGL prices in the quarter.

Much of our third-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. POP volumes from these contracts get reported as Hess net production. When NGL prices increase, as they did in the first quarter, it takes fewer barrels to cover our gas processing fees. Hence our reported NGL production was reduced. 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 Uri, which brought power outages and average wind chill temperatures of minus 34 degrees Fahrenheit for two 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 first quarter, we drilled 11 wells and brought four new wells on line. In the second quarter, we expect to drill approximately 15 wells and to bring approximately 10 new wells on line, and for the full year 2021, we expect to drill approximately 55 wells and bring approximately 45 new wells on line. Thanks to the continued application of Lean and technology, our drilling and completion costs are expected to average approximately $5.8 million per well in 2021, which represents a 6.5% reduction from $6.2 million in 2020 and a 15% reduction from $6.8 million in 2019.

For the second quarter, 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 of the Tioga Gas Plant in the third quarter. We expect net production to build in the second half of the year and forecast a 2021 exit rate of between 170,000 and 175,000 barrels of oil equivalent per day.

Moving to the offshore. In the deepwater Gulf of Mexico, first 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 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 equivalent per day, reflecting planned maintenance downtime and natural field declines.

In the Gulf of Thailand, net production in the first quarter was 64,000 barrels of oil equivalent per day, as natural gas nominations continued to increase due to strong economic growth. Second 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 and $35 per barrel, represent some of the lowest project breakeven oil prices in the industry. Production from Liza Phase 1 averaged 121,000 gross barrels of oil per day, or 31,000 barrels of oil per day net to Hess in the first quarter.

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 11th. Production is currently averaging between 110,000 and 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 three months, production is expected to return to or above nameplate capacity of 120,000 barrels of oil per day. For the second quarter, we now forecast net production to average between 20,000 and 25,000 barrels of oil per day and our full year 2021 net production 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 fourth quarter of 2021. Production optimization work is now planned in the fourth quarter which will further increase the Liza Destiny’s production capacity.

I think, it is 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 to 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 third development, Payara, is also progressing to plan, with about 38% of the overall work completed. The project will utilize the Liza Prosperity FPSO, which will have the capacity to produce up to 220,000 gross barrels of oil per day. The FPSO hull is complete and topsides construction activities have commenced in Singapore. First oil remains on track for 2024.

Front-end engineering and design work continues for the fourth 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 Uaru-2 well successfully appraised the Uaru-1 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 areal extent. The Stena DrillMax is currently appraising the Longtail discovery. Additional appraisal is planned at Mako and in the Turbot area, which will help define our fifth and sixth developments on the block.

The Stena Carron has commenced exploration drilling at the Koebi-1 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 2021 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, companywide second quarter net production is forecast to average between 290,000 and 295,000 barrels of oil equivalent per day. 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; second factor is, approximately 6,000 barrels of oil equivalent per day related to the sale of our interests in Denmark and non-strategic acreage in North Dakota, for which we brought forward 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 and 175,000 barrels of oil equivalent per day.

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 will enable us to deliver industry-leading performance and value to our shareholders for many years to come.

I will now turn the call over to John Rielly.

[John Rielly, CFO]

Thanks Greg.

In my remarks today, I will compare results from the first quarter of 2021 to the fourth quarter of 2020.

We had net income of $252 million in the first quarter of 2021 compared to an adjusted net loss of $176 million, which excluded an after tax gain of $79 million from an asset sale in the fourth quarter of 2020.

Turning to E&P. E&P had net income of $308 million in the first quarter of 2021 compared to an adjusted net loss of $118 million in the previous quarter. The changes in the after-tax components of adjusted E&P results between the first quarter of 2021 and the fourth quarter of 2020 were as follows: Higher realized crude oil, NGL, and natural gas selling prices increased earnings by $192 million; Higher sales volumes increased earnings by $99 million; Lower DD&A expense increased earnings by $88 million; Lower cash costs increased earnings by $39 million; All other items increased earnings by $8 million, for an overall increase in first quarter earnings of $426 million.

Excluding the two VLCC cargo sales, our E&P sales volumes were overlifted compared with production by approximately 300,000 barrels, which improved after-tax results by approximately $10 million. The sales from the two VLCC cargos increased net income by approximately $70 million in the quarter. The impact of higher NGL prices improved first quarter earnings by approximately $55 million 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 fourth quarter of 2020.

Turning to Midstream. The Midstream segment had net income of $75 million in the first quarter of 2021 compared to $62 million in the prior quarter. Midstream EBITDA, before non-controlling interests, amounted to $225 million in the first quarter of 2021 compared to $198 million in the previous quarter. In March, Hess received net proceeds of $70 million 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 $1.86 billion, and our total liquidity was $5.5 billion including available committed credit facilities, while debt and finance lease obligations totaled $6.6 billion. Our fully undrawn $3.5 billion revolving credit facility is now committed through May 2024, following the amendment executed earlier this month to extend the maturity date by one year.

In the first quarter of 2021, net cash provided by operating activities before changes in working capital was $815 million compared with $532 million in the fourth quarter of 2020, primarily due to higher realized selling prices. In the first quarter, net cash provided from operating activities after changes in working capital was $591 million compared with $486 million in the prior quarter.

The sale of our Little Knife and Murphy Creek acreage in the Bakken for total consideration of $312 million is expected to close within the next few weeks and the sale of our interests in Denmark for total consideration of $150 million is expected to close in the third quarter of this year.

Now, turning to guidance. Our E&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 first quarter of 2021. We project E&P cash costs, excluding Libya, to be in the range of $12 to $13 per barrel of oil equivalent for the second quarter, primarily reflecting the timing of maintenance and workover spend. Full year E&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&A expense was $11.83 per barrel of oil equivalent, including Libya and $12.36 per barrel of oil equivalent, excluding Libya in the first quarter. DD&A expense, excluding Libya, is forecast to be in the range of $11.50 to $12.50 per barrel of oil equivalent for the second quarter and full year guidance of $12 to $13 per barrel of oil equivalent is unchanged. This results in projected total E&P unit operating costs, excluding Libya, to be in the range of $23.50 to $25.50 per barrel of oil equivalent for the second 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 million to $45 million in the second quarter and full year guidance of $170 million to $180 million is unchanged. The midstream tariff is projected to be in the range of $260 million to $270 million for the second quarter and full year guidance of $1,090 million to $1,115 million is unchanged.

E&P income tax expense, excluding Libya, is expected to be in the range of $25 million to $30 million for the second quarter and $105 million to $115 million for the full year, which is up from previous guidance of $80 million to $90 million due to higher commodity prices.

We expect non-cash option premium amortization will be approximately $65 million for the second quarter and approximately $245 million for the full year, which is up from previous guidance of $205 million, reflecting additional premiums paid to increase the strike price on our crude oil hedging contracts.

In the second quarter, we expect to sell two 1 million barrel cargos from Guyana whereas we sold three 1 million barrel cargos in the first quarter and we expect to sell five 1 million barrel cargos over the second half of the year.

Our E&P capital and exploratory expenditures are expected to be approximately $500 million in the second quarter and the full year guidance of approximately $1.9 billion remains unchanged.

For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be in the range of $60 million to $70 million for the second quarter and the full year guidance of $280 million to $290 million remains unchanged.

For Corporate. Corporate expenses are estimated to be in the range of $30 million to $35 million for the second quarter and full year guidance of $130 million to $140 million is unchanged. Interest expense is estimated to be in the range of $95 million to $100 million for the second quarter and full year guidance of $380 million to $390 million is unchanged.

This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

[Operator]

[Operator Instructions] Your first question comes from Neil Mehta with Goldman Sachs.

[Neil Mehta, Goldman Sachs]

Congrats on a good quarter. John, you talked about accelerating returns back to shareholders when you get net debt-to-EBITDA sub 2 times. It seems like between Liza-2 and the forward curve, you’re going to get there inside of one year. So, how do you think about what to do with the excess cash and the optimal allocation of that to shareholders?

[Greg Hill, COO]

Thanks, Neil. Yes. Now, we’ve had a strong first quarter 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 a 220,000 barrel a day ship. So, we’ll get -- our entitlement there will significantly drive our cash flow inflection for us next year. And therefore, our debt-to-EBITDA will begin to get under 2, as we take that excess cash flow, then we have and pay down the term loan. So, the first thing that we’re going to do with excess cash flow is pay down the $1 billion term loan. Once we have that paid off and that increased EBITDA from Phase 2, 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, we’ll have a significant cash flow growth, we’ll begin to do opportunistic share repurchases after the dividend increase.

[Neil Mehta, Goldman Sachs]

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 and the FPSOs that come in post 2026 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 risks.

[John Hess, CEO]

Yes. Great question, Neil. Thank you. A couple of points we’d like to make. Look, the world has two future challenges. One is how do we provide more energy supply, 20% more energy supply by 2040? And how do we get to net zero emissions by 2050? 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 2040. So, it’s not just about climate literacy, it’s also about energy literacy. Oil and gas is still going to be needed 20 years out.

The key to all of this, because none of us can call an 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 of 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 it forward almost every year. First in 2022 with Liza-2, then in 2024 with Payara, then Yellowtail in 2025. The payouts are very quick and the 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.

[Operator]

Our next question comes from Arun Jayaram with JP Morgan.

[Arun Jayaram, JP Morgan]

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, I 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.

[Greg Hill, COO]

Yes. Sure. So, let me take it in two 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 three 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 increment, as you mentioned, is the debottlenecking project, which now is going to occur in the fourth quarter. And that will take Liza Phase 1 up another incremental production. Now, they’re still in final engineering phase 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 fourth quarter. Also, in the fourth quarter, Exxon is going to replace the existing flash gas compressor with some of the components that have been redesigned.

So, that shutdown in the fourth quarter, about 14 days, will accomplish those two things. It will be the debottlenecking and also the installation of a new redesigned flash gas compressor for Phase 1.

[Arun Jayaram, JP Morgan]

Great. And my follow-up is perhaps for John Rielly. 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?

[John Rielly, CFO]

Right now, Exxon is in discussions with SBM. They’re having commercial discussions on the purchases of that. 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.

[Operator]

Our next question comes from Doug Leggate with Bank of America.

[Doug Leggate, Bank of America]

So, Greg, Payara, 38% complete as at least on the hull SCM is telling us 12 to 14 months is the standard sort of topside 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 boats are ready middle of next year?

[Greg Hill, COO]

Well, I mean, Doug, as you know, Payara does have a very extensive drilling and SURF program. In particular, the SURF requires three 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 amount of SURF work that has to be done. But ExxonMobil is executing extremely well. Hopefully, Payara will come on earlier in 2024. But, we’ll see, Doug. There’s a lot of work left to do yet.

[Doug Leggate, Bank of America]

Okay. We got to get an in-person dinner, Greg. I’ll take a small bet with you that we see a [indiscernible] at some point. Okay.

My follow-up is on the exit rate in the Bakken. How have you been able to lose 7,000, 8,000 barrels a day of NGLs in the POP contracts. But on the fourth quarter, you also guided to an exit rate of about 175 has been reasonable even with the second rig. So, can you just walk us through what’s going better there to allow you to stick with the same guidance? I’ll leave it there. Thanks.

[Greg Hill, COO]

John, do you want to answer the POP contract question, John Rielly?

[John Rielly, CFO]

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 fourth. So, we’re not hit with this high number on that POP in the fourth quarter. But yet, there is still impact on that. And originally, we were guiding at that 175. Now with the 170 to 175, that POP does have impact to it. And I’ll start with Greg. But, the well performance is 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 fourth quarter, only four in the first. We’re just beginning now to pick up from the second rig, and that will really pick up in the third and fourth quarter. 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 170 to 175.

Greg, I don’t know if there’s anything you want to add.

[Greg Hill, COO]

No. I think you nailed it, John. Yes.

[Operator]

Our next question comes from Jeanine Wai with Barclays.

[Jeanine Wai, Barclays]

My first question is on Guyana. The latest well, the Uaru-2, 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 on the block? And do you plan to test them elsewhere this year?

[John Hess, CEO]

Go ahead, Greg.

[Greg Hill, COO]

Yes. Thanks, Jeanine. So, again, Uaru-2 was a great result, right? We had high-quality oil sands, 120 feet. I think, the most significant part about Uaru was that it was 6.8 miles from Uaru-1, which demonstrates a very large areal extent for the Uaru reservoir itself.

And 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 of the block. But certainly, the reason we didn’t call it the 19th discovery is in this particular location. It’s clearly not as significant as the other 18, right? But, it does have some read-through to other parts of the block.

[John Hess, CEO]

The key is that the appraisal is very encouraging results. You have excellent reservoir characteristics. You have high-quality oil. And given that Uaru-1 versus Uaru-2 is 6.8 miles away, it shows the potential for large aerial extent of a highly-prolific high-quality reservoir.

[Jeanine Wai, Barclays]

Okay. Got you. That’s really helpful. Thank you. My second question is maybe just going back to the debottlenecking discussion and Arun’s question. Liza 1 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 debottlenecking, it really pulls forward a lot of NAV there. So, just wondering kind of the potential for that for the 220 ships.

[John Hess, CEO]

Greg?

[Greg Hill, COO]

Yes. Jeanine, I think you could assume that there would be debottlenecking potential on all those ships. What typically happens is, you’ll 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 is 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.

[Operator]

Our next question comes from Paul Cheng with Scotiabank.

[Paul Cheng, Scotiabank]

I think, several questions. First, John, the net debt-to-EBITDA less than 2. And at $60 plus, that doesn’t seem to be a very conservative number. I presume it’s just a near term. So, what is the longer term expectation? I mean that the EBITDA changed a lot due to the commodity prices.

[John Rielly, CFO]

Yes. You’re right. I mean, let alone our EBITDA is going to change, one from commodity prices, and two, as each FPSO comes on in Guyana, obviously, our EBITDA is going to jump with each ship coming on line. So, for us, what we did was set that 2 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 is the EBITDA goes up, debt to 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 beginning to increase dividends first, and then because of that free cash flow position, doing opportunistic share repurchases.

[Paul Cheng, Scotiabank]

Do you have a net debt target at all?

[John Rielly, CFO]

So, really short term, as we said, it is that 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.

[Paul Cheng, Scotiabank]

John, the first quarter working capital was a big use of cash. And in the second quarter, any kind of guidance that you can provide?

[John Rielly, CFO]

So, let me just do the first quarter first, and I’m going to give the normal recurring. And there were two nonrecurring things that offset each other.

So, the basic driver of the $220 million draw was an increase in receivables of $150 million, which we’re happy to have. Obviously, oil prices 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 of $70 million. So, that $150 million and $70 million was the draw in working capital.

We did have two nonrecurring items. One was the -- as we increased 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 second quarter with receivables that should balance out now with the prices, now if prices continue to go up, 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 second quarter.

[Paul Cheng, Scotiabank]

Okay. Thank you. Greg, 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 sort of total 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 you debottleneck allow you to get a higher production capacity from that ship?

[Greg Hill, COO]

So, let me take the second one first. So again, Paul, the engineering is still underway on Liza Phase 1 optimization project or debottlenecking. There’s nothing remarkable on it. It’s piping changes, et cetera, just to eliminate, reduce the friction basically flowing through the facility on the top sides. So, we can give more color as the engineering of that project gets done.

Now, regarding the Bakken, again, the primary role of the Bakken in our portfolio is to be a cash engine. And so, as such, the decision to add any rigs in the Bakken is 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 third rig in the fourth quarter of 2021. And then, as you indicated, our medium-term or long-term objective, again going to be driven by returns and driven by corporate cash flow, would be to get the Bakken back to 200,000 barrels a day. That would probably require a fourth rig. And by doing so, at $60 WTI, the Bakken would be $1 billion 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 built up there. So, it’s sort of the ultimate sweet spot for the Bakken. But again, whether we add that fourth rig or the third rig is going to be driven by returns and corporate cash flow needs, because the role of the Bakken is to be a cash engine.

[Operator]

Our next question comes from Ryan Todd with Simmons Energy.

[Ryan Todd, Simmons Energy]

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?

[John Hess, CEO]

Greg?

[Greg Hill, COO]

Sure, Ryan. So, there’s really three objectives of the exploration appraisal program this year with the three drilling rigs. The first one is to appraise existing discoveries, and that’s really to underpin the fifth and the sixth ship in Guyana. So, Uaru was first cab off the rank, if you will; Longtail’s next; Turbot 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 ship 5 and where ship 6 is 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 Turbot and Liza. 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 addition to the recoverable resources in Guyana. And I’ll remind everyone, we’ve had four 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.

[Ryan Todd, Simmons Energy]

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?

[John Hess, CEO]

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 make -- 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 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 zero emissions, greenhouse gas emissions by 2050.

And one way that we are going to lead in that and be part of that is obviously get our own carbon footprint down for Scope 1 and Scope 2 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 one.

And number two, we are looking at groundbreaking research, and we think nature offers that opportunity to really make a difference and the work we’re doing at 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 contribute to getting us to net zero carbon emissions.

So, we’re trying to play our role, but the first, second and third priority is to maximize value for our shareholders.

[Operator]

Our next question comes from David Deckelbaum with Cowen.

[David Deckelbaum, Cowen]

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 Midstream. Are there still remaining assets out there that fit similar profiles that would be amenable to pruning right now?

[John Hess, CEO]

No. The majority of our inventory, very high-return locations, really underpinning, if you assumed a four-rig program, a 15-year drilling inventory. That’s intact. This is the southern most part that, quite frankly, the returns there weren’t as attractive as our current inventory. It wasn’t accretive and strategic to Hess Midstream. So, 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.

[David Deckelbaum, Cowen]

I appreciate that. And 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 the Gulf of Mexico along the same vein as it relates to sort of maintaining volumes? Are there attractive exploration targets there or tiebacks that you’re looking at beyond ‘21 that sort of make sense here, or how does the gum fit in right now?

[John Hess, CEO]

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 engine as well, but it does have some growth opportunities.

[Greg Hill, COO]

Absolutely. So, the Gulf of Mexico is like the Bakken, remains an important cash engine and a platform for higher 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 it flat in the short term, three to four years probably, once we get back to work with some of the tieback opportunities.

First, these high-return opportunities, Llano-6, which we’re currently evaluating with Shell, and if we sanction that, it could quickly add production, with expected first oil four months from the 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 potentially on new leases. And in that, we see some very good hub class opportunities as well, both in the Miocene and the emerging Cretaceous per foot [ph] 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 Heron, [ph] 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. But, we certainly got the inventory to do it and would like to get back to work as soon as we can.

[Operator]

Our next question comes from Roger Read with Wells Fargo.

[Roger Read, Wells Fargo]

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 ‘19, ‘20, ‘21 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 changed tax rate, how you think about that affecting utilization of those over time?

[John Hess, CEO]

Yes. Greg, first and then John.

[Greg Hill, COO]

Yes, sure. So, on the Bakken, no, those wells -- let’s say, the last three years, we’ve been drilling the same types of wells really for the past three years. So, there’s no differences in, say, like shorter laterals or anything like that, so that the trajectory of well costs coming down is 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 1.2 million 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 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.

[John Rielly, CFO]

Then Roger, on the tax policy. So, it’s a little early for me to be able to comment on them because what -- from what’s been released, there’s 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 carryforward, which will mitigate the effects of increased tax rates or changes in depreciation method. So, we’ll just have to wait for more detail.

[Operator]

Our next question comes from Bob Brackett with Bernstein Research.

[Bob Brackett, Bernstein Research]

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 Santonian. 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?

[John Hess, CEO]

Yes. Thanks, Bob. Greg?

[Greg Hill, COO]

Yes. So, Bob, look, no, the Santonian really underlies the entire Liza complex. So, I don’t want to imply that 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 four 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, they’re -- I wouldn’t pick any area as being particularly the sweet spot yet.

[John Hess, CEO]

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 going to be Santonian, 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.

[Operator]

Our next question comes from Vin Lovaglio with Mizuho.

[Vin Lovaglio, Mizuho]

First one on cash return. Different operators have kind of laid out different strategies I think based on business mix, but mainly centered around percentage of operating cash flow or percentage of excess 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, a percentage of free cash flow back to shareholders or maybe something entirely different. Thanks.

[John Hess, CEO]

Yes. Those formulas are mainly for shale producers, that’s more 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 Rielly 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 keyword there.

[Vin Lovaglio, Mizuho]

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. I’m maybe reading a little bit too deep into it here. But, just wondering if there’s any hurdles, factors or variables that we should be considering or that you guys are considering that could potentially accelerate the FPSO deployment schedule longer term?

[John Hess, CEO]

Yes. Look, our exploration appraisal program this year is to really help define what the fifth ship will be and potentially the sixth ship 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 one, build many, being capital disciplined, bringing value forward. ExxonMobil, as Greg said before, is doing an outstanding 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 one ship a year and the exploration appraisal program is to give definition to those future developments.

[Operator]

Our next question comes from Monroe Helm with Barrow Hanley.

[Monroe Helm, Barrow Hanley]

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 it. Really had my questions 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 in the first half of the year targeting the Santonian kind of as well along that line is whether or not what the long-held sidetracks about.

[Greg Hill, COO]

Yes. So, there will be -- Monroe, certainly in the early first part of the year, first half of the year, Longtail-3 will have a tail on it. That will dip down into the Santonian, and Whiptail will as well. So, recall Whiptail is kind of the next Campanian on exploration prospect in the queue right after Koebi. So, both of those will have Santonian 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 two.

[Monroe Helm, Barrow Hanley]

And I think you said that there will be specific Santonian test. Is that correct?

[Greg Hill, COO]

There will be, yes, at least one, that will be aimed at the Santonian itself.

[Monroe Helm, Barrow Hanley]

My second question is, Exxon says that there’s -- double the reserves for the exploration program. Does that include Santonian?

[John Hess, CEO]

Yes.

[Monroe Helm, Barrow Hanley]

Okay. Thank you very much.

[John Hess, CEO]

Thank you.

[Operator]

Thank you very much. This concludes today’s conference call. Thank you for your participation. You may now disconnect. Everyone, have a great day.

[John Hess, CEO]

Thank you.