Hess Q4 2021 Earnings Call Transcript

Quartr
Provided by Quartr
January 26, 2022

There are 16 speakers on the call.

Operator

Good day, ladies and gentlemen, and welcome to the 4th Quarter 2021 Hess Corporation Conference Call. My name is Josh, and I will be your operator for today. At this time, all participants are in a listen only mode. Later, we will conduct a question and answer session. Followed by 0, and we will be happy to assist you.

Operator

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, Josh. Good morning, everyone, and thank you for participating 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 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.

Speaker 1

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. On the call with me today are John Hess, Chief Executive Officer Greg Hill, Chief Operating Officer and John Reilly, Chief Financial Officer. In case of any audio issues, we will be posting transcripts of each I'll now turn the call over to John Hess.

Speaker 2

Thank you, Jay. Good morning. Welcome to our Q4 conference call. I hope All of you and your families are well and staying healthy. Today, I will review our continued progress in executing our strategy and provide a look at the year ahead.

Speaker 2

Then Greg Hill will discuss our operations and John Reilly will cover our financial results. 2022 marks an inflection point in the execution of our strategy. As we go from investment mode to return of capital mode, while still being able to invest to grow our business. Our strategy has been and continues to be to deliver high return resource growth, deliver a low cost to supply And deliver industry leading cash flow growth, while at the same time maintain our industry leadership in environmental, Social and governance and disclosure. In terms of resource growth, we have been disciplined in allocating capital to the best rocks for the best returns And have built a differentiated portfolio focused on the Bakken, deepwater Gulf of Mexico, Southeast Asia and Guyana with its multiple phases of low cost oil developments.

Speaker 2

We expect all 4 of these assets to be free cash flow generative in 2022. In terms of the low cost of supply, because of the investments we are making, our cash costs by 2026 are forecast to declining Approximately 25 percent to $9 per barrel of oil equivalent versus 2021. And Our portfolio breakeven is positioned to be one of the lowest in the industry in 2026, decreasing to $45 per barrel Brent. In terms of cash flow growth, we have an industry leading rate of change and durability story. We are positioned to grow our cash flow At a compound rate of 25% per year out to 2026 based upon a Brent price of $65 per barrel And any business that can grow its cash flow at twice the rate of its top line is a business you want to have in your investment portfolio.

Speaker 2

Our company has been in the investment mode for the last several years, building our portfolio to where it can deliver durable cash flow growth. The Alisa Phase 2 project, which is on track for 1st oil this quarter, will add $1,000,000,000 of net operating cash flow annually at $5 Brent. Following project startup, we plan to repay the remaining $500,000,000 term loan and to increase our base dividend. As our portfolio becomes increasingly free cash flow positive in the coming years, our top priority Will be both to grow the base dividend and also accelerate our share repurchases. Key to our strategy is Guyana, The industry's largest new oil province discovered in the last decade, which is positioned to be one of the highest margin, Lowest carbon intensity oil developments globally according to a study by Wood Mackenzie.

Speaker 2

The world will need these low cost, high value resources to meet growing energy demand, particularly given underinvestment by our industry in recent years. The International Energy Agency's latest World Energy Outlook provides multiple scenarios for addressing the dual challenge of growing global energy supply by about 20% over the next 20 years and reaching net 0 emissions by 2,050. In all of the IEA scenarios, oil and gas will be needed for decades to come and significantly more investment will be required, Much more in renewables and much more in oil and gas. Our reasonable estimate for global oil and gas From these IEA scenarios is approximately $450,000,000,000 each year over the next 10 years. In 2020, that number was $300,000,000,000 Last year's investment was $340,000,000,000 So while investors in oil and gas companies need to remain capital disciplined, we also need to invest more in oil and gas than we are currently to ensure an affordable, just and secure energy transition.

Speaker 2

Turning to our plans for the year ahead. Our 2022 capital and exploratory budget is $2,600,000,000 of which approximately 80% will be allocated to Guyana and the Bakken. On the Stabroek Block in Guyana, where Hess has a 30% interest and ExxonMobil is the operator, we continue to see the potential for at least 6 floating production Storage and offloading vessels or FPSOs in 2027 with a production capacity of more than 1,000,000 gross barrels of oil per day And up to 10 FPSOs to develop the discovered resources on the block. Our 3 sanctioned oil developments on the block have a Brent breakeven oil price of between $25 $35 per barrel. In terms of our Guyana oil developments, Production capacity at the Liza Phase 1 development is expected to increase to more than 140,000 gross barrels of oil per day following Production optimization work.

Speaker 2

The Liza Phase 2 development is on track for start up this quarter with a gross production capacity of 220,000 barrels of oil per day. Our 3rd development on the Stabroek Block at the Payara field Is on track for production startup in 2024, also with gross capacity of approximately 220,000 barrels of oil per day. The Yellowtail development has world class economics and will be the largest to date on the Stabroek Block, developing nearly 1,000,000,000 barrels of oil With a gross production capacity of approximately 250,000 barrels of oil per day, the Yellowtail project continues to make progress, Has the full support of the government of Guyana, which is finalizing its 3rd party review and remains on track for production startup in 2025. We will continue to invest in an active exploration and appraisal program in Guyana in 2022, With approximately 12 wells planned for the Stabroek Block. Earlier this month, we announced 2 more significant discoveries on the block at the Fang Tooth and Lalau wells.

Speaker 2

With these discoveries, the gross discovered recoverable resource estimate for the block is more than 10,000,000,000 barrels of oil equivalent, And we continue to see multi 1000000000 barrels of future exploration potential remaining. Positive results at fine tooth, our first standalone Deep exploration prospect confirm the deeper exploration potential of the block. Both discoveries further underpin our queue of future low cost oil development opportunities. In the Bakken, we plan to operate a 3 rig program in 2022, which will enable us to generate significant free cash flow, lower our unit cash costs and further optimize our infrastructure. Greg and our Bakken team continue to do an outstanding job of applying lean manufacturing principles to keep driving down costs and building a culture of innovation and efficiency.

Speaker 2

We will also continue to invest in our operated cash engines offshore. In the Gulf of Mexico, we will drill the Huron No. 1 exploration well and also a tieback well at Delano Field. And in Southeast Asia, we will invest in drilling and facilities, some of which was previously deferred due to COVID and low commodity prices. We are proud of our workforce for living that has values by working safely and delivering strong operating results, especially during the pandemic.

Speaker 2

As we continue to execute our strategy, our commitment to sustainability will remain a top priority. Our Board and senior leadership have set aggressive 5 year targets for greenhouse gas emissions reduction for 2025. Most recently, we endorsed the World Bank's 0 Routine Flaring by 2,030 initiative and have set a target to eliminate Routine flaring from our operations by the end of 2025. We are honored to have been recognized throughout 2021 as an industry leader in our environmental, social and governance performance and disclosure. In December, we leadership status in CDP's Annual Global Climate Analysis for the 13th consecutive year.

Speaker 2

And in November, Earned a place on the Dow Jones Sustainability Index for North America for the 12th consecutive year. In summary, 2022 marks an inflection point in the execution of our strategy. We have built a differentiated portfolio offering a unique value proposition, Delivering durable cash flow growth that enables us to continue to invest in some of the highest return projects in the industry and also to start growing our cash returns to our shareholders. I will now turn the call over to Greg for an operational update.

Speaker 3

Thanks, John. 2021 was another year of strong Operating performance and strategic execution for Hess. Starting with reserves, proved reserves at the end of 2021 stood at 1,300,000,000 barrels of oil equivalent. Net proved reserve additions in 2021 totaled 348,000,000 barrels of oil equivalent, including positive net price revisions of 107,000,000 barrels Oil equivalent resulting in an overall 2021 production replacement ratio of 2 95% And a finding and development cost of approximately $5.25 per barrel of oil equivalent. Now turning to production.

Speaker 3

In the Q4 and full year 2021, company wide net production averaged 295,000 barrels Oil equivalent per day, excluding Libya, in line with our guidance. For the full year 2022, We forecast net production to increase by 12% to 15% and average between 330,000 And 340,000 barrels of oil equivalent per day excluding Libya. For the Q1 of 2022, We forecast net production to average between 275,000 This forecast reflects the impact of severe weather in the Bakken, remedial maintenance work at the Baldpate and Penn State Fields in the Gulf of Mexico and planned downtime on the Leaves of Destiny FPSO for production optimization work. Company wide net production is forecast to significantly increase over the course of the year, driven both by Guyana and the Bakken, With the Q4 expected to average between 360,000,370,000 barrels of oil equivalent per day. In the Bakken, both 4th quarter and full year 2021 net production were in line with our guidance, averaging 159,000,156,000 barrels of oil equivalent per day, respectively.

Speaker 3

We have a robust inventory of approximately 2,100 drilling locations in the Bakken that can generate attractive returns at $60 WTI, representing approximately 70 rig years of activity. In 2022, We plan to operate 3 rigs and expect to drill approximately 90 gross operated wells and bring approximately 85 new wells online. In the Q1 of 2022, we plan to drill approximately 22 wells and bring 10 new wells online. For the balance of the year, we expect to bring online an average of 25 wells per quarter. In 2021, our drilling and completion costs per Bakken well averaged $5,800,000 which was $400,000 or 6% lower than 2020.

Speaker 3

In 2022, We expect to fully offset anticipated inflation through lean manufacturing and technology driven efficiency gains, And therefore, D and C costs are expected to be flat with last year at approximately $5,800,000 per well. For the full year 2022, we forecast Bakken net production to average between 165,000 And 170,000 barrels of oil equivalent per day, a 6% to 9% increase over 2021. First quarter net production is forecast to average between 155,000,160,000 barrels of oil equivalent per day. Beginning in the Q2, we expect to benefit from the addition of the 3rd rig, which we added last September and improving weather conditions. Net production net Bakken production is forecast to steadily ramp over the course of 2022 and to average between 175,000 And 180,000 barrels of oil equivalent per day in the Q4.

Speaker 3

Moving to the offshore. In the Deepwater Gulf of Mexico, net production averaged 39,000 barrels of oil equivalent per day in the 4th quarter And 45,000 barrels of oil equivalent per day for the full year 2021, in line with our guidance. The Deepwater Gulf of Mexico remains an important cash engine for the company as well as a platform for growth. In 2022, we will resume drilling operations after a 2 year hiatus With one tieback well planned at the Shell operated Lano field and one exploration well planned at the Hess operated Huron prospect On Green Canyon Block 69. Over the last 5 years, we have focused our efforts on getting best in class imaging across our acreage position in Northern Green Canyon, where we believe there is high potential for multiple high return hub class Miocene opportunities.

Speaker 3

Huron is the first of these opportunities, which attracted interest from multiple parties during the farm out process. We expect to spud Huron in the Q1 with Hess having a 40% working interest as operator and Shell and Chevron at 30% each. As part of our agreements with Shell and Chevron, we have also accessed additional Miocene prospects across Green Canyon and are excited about further potential in the play. In February, Shell plans to spud the Llanos VI development well in which Hess has a 50% working interest. The well will be tied back to Shell's auger platform with gross production from the well expected to build to a plateau rate of between 10,015,000 barrels of oil equivalent per day by the end of this year.

Speaker 3

For the full year 2022, we forecast net production in the Gulf of Mexico to average approximately 35,000 barrels of oil equivalent per day. 1st quarter net production is forecast to average between 3,000,35,000 barrels of oil equivalent per day. In Southeast Asia, net production from the joint development area in North Malay Basin, where Hess has a 50% interest, averaged 66,000 barrels of oil equivalent per day in the 4th quarter 61,000 barrels of oil equivalent per day for the full year 2021, in line with our guidance. For the full year 2022, we forecast net production in Southeast Asia To average approximately 65,000 barrels of oil equivalent per day, in the Q1, we forecast net production to average Turning to Guyana, We're Hess has a 30% interest in the Stabroek Block, and ExxonMobil is the operator. We have continued our extraordinary run of exploration success and increased our estimate of gross discovered recoverable resources to more than 10,000,000,000 barrels of oil equivalent.

Speaker 3

Net production from Guyana averaged 31,000 barrels of oil per day in the Q4 of 'twenty one And 30,000 barrels of oil per day for the full year 2021 in line with our guidance. For the full year 2022, we forecast net production in Guyana to average between 65,070,000 barrels Oil per day. In the Q1, we forecast net production from Guyana to average between 25,030,000 barrels of Oil per day, reflecting planned downtime on the Liza Destiny for production optimization as previously mentioned And net production in the Q4 will increase to between 8,500,90,000 barrels of oil per day. Earlier this month, we announced significant discoveries on the Stabroek Block at Fangtooth and Lao Lau. Positive results at Fangtooth, our first stand alone deep exploration prospect, help confirm In the coming months, we will complete the analysis of the exploration well results.

Speaker 3

Appraisal activities will then be conducted to determine the optimum development approach and timing. Lau Lau further underpins our queue of future low cost development opportunities in the southeastern portion of the Stabroek Block. This discovery will also require appraisal to determine the ultimate development approach and timing. We continue to see multibillion barrels of exploration potential on the Stabroek Block. And in 2022, We plan to drill approximately 12 exploration and appraisal wells that will target a variety of prospects and play types.

Speaker 3

These will include lower risk wells near existing discoveries, higher risk step outs and several penetrations that will test deeper, Lower Campanian and Santonian Intervals. Exploration wells planned for the Q1 of 2022 include Barreleye-one, located approximately 20 miles Southeast of Liza. The primary target is Lower Campanian with shallower And deeper secondary targets, the well spud on December 30. Tarpon 1, which is located approximately 63 miles northwest of Liza, will target Lower Campanian Clastics plus a deeper Jurassic carbonate. The well will spud following completion of Fangtooth operations.

Speaker 3

Patwa 1 is near our turbid area discoveries. The well is approximately 3 miles northwest of the Catibac 1 discovery With targets in Upper Cretaceous Clastic Reservoirs, this well is anticipated to spud in March. Luca 991 is in the southeastern part of the Stabroek Block, located approximately 2 miles west of Pluma And as anticipated, despite in March, the primary target is mustrytrine agedclastic reservoirs with secondary objectives in Lower Campanian reservoirs. The appraisal program in 2022 We'll be focused on delineating future developments. 1st quarter appraisal activities will include the Tilapia II appraisal well, Located approximately 24 miles Southeast of Liza 1.

Speaker 3

The well well appraised the February Team Tilapia 1 discovery in the Turbot area and is anticipated to spud in March. In addition, we plan to conduct drill stem tests Tilapia 1 and Pinktail 1. Turning now to our Guyana developments. Development activity this year will include drilling for both the Liza Phase 2 and Payara Projects. Initial development drilling activities will also begin for the Yellowtail project following approval of the field development plan by the government.

Speaker 3

A planned turnaround will be conducted in March on the Liza Destiny FPSO. Work activities will include production optimization work designed to increase the vessel's production capacity. At Liza Phase 2, the Liza Unity FPSO vessel is undergoing final hookup and commissioning After arriving in the Guyanese waters in October 2021, Uniti is on track to start production in the Q1 of 2022 With a capacity of approximately 220,000 gross barrels of oil per day. With regard to our 3rd development of Payara, The overall project is 66% complete. SURF activities are progressing ahead of plan, and we are preparing for a 2022 The hull for the Prosperity FPSO vessel is complete, and topside construction activities are ongoing in Singapore for planned production startup in 2024.

Speaker 3

The field development plan and environmental impact assessment for the 4th potential project, Yellowtail, Have been submitted for government and regulatory review. The government is supportive of the project, and start up remains on track for 2025. We look forward to continuing to work with the government of Guyana and our partners to realize the extraordinary potential of this world class project. Moving to Suriname. Planning is underway for our second exploration well on Block 42 at the Zandorai I prospect, targeting the Santonian and Deep play potential.

Speaker 3

The operator, Shell, has indicated that they expect to drill a well around midyear. We see the acreage as a potential play extension from the Stabroek Block with similar play types and trap styles. Shell, Chevron and Hess each have a 1 third working interest in Block 42. In closing, our execution continues to be strong. The start up of Liza Phase 2 and steadily increasing production in the Bakken are expected to drive an approximate 30% increase In net production, between the Q1 and Q4 of 2022, along with a significant increase in operating cash flow, which will underpin our commitment to increase cash returns to shareholders.

Speaker 3

I will now turn the call over to John Reilly.

Speaker 4

Thanks, Greg. In my remarks today, I will compare results from the Q4 of 2021 to the Q3 of 2021 and provide guidance for 2022. Turning to results. We had net income of $265,000,000 in the Q4 of 2021 compared with $115,000,000 in the Q3 of 2021. On an adjusted basis, 3rd quarter net income was 86,000,000 Which excludes an after tax gain of $29,000,000 from the sale of our interest in Denmark.

Speaker 4

Turning to E and P. E and P had net income of $309,000,000 in the Q4 of 2021 compared with adjusted net income of $149,000,000 in the Q3. The changes in the after tax components of adjusted E and P results between the 4th and third quarter were as follows: Higher sales volumes increased earnings by $158,000,000 Higher realized selling prices increased Earnings by $103,000,000 Higher DD and A expense decreased earnings by $44,000,000 Higher midstream tariff expense decreased earnings by $22,000,000 Higher cash costs decreased earnings by $21,000,000 Higher exploration expenses decreased earnings by $10,000,000 All other items decreased earnings by $4,000,000 For an overall increase in 4th quarter earnings of $160,000,000 For the 4th quarter, Our E and P sales volumes were over lifted compared with production by approximately 690,000 barrels, which increased after tax income by approximately $17,000,000 Turning to Midstream. The Midstream segment had net income of $74,000,000 in the Q4 of 2021 compared with $61,000,000 in the prior quarter. Midstream EBITDA before non controlling interest amounted to $246,000,000 in the Q4 of 2021 compared with $203,000,000 in the previous quarter.

Speaker 4

Turning to our financial position. At quarter end, excluding Midstream, cash and cash equivalents were $2,710,000,000 and total liquidity was $6,300,000,000 including available committed credit facilities, while debt and finance lease obligations totaled $6,100,000,000 In the Q4, net cash provided by operating activities before changes in working capital was $886,000,000 compared with $631,000,000 in the 3rd quarter, primarily due to higher realized selling prices and sales volumes. In the Q4, net cash provided by operating activities after changes in operating assets and liabilities was $899,000,000 compared with $615,000,000 in the 3rd quarter. In October, we received net proceeds of $108,000,000 from the public offering of 4,300,000 Hess Owned Class A Shares of Hess Midstream. In January 2022, we paid accrued Libyan income taxes and royalties of approximately $470,000,000 related to operations for the period December 2020 through November 2021.

Speaker 4

Post the start up of the Liza Phase 2 development, We intend to pay off the remaining $500,000,000 on our term loan and increase our dividend. With our strong cash and liquidity positions At our industry leading cash flow growth, we are well positioned to significantly improve our credit metrics and increase cash returns to shareholders in the coming years. We remain committed to returning the majority of our increasing free cash flow to shareholders through further dividend increases and share repurchases. Now turning to guidance. First for E and P.

Speaker 4

We project E and P cash costs, excluding Libya, to be in the range of $13.50 to $14 per barrel of oil equivalent for the Q1, reflecting the impact of lower company wide production And higher initial per unit cost for Liza Phase 2 during its production ramp following first oil. Cash costs excluding Libya for the full year 2022 are expected to be in the range of $11.50 to $12.50 per barrel of oil equivalent as the low cost Guyana production reduces our unit cash costs in the second half of the year as Liza Phase 2 reaches capacity. DD and A expense excluding Libya is forecast to be in the range of $11.50 $12 per barrel of oil equivalent for the Q1 and $11.50 to $12.50 per barrel of oil equivalent for the full year. This results in projected total E and P unit operating costs, excluding Libya, to be in the range of 25 to $26 per barrel of oil equivalent for the Q1 $0.23 to $25 per barrel of oil equivalent for the full year 2022. Expiration expenses, excluding dry hole costs, are expected to be in the range of $40,000,000 to $45,000,000 in the first quarter And $170,000,000 to $180,000,000 for the full year.

Speaker 4

The midstream tariff is projected to be in the range $285,000,000 to $295,000,000 for the Q1 and $1,190,000,000 to $1,215,000,000 for the full year 2022. E and P income tax expense, Excluding Libya, it is expected to be in the range of $40,000,000 to $45,000,000 for the Q1 $300,000,000 to $310,000,000 for the full year 2022. For calendar year 2022, we have purchased WTI collars for 90,000 barrels of oil per day With an average monthly floor price of $60 per barrel and an average monthly ceiling price of $100 per barrel. We also have entered into Brent collars for 60,000 barrels of oil per day with an average monthly floor price of $65 per barrel And an average monthly ceiling price of $105 per barrel. We expect non cash option premium amortization, which will be reflected in our realized selling prices to reduce our results by approximately $55,000,000 per quarter or approximately $225,000,000 for the full year 2022.

Speaker 4

In the Q1, we expect to have 3 liftings from Guyana With 2 lifts coming from the Liza Destiny and our first lift from the Liza Unity expected to occur at the end of March. In the Q2, we expect a total of 5 liftings. After the Liza Unity reaches full production, which is currently projected for the Q3 of this year, We expect to have 8 liftings per quarter in Guyana from these 2 FPSOs. For the full year 2022, we expect 24 liftings in Guyana. Our E and P capital and exploratory expenditures are expected to be approximately $650,000,000 in the first quarter And approximately $2,600,000,000 for the full year 2022.

Speaker 4

For Midstream, we anticipate net income attributable to Hess from the Midstream segment to

Operator

be in the range of

Speaker 4

$65,000,000 to $70,000,000 for the Q1 $275,000,000 to $285,000,000 for the full year 2022. For corporate, corporate expenses are estimated to be in the range of $35,000,000 to $40,000,000 for the 1st quarter And $120,000,000 to $130,000,000 for the full year. Interest expense is estimated to be in the range of $90,000,000 to $95,000,000 for the 1st quarter And $350,000,000 to $360,000,000 for the full year 2022. This concludes my remarks. We will be happy to answer any questions.

Speaker 4

I will now turn the call over to the operator.

Operator

Thank you. Your first question comes from the line of Jeanine Wai with Barclays.

Speaker 5

Hi, good morning everyone. Thanks for taking our question.

Speaker 2

Good morning.

Speaker 5

Good morning. Our first question is on cash returns for John Hess. How are you thinking about the trajectory of the base dividend increases? In the past, you've commented that the majority of your shareholders That's the base dividend needs to be higher than the S and P, but any more color on where your target is on that? And then for the buybacks, You've been pretty clear that the base dividend is the first priority, but is the catalyst for more meaningful share repurchases, Is that really Payara coming online in 2024, but you could maybe initiate them on an earlier but more modest level and then accelerate them?

Speaker 2

Jeanine, thank you. In terms of our return of capital framework, once the lease of Phase is up and producing oil. We will pay off the $500,000,000 remaining on our term loan and we'll start to increase our base dividend. At that time, we'll also communicate our return of capital framework, not just where we want to take the dividend, but also How we plan on returning our free cash flow. As a reminder, as you've said earlier, we've It's been consistent in saying that our cash flow compounding, as it does, we intend to return the majority of our free Cash flow to our shareholders by further increasing our dividend and also accelerating share repurchases.

Speaker 2

And in terms of the dividend itself, the base dividend, As our cash flow grows, we plan to have a dividend that will have a meaningful premium to the S and P $500,000,000 dividend yield.

Speaker 5

Okay, great. Thank you for that color. Our second question maybe for John Reilly, it's on Libya. And just maybe a housekeeping clarification thing. The roomies indicated that in January has paid accrued living income tax and royalties of 470,000,000 And that was related to operations from last year.

Speaker 5

Can you just provide a little bit of color on this and what if anything more we can expect

Speaker 4

Sure, Janine. Basically, we had taxes and royalties related to our production on the Waha concessions. And these taxes and royalties were held by Hess and our other WAHA partners after receiving instructions from the Libyan authorities to withhold payment. Then just recently the authorities instructed us to make those payments. So we did release it.

Speaker 4

Hess and our partners released those Taxes and royalties and paid during January, as it was mentioned in the release and I mentioned earlier, in my discussion. Going forward, This is just normal taxes and royalties related to our production. It's typically paid monthly. We expect it to be paid monthly here in 2022. So That's what I would say the go forward is.

Speaker 4

And just so you know, I mean all those those are just normal taxes and royalties. They were all accrued, all in earnings, all in cash

Speaker 2

And as a reminder, Janine, Total Recently announced the sale of our interests in Libya to both Total and ConocoPhillips And we are still awaiting final approval from the government on that sale.

Speaker 5

Great. Thank you.

Speaker 2

Thank you.

Operator

Thank you. Your next question comes from Arun Jayaram with JPMorgan.

Speaker 6

Yes, good morning. John, for you, as you talked about adopting a formal Capital allocation returns framework kind of near term. And I was wondering if you could give us maybe some insights on how you're thinking about this. Some of your E and P peers have a very formulaic approach to this, while some of your major peers are a little bit more Flexible. So I was wondering if you could maybe give us a little bit of thoughts on how you and both and the Board are thinking about that?

Speaker 6

Yes.

Speaker 2

No, Great question. We will be coming out with a framework that will be pretty clear about how we allocate capital, but also How we intend and how much we intend of our free cash flow to return. It will have some flexibility in it, But it will be very clear of our commitment to return the majority of our free cash flow to our shareholders by further increasing the dividend. We'll still have our first The dividend once Liza Phase II is up and running and producing oil, but then we will intend as our cash flow The majority of that free cash flow will go back to our shareholders by further increasing the dividend and also accelerating the share I think the return of capital framework when we announce it will be clear and help provide clarity to the question you're asking.

Speaker 6

Great. And just my follow-up is on Guyana. Greg, you mentioned that The Yellowtail project could include resources of 1,000,000,000 barrels. So wondering if you could kind of compare how this development looks like relative to Payara. I think the subsea kits are a bit more to let Bigger of an FPSO, so maybe give us some thoughts on how this could look like.

Speaker 6

And then as well as maybe provide some insights On the objectives of the 2022 exploration program in Guyana, it looks like you're maybe targeting some more elephants, But I wanted to get some thoughts on those two questions.

Speaker 3

Sure. So let me take your second question first, Tarun. So As I mentioned in my opening remarks, the objectives of the program this year are twofold like they always have been. The first one to explore for new opportunities. So that includes things in the Upper Campanian, but also more penetrations In the deeper zone section that we saw as Fangtooth, right?

Speaker 3

And so if you look at the 12 wells that we're going to do this year, about Two thirds of those wells are exploration wells and about one third is appraisal wells. So pretty active this year on the And again, we're going to be testing deeper zones and also shallower zones with that exploration program. And I kind of lined out The Q1 in my opening remarks as to where we're headed with that. And then appraisal, of course, is about appraising The existing discovery so that we can figure out what that development queue is for the play out of the vessels, the up to 10 FPSOs that we've talked about. Now if I get back to your question On Yellowtail, so first of all, the Yellowtail developments, world class economics will be the largest to date on the Stabroek Block.

Speaker 3

As you mentioned, it's going to develop nearly 1,000,000,000 barrels of oil, have a gross capacity of 250,000 barrels a day. So it's got a little bit bigger topsides, And it's also got more wells. So Payara has 41 wells whereas Yellowtail will have 51 wells. So it's just a bigger project, very large area extent, very fantastic reservoir. So it's going to be one of the, Again, the world class economics.

Speaker 2

Yes. Some of the highest returns in the oil industry comparing it to shale or comparing it Offshore Developments and it's going to have a breakeven cost that will be lower than Payara.

Speaker 6

Great. Thanks a lot, gents.

Operator

Thank you. Your next question comes from Doug Leggate with Bank of America.

Speaker 7

Thanks. Good morning, everybody. I don't know if it's too late to say Happy New Year, but Happy New Year, everybody.

Speaker 2

Happy New Year as well.

Speaker 7

So John or Greg, I'm not sure who wants to take this, but I want to ask a portfolio question given you touched on the Libya news earlier. You have a very, very large footprint in the Gulf of Mexico, obviously. You've taken advantage of lease rounds when no one else cared and so on. But when I look at Payara Yellowtail adding essentially 5 times the current production in the Gulf of Mexico, I got to ask The Gulf of Mexico is a keeper longer term for the portfolio given the effort that has to be put into Maintaining the production and so on. So just long term thoughts on whether the Gulf stays in the portfolio?

Speaker 2

Yes. Greg?

Speaker 3

Yes, sorry, it took me a second to get off on mute. So Doug, as we talked before, the Gulf stability in both deepwater drilling and project delivery in the Gulf. And so our objective is maintain that cash hub, Sustained production and cash flow generation through both tiebacks and also selectively pursuing these high return hub glass exploration Opportunities hopefully here on would be the 1st cap off the rank there. And as you said, we've been selectively rebuilding our Gulf of Mexico Portfolio acquired more than 60 lease blocks at really low prices. And that's again that balance of high Turn tieback opportunities have glass prospects.

Speaker 3

It remains a very important province, foreheads Good returns in the Gulf of Mexico. And as I mentioned, we do have the capability to execute well there. So it's a core hold for us.

Speaker 7

Okay. That's very clear. I appreciate the answer. My follow-up is actually a balance sheet question, so it's probably a John Reilly question. John, I'm just curious, When you think about the scale of the free cash flow that you're going to be able to generate, you still carry in absolute terms a sizable amount of debt.

Speaker 7

What do you see as the right level of debt? Where does the priority sit in the cash return framework to actually bring that debt down to, Let's say, sector leading levels like some of your peers and they're talking about 0 net debt, for example.

Speaker 4

Sure, Doug. So as you know, right, once we start up Liza Phase 2, we are going to pay off the remaining $500,000,000 of that term loan. Then our next maturity, because we've got a nice liquidity position, is until 2024 and it's $300,000,000 We do intend, as you You said with our rising free cash flow to pay off that maturity in 2024 and then we don't have a really another debt maturity until 2027. So we're happy when we pay off that 2024 amount with the absolute level of debt that we have. And if we're let me just say it like $65 Brent, and we run this out, we bring Payara on and obviously other FPSOs, We're going to drive our leverage down to under one times debt to EBITDAX.

Speaker 4

That's gross debt to EBITDAX. So We're going to have really a strong low leverage position improving credit metrics as I mentioned earlier. So we are happy with that debt level, that absolute debt level as our EBITDAX grows from there. And so There is no real benefit. We've run NPVs on doing some things with either just doing Paying off the debt at this point, but right now with our low leverage, we are very comfortable with leaving the debt levels where they're at.

Speaker 4

And then like we said, with that balance sheet so strong at that point and the rising free cash flow from Payar or from Yellowtail from the 5th development, We will then increase returns to shareholders. Obviously, with the rising free cash flow, it's more of that free cash flow return versus will be share repurchases, But we'll also be growing our dividend over the time too as well. So I think we're in a really good position for this with Guyana coming on these low cost development, Strong balance sheet and increasing return of capital to shareholders.

Speaker 7

Great. I appreciate the answer, fellas. Thanks again.

Operator

Thank you. Your next question comes from Neil Mehta with Goldman Sachs.

Speaker 8

Good morning, team.

Speaker 9

A couple of questions here.

Speaker 8

Good morning, John. First one is around Liza 2. We're weeks away here from start up. How do you think about any gating issues around the start up? And just can you give a sense from an operational standpoint, how is it going around Structuring at Payara as well.

Speaker 8

So just any thoughts around the logistics I'm getting these assets turned on.

Speaker 2

Yes, Greg, please.

Speaker 3

Yes, sure. So let me just talk about Phase 2 first. We'll have 19 wells available at start up. Those are all ready to go. All the risers have been recovered.

Speaker 3

So they're hooked up into their porches now. We've got a few left to commission. So we've got still got some commissioning of those risers. The FPSO topsides readiness is nearly complete. So Neal, what that means is we are on track for That Q1 start up as we said in our opening remarks.

Speaker 3

And if you look at Payara, Again, it's still relatively early in the project, but right now we're running slightly ahead of schedule in Payara. So I would say we're firmly on track for that 2024 startup. So the project is about 66% complete As we sit here today, so we're in good shape, but again, it's early days in Payara. So I think the operator having some contingency in there is wise at this point, but on track for a

Speaker 8

2024 startup. Thanks, Greg. And the follow-up here is for John and John On the hedging strategy here, so you did provide an update around the collars and increased the ceiling price there. Just talk about how you think about the optimal way to approach hedging is. And John, if you don't mind tying that into your own view of the oil macro as you've been constructive here You're in 90 Brent.

Speaker 8

Is anything changing for the better or for the worse relative to what you've talked about over the last couple of months?

Speaker 4

Sure, Neil. I'll start and hand it over to John Hess. But our hedging strategy, it really is consistent what we're doing with our past strategy. So as we continue to invest in our world class opportunity in Guyana, we want to ensure that we have significant price protection, which we did in 2022. So just to reiterate, we have 90,000 barrels of oil per day with WTI puts at a floor of $60 and And then we have 60,000 barrels a day of Brent puts at a floor of $65 Now this year, we did use high ceiling calls, so we have a call at 100 Well, in the case of higher oil prices above the hedged floor.

Speaker 4

So in addition, we haven't hedged all of our oil production and obviously we have unhedged NGL and gas production as well that will benefit from higher prices. So when I say this is consistent with our strategy, we provide significant downside protection while also giving the majority of upside Our shareholders as we continue to invest the opportunity in Guyana.

Speaker 2

Yes, Neal. And obviously, it does reflect a constructive view on the market And very consistent with our approach of protecting the downside and giving the majority of the upside to our shareholders. On the Macro oil outlook on the demand side, V shaped recovery, temporary setback of about 1,000,000 barrels a day globally because of omicron, Starting to see cases going down, thank God. We think we'll be back at pre COVID global demand levels of 100,000,000 barrels a day In the next month or so, and as the year unfolds, we see jet demand increasing as international travel Probably see a number of about 102,000,000 barrels a day by the end of 2022. Supply side different, it's a U shaped recovery, more sticky.

Speaker 2

Shale is growing, but at a more tempered PACE, function of the rig count of about 604 U. S. Rigs operating, we think that

Speaker 4

adds about 750,000 barrels

Speaker 3

a day over the

Speaker 2

year of increased oil production. And Some barrels a day over the year of increased oil production. Remember, U. S. Production probably end up at the end of the year about 12 200,000 barrels a day, that's still short of the 13,000,000 barrels a day we had pre COVID.

Speaker 2

So shales on the recovery, but not at pre COVID levels in terms of absolute U. S. Oil production. OPEC, sounds like they're going to stick to their 400,000 barrels a day increases each As has been written by a number of commentators, a couple of countries are not meeting their quotas there. So again, I'd say disciplined tempered recovery in OPEC plus disciplined tempered recovery in shale, All of which adds up to global oil inventories, which had been a year and a half ago, April, $1,200,000,000 excess inventories globally, that's all been eaten up.

Speaker 2

And now we see global oil inventories about 200,000,000 barrels less than pre COVID levels. So as you go through this year With demand increasing, inventory is tight, not much spare capacity in OPEC plus we're pretty constructive on the oil market. And really the oil price is giving a signal that investment has to increase, which is why I referred to the World Energy outlook earlier. Depending upon what scenario you pick, any credible scenario from the International Energy Agency, enough as an industry to do that. So we're going to have to have the right balance of being capital disciplined, returning capital to shareholders, but at the same time, Grow the resource and grow the production capacity of the world.

Speaker 2

So that's the challenge that we have ahead and I think that also Really presents a constructive oil market as the year unfolds.

Operator

Thanks, Chad. Thank you. Thank you. Your next question comes from Paul Cheng with Scotiabank. You may proceed with your question.

Speaker 10

Hey guys, good morning.

Speaker 9

Good morning.

Speaker 10

I guess two questions. One for Greg and the other one is for John Marley. Greg, when you're looking at Frank II and the other That you also have penetrated the difference formation. Is there anything you can tell us that In terms of the oil and gas ratio, in terms of the permeability, oil quality comparing to the more shareholder Is there any significant differences that we see or any kind of conclusion that you can share?

Speaker 3

So Paul, I guess the first thing I'd say is the positive result of FanDooth, which It was our 1st standalone deep exploration prospect. And remember, it's up towards Liza, so it's kind of in that country. So very good, oil quality and it confirms the deeper exploration potential of the Stabroek Block. So In the coming months, we're going to complete the analysis of that well, the Fangtooth well, and then plan appraisal activities to really determine You have the best development approach. So generally, we see these deeper zones as being developed through a combination of standalone developments and tie potentially to existing FPSO.

Speaker 3

So very encouraged, very pleased by the results we saw at Fangtooth. Also remember, we had other penetrations prior to things into those deeper zones that confirmed the same thing, good reservoir quality And good, good food properties. So very excited. That's why we're going to drill a lot more wells in kind of the deeper Prospectivity this year than years past and so watch this space, but we're encouraged by the outcome in particular of FANG2.

Speaker 10

Well, we understand that, yes, good, but is there any contrast or comparison you can provide in terms of the gas oil ratio, The grade of the oil and the permeability and the kind of data that you can share?

Speaker 3

No, not at this point, because again, we need to do some more analysis of the wells and do some So the wells induce more appraisal of particularly in the Fanfus area.

Speaker 10

Okay. The second question is For John Marley that by the Q4, as you indicate that your unit cost is going to come down a lot because China, These are 2 years, ramp to the full capacity and all that. So what's the target unit cost that you have by the Q4 in Guyana? And also, that have you looked at I know you guys talking about Next year that you may start the buyback, but have you visited between the variable dividend and the buyback and that The plus and minus is that have you and that's why you decide that variable dividend is not A better tool and then the buyback is the one tool for the company. I'm not saying that you should be variable dividend.

Speaker 10

Just curious that I will debate that, that has been the case.

Speaker 4

Sure. So let me start with cash costs. So Through the year, as I said and you mentioned, our unit costs will be dropping basically as Guyana Phase 2 comes online and its lower cost. Let me just remind you where the costs are for Guyana. On Phase 1, obviously, it's a smaller boat.

Speaker 4

And what we've been saying is that the cash cost Per barrel there were $12 However, you did hear it was mentioned that we're doing the production optimization work, so that $120 gross capacity is going up. So the cash cost per barrel for Phase 1 will be decreasing as that production optimization is completed. On Phase 2, the cash cost per barrel are $10 per barrel for Phase 2 when it is fully up and running. I also should mention that both of these is when we're leasing the FPSO. So Phase 2 will actually drop down to $7 to $8 post purchase But for this year around $10 So you have cash costs for Phase 2 at $10 and you've got Phase 1 under $12 And what it does Along with increasing production in the Bakken is by the Q4, our cash costs will drop to around $11 per barrel for the company in the Q4.

Speaker 4

And then I'll pass it over to John.

Speaker 10

Yes, Paul,

Speaker 7

is someone on That's true.

Speaker 2

Oh, is that you, Paul? Yes,

Operator

yes.

Speaker 2

Okay. Yes. No, we were getting some feedback. In terms of the dividend, we've done studies. We don't think The variable dividend sustains the creation of long term value.

Speaker 2

We believe strengthening the base dividend and Consistent share repurchases are a better way to go. And in terms of the timing on that, as I said, Once Liza Phase 2 is up and producing, we pay the $500,000,000 of Remaining dead off from our term loan, we will increase our base dividend. We will start the process of That increase and then as you look forward in time, further dividend increases and accelerating share repurchases will be a function Market conditions and the growth in our cash flow. So, the framework for that, will be very clear, and I think something that will be very competitive.

Speaker 10

Okay. Thank you, John. John Nalley, can I go back into your when you're talking about the Guyana unit cost? Wondering that what is the timeline in terms of when do you, the consortium, decide to Buyback the FPSO or that I mean for both NISA-one and NISA-two? And secondly that when you're talking about those numbers $12 for Phase $1.10 for Phase 2.

Speaker 10

Are those that what is the denominator on that? Is that based on, Say, in Phase 2, 220,000 barrels per day, but your actual reported in your financial statement will be different or that this is what you

Speaker 4

Okay. So answering your last question first. Yes, that's what will be reported In our financial statements, so that's our if you want to call it our net cash costs on our entitlement production in Guyana. So Those are those numbers. And as far as the FPSO purchases, the operator ExxonMobil is still in discussions with, SBN On the actual date of the purchases of the FPSOs, and we'll give you the specific timing to that when that is set.

Speaker 4

But having said that, As you noted in our 2022 CapEx release, we don't expect any purchases in 2022 or in 2023.

Speaker 10

Thank you.

Operator

You're welcome. Thank you. Your next question comes from David Deckelbaum with Cowen.

Speaker 11

Thanks, John. Thank you guys for squeezing me in here. I'll try to make it quick. I had one question just on the reserve report. It looked like your net additions organically at

Speaker 12

the drill bit like

Speaker 11

$241,000,000 were you noted in the press release we're primarily from the Bakken. Is that just reflecting increased gas capture or Have there been some performance revisions there as well?

Speaker 2

Josh? No,

Speaker 3

there have been Go ahead, Josh.

Speaker 2

Go ahead, Greg. You go first.

Speaker 3

Yes. So look, there were both performance additions in the Bakken, Plus, we brought additional wells into our 5 year plan due to price Increase, which was 107, but then the other wells bringing in. So if you look at the Bakken, we had adds of about 209,000,000 And then the price of about $119,000,000 specifically to the Bakken, right? So both performance adds and also bringing additional wells into the 5

Speaker 1

Great. Thanks, Greg.

Speaker 11

Appreciate the color on that, Greg. And then maybe for John, just my last question. Just around You've laid out the timeline for paying down the $500,000,000 term loan, noted the fact that you don't really have that many maturities beyond. As I guess the free cash profile ramps here. You talked about getting some one times leverage as we have on our numbers at a run rate sort of in that 2Q, 3Q timeframe.

Speaker 11

Should we be thinking about investment grade sort of coinciding sort of with midyear? And how do you think About the tangible benefits from that outside of the obvious of refinancing some of that higher cost debt stack.

Speaker 4

So again, with our growing free cash flow and obviously our growing cash flow and our growing free cash flow, our debt metrics are going to significantly improve as and basically as each FPSO comes on. And like I said, we are targeting to be on a gross debt To EBITDAX under 1, and we will achieve that as the cash flow grows. Now I can't specifically Safe with the rating agencies on timing. Obviously, we are investment grade with 2 of them and we're below on 1, but have a positive outlook with the 1. So I do expect as our cash flow improves that we'll become investment grade and actually will improve from where we are today as our cash flow grows.

Speaker 4

So What we try to do from our own strategy standpoint is we want to have a strong balance sheet, obviously, to fund the growing resource base that we have and also And for further return to shareholders. So from our standpoint, that will be the outcome of our strategy of having a low leverage, Strong liquidity position, which you mentioned as well. And then as each FPSO comes on, it will just continue to improve And we'll improve our credit metrics as well as still providing increasing cash returns to shareholders. So the portfolio is set to be in a nice spot. As John has mentioned earlier, this is kind of the inflection year and we'll expect to grow on it from here.

Speaker 11

Appreciate the answers guys.

Speaker 13

Thank you.

Operator

Thank you. Your next question comes from Ryan Todd with Piper Sandler.

Speaker 12

Great, thanks. Maybe just a couple of quick ones. I know as we think about the medium term outlook in the Bakken, I know you've talked about eventually wanting to get 4 rig program and a production plateau closer to 200,000 barrels a day. How much impact does the price of oil have on the timing Of adding a 4th rig, is that something that would be possible by the end of this year if prices stay high? Or is that further down the line?

Speaker 2

Go ahead, Greg.

Speaker 3

Yes. Again, Ryan, I think as we've talked before, the role of the Bakken in the portfolio is to be a cash engine. So any decisions on pace or timing of addition of the 4th rig It's going to depend upon corporate cash flow needs and also returns. Now having said that, assuming prices Hold, at this relatively high level, we would look to add that 4th rig next year. And by doing so, We could then take the Bakken to 200,000 barrels a day.

Speaker 3

And with the inventory we have at 4 rigs, we could hold that flat Yes, broadly that 200,000 barrels a day for almost a decade, with that 4th rig. Now at 200,000 barrels a We really maximize utilization of the infrastructure. So that would be another objective to fill that infrastructure up. And of course, gosh, with these prices, the Bakken becomes this massive cash generator. And at that 200,000 barrels a day, even at $60 to $65 it generates about $1,000,000,000 of free cash flow.

Speaker 3

So you can see the real cash firepower of the Bakken.

Speaker 12

Thanks, Greg. And then maybe I appreciate the comments on And cost inflation and well cost in the Bakken earlier, as you think about the rest of the portfolio, any comments on what you're seeing in terms of the Service or material cost inflation in an offshore environment, particularly as we think about upcoming potential project sanctions?

Speaker 2

Greg, please.

Speaker 3

Yes, sure. So like the onshore, we're also seeing some inflation in the offshore. However, recall the majority of our offshore portfolio right now is driven by Guyana. And of course, the projects currently in development are covered by EPC contracts. So we're largely insulated From cost increases in the offshore, current cost increases in the offshore plus ExxonMobil With this design 1, build many strategy is just doing an outstanding job of delivering efficiencies across that portfolio down there as well.

Speaker 3

If you look at our in the Gulf of Mexico, the rig that's going to drill the Huron well, $255,000 a day rate. So I think that still reflects the low cost On a relative basis of the offshore drilling.

Operator

Thanks for all the help. Thank you. Your next question comes from Bob Brackett with Bernstein Research.

Speaker 14

Good morning all. Had a Question around Payara, and I'm going to try to type a date and a percent completion. So if I'm not incorrect, Tyra was sanctioned maybe 5 quarters ago. First production is expected maybe 8 plus quarters from now, But at the same time, it's 66% complete. So if those numbers are right, can you talk about maybe the rate limiting steps for Payara and maybe for future developments?

Speaker 2

Morning, Bob. Great question. Greg, it's yours.

Speaker 3

Sure. Yes. Bob, so Payara, I think what's different about Payara Yes, there are 3 offshore installation campaigns. So yes, the project is 66% complete, But because there's 3 installation campaigns, you will build a little bit more contingency into that project. Because while you don't have hurricane issues or anything down there, you do have some current issues, Offshore currents during the installation campaign.

Speaker 3

So that's why there's still contingency in Payara. We agree with the operator That's the appropriate thing to do at this stage of the project. And so we are firmly on track for a 2024 startup. Little ahead right now, but again, it's early days.

Speaker 14

Understood. Is there a good rule of thumb for the number of development wells a drillship in Guyana can do in a year?

Speaker 3

You mean in terms of drilling? Yes. No, Bob, it's really kind of bespoke. Some of these horizontals are longer than other ones, for example, in some of these developments. So There's not a great rule of thumb that I would say because again each development is very bespoke on not only the length of the horizontals, but also what reservoirs they're tapping into as well.

Speaker 14

Okay, fair point. Thanks all.

Speaker 2

Thank you.

Operator

Thank you. Your next question comes from Noel Parks with Tuohy Brothers.

Speaker 14

Good morning.

Speaker 2

Good morning.

Speaker 9

I just had a general question about the exploratory program this year. Just wondering what's the next most informative data point you're looking for out of the program Because there's quite some large step outs there, so there's possibility for aerial expansion. And then it also sounds like some of the particular formations you're going at are, I believe, The

Speaker 8

first time you're going to

Speaker 9

be tapping them in Guyana. And so I was wondering if any of these really opens up a lot of new doors, if it meets

Speaker 3

As you know, A, to continue to do kind of the Upper Campanian exploration, But also most importantly is to get more penetrations in the deep. So the deep penetrations We're going to be watching closely and these are wells that we're going to spud in the Q1 are Barreleye-one, which is a lower Campanian primary target, but it's also got some shallower things as well. And then Tarpon 1, Which is another Lower Campanian well, plus a deeper Jurassic carbonate feature that we see. And then kind of in the Upper Campanian space, Objectives in the Lower Campanian reservoirs. And then finally, Potwa1, which has got some targets in the Upper Cretaceous reservoir.

Speaker 3

So you can see it's a mixture Play type, so I wouldn't want to call one out specifically and say, oh, that's the most significant. They're all significant In this year's program, they're all very promising wells on seismic.

Speaker 9

And then are most of those deeper targets then things that you've Identified largely through seismic or are any of them are your expectations informed by any of them by Actual analogies you have or have already seen?

Speaker 3

No, I think they're all they all have seismic features, Right. So the primary driver down here is our seismic signature. Now obviously, as we've gotten more data in the deep, We're getting better at teasing out what that seismic is going to show us and the additional data we pick up from these deeper wells We'll improve that even more kind of as we go forward.

Speaker 9

Okay, great. Thanks a lot.

Operator

Thank you. Your next question comes from David Aikkinen with Pickering Energy.

Speaker 13

Good morning, guys. And really just making sure that I'm thinking about this correctly, you all continue to be cash taxpayers in the U. S. And Malaysia And then continue to build a cost pool at a faster pace, given your spending in the ring fencing in Guyana for the next couple of years, just thinking $80 plus oil, 20222023 is, you got this call it the hug of higher oil prices, but a punch of higher cash tax, But you're already essentially a full payer, is the way we're thinking about it. Is Is that correct?

Speaker 4

David, no. So for us, we are not cash taxpayers in the U. S. We have a net operating loss carry forward. And I would tell Yes, I don't see us paying cash taxes even with these high prices, let's just say for 5 years and beyond.

Speaker 4

So That's where we are in the U. S. The only place that we really are paying cash taxes is in Southeast Asia. Okay. And that's a it's a small amount in the portfolio.

Speaker 13

So I think I said that opposite.

Speaker 3

Sorry, I've got a little COVID brain fog

Speaker 4

No, no. The only thing you would see is in our when you're looking at it because I always do it ex Libya. Libya obviously has it's a 93.5 Tax rates. So that's the one place that we are paying cash taxes. And then the Guyana taxes are actually within the PSC.

Speaker 4

So it's in the economics and in our net entitlement. So we pay them there.

Speaker 13

Yes. Again, you just keep building a cost pool For the next 3 years even at these prices?

Speaker 4

Correct.

Speaker 13

Yes. Okay. Thanks guys. I think I said that opposite. My apologies.

Speaker 4

No, no problem.

Speaker 13

You've answered my question. Thank you all.

Operator

Thank you. Your next question comes from Philip Johnston with Capital One.

Speaker 15

Hey guys, thanks. Just one question for Greg on the production outlook. You guys have a large ramp throughout the year and I know you don't give specific guidance on oil production, but just wondering if you could help us with the oil mix in both the Bakken and the Gulf of And how those numbers should trend throughout the year. I realized the Bakken mix can fluctuate depending on gas capture and NGL prices, but From a high level perspective, should we stick with around 50% of the Bakken and around 65% or so for the

Speaker 4

Greg?

Speaker 15

Gulf of Mexico for the rest of the year.

Speaker 3

Yes. So let's address the Bakken first. So First of all, the mix at the wellhead is constant at around 65% and will be for the next several years for In the Bakken and that's because we still have a lot of undeveloped well locations. Now you're right, when you get to the corporate Results, it goes to 50%, and that's because of increased gas capture and our 3rd party volumes and our POP contracts and all that. That's how you To the 50%.

Speaker 3

So at a corporate level broadly, you could assume that that's going to be the same mix. And you're on

Speaker 4

target for the Gulf of Mexico,

Speaker 3

kind of that 65% or so, mix in the Kind of that 65% or so mix in the Gulf.

Speaker 15

Okay, perfect. Thanks, Greg.

Speaker 2

Thank you.

Operator

Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.

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Earnings Conference Call
Hess Q4 2021
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