Hess Corporation (NYSE:HES) Q2 2022 Results Conference Call July 27, 2022 10:00 AM ET
Jay Wilson – VP, IR
John Hess – CEO
Greg Hill – COO
John Rielly – CFO
Conference Call Participants
Arun Jayaram – JPMorgan
Doug Leggate – Bank of America
Paul Cheng – Scotiabank
Jeanine Wai – Barclays
Ryan Todd – Piper Sandler
Neil Mehta – Goldman Sachs
Roger Read – Wells Fargo
Vin Lovaglio – Mizuho
David Deckelbaum – Cowen
Good day, ladies and gentlemen, and welcome to the Second Quarter 2022 Hess Corporation Conference Call. My name is Liz, and I will be your operator for today. [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.
Good morning, everyone, and thank you for participating in our second quarter earnings conference call.
Our earnings release was issued this morning and appears on our website, www.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 sections of Hess’s 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.
On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. In case there are any audio issues, we also will be posting transcripts of each speaker’s prepared remarks on www.hess.com following the presentation.
I’ll now turn the call over to John Hess.
Thank you, Jay. Welcome to our second quarter conference call. Today, I will provide first some comments on the oil markets and then review our progress in executing our strategy. Greg Hill will then discuss our operations, and John Rielly will review our financial results.
In the last month, recessionary fears that have affected the financial markets have also been weighing on the oil markets. The price for Brent crude oil has gone from a peak of $120 per barrel to a low of $95 per barrel to approximately $105 per barrel today. However, the physical oil market remains tight.
For example, to buy a physical Brent cargo, crude buyers today have to pay a cash premium of at least several dollars per barrel. We are in unprecedented times for the financial markets and for the oil markets. In both markets, we have experienced a demand shock and a supply shock. The global economy shut down in 2020 and it is taken approximately 2 years to recover.
In terms of global oil demand, there has been a V-shaped recovery due to various government financial stimulus programs and accommodative monetary policies. Global oil demand has returned to pre-COVID levels of approximately 100 million barrels per day. On the other hand, global oil supply has seen more of a U-shaped recovery.
Global oil supply has been struggling to keep up with demand, predominantly as a result of more than 5 years of industry under investment. As a consequence, we have seen 7 consecutive quarters of draws on global oil inventories so much so that global oil inventories today are approximately 400 million barrels less than pre-COVID levels.
As we look to the second half of the year, we expect global oil demand to increase by 1 million to 1.5 million barrels per day as a result of China’s economy reopening after COVID lockdowns and increasing air travel. In terms of global oil supply, while shale producers have enabled the U.S. to grow oil production by approximately 1 million barrels per day over the year — in the last year, there is very little spare capacity left in the world.
With demand growing, supply lagging and the potential for further sanctions on Russian oil exports, we expect a tight global oil market to get even tighter over the balance of the year. In a world that needs reliable, low-cost oil and gas resources now and for decades to come, Hess is in a very strong position offering a highly differentiated value proposition for investors.
Our strategy is to continue delivering high resource growth, a low cost of supply and industry-leading cash flow growth while at the same time, maintaining our industry leadership in environmental, social and governance performance and disclosure. Our successful execution of this strategy has uniquely positioned our company to deliver value to shareholders now and for years to come, both by growing intrinsic value and by growing cash returns.
By investing only in high-return low-cost opportunities, the best rocks for the best returns, we have built a balanced portfolio focused on Guyana, the Bakken, deepwater Gulf of Mexico and Southeast Asia with multiple phases of low-cost oil developments coming online in Guyana and our robust inventory of high-return drilling locations in the Bakken, we can deliver highly profitable production growth of more than 10% annually over the next 5 years.
Through the continued development of our high-quality resource base, we are steadily moving down the cost curve. Our 4 sanctioned oil developments in Guyana have a breakeven Brent oil price of between $25 and $35 per barrel. In terms of cash flow growth, we have an industry-leading rate of change and industry-leading durability story.
Based upon a flat Brent oil price of $65 per barrel, our cash flow is forecast to increase by approximately 25% annually between 2021 and 2026, more than twice as fast as our top line growth. Our balance sheet will also continue to strengthen in the coming years, with debt-to-EBITDAX expected to decline from less than 2x in 2022 to under 1 time in 2024.
As our portfolio becomes increasingly free cash flow positive in the coming years, we are committed to returning up to 75% of our annual free cash flow to shareholders with the remainder going to strengthen the balance sheet by increasing our cash position or further reducing our debt. Given our strong cash flow growth, we commenced a share repurchase program during the second quarter, repurchasing approximately 1.8 million shares of common stock for $190 million under our existing $650 million board authorization and we intend to opportunistically repurchase the remaining amount by year-end.
Looking ahead, we plan to continue increasing our regular dividend to a level that is attractive to income-oriented investors, but sustainable in a low oil price environment. As our free cash flow generation steadily increases, share repurchases will represent a growing proportion of our return of capital.
Key to our strategy is Guyana, the industry’s largest oil province discovered in the last decade. 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 gross production capacity of more than 1 million barrels of oil per day and up to 10 FPSOs to develop the discovered resources on the block.
In terms of our sanctioned oil developments, production at the Liza Phase 1 development has reached its new production capacity of more than 140,000 gross barrels of oil per day in the second quarter following production optimization work on Liza Destiny FPSO.
The Liza Phase 2 development, which achieved first oil in February, reached its gross production capacity of approximately 220,000 barrels of oil per day earlier this month. Our third development on the Stabroek Block at the Payara field with a gross production capacity of approximately 220,000 barrels of oil per day is on track for start-up in late 2023.
In early April, we announced a sanction of Yellowtail, which will be the largest development to date on the Stabroek Block. The project will develop an estimated recoverable resource base of approximately 925 million barrels of oil and have a gross production capacity of approximately 250,000 barrels of oil per day with first oil expected in 2025.
Front-end engineering and design work for our fifth development in Uaru Meco is underway with a plan of development expected to be submitted to the government by year-end. In terms of exploration and appraisal in Guyana, we continue to invest in an active program with approximately 12 wells planned for the Stabroek Block in 2022.
Yesterday, we announced 2 new discoveries on the block at the Seabob 1 and Kiru-Kiru 1 wells, bringing our total this year to 7. These discoveries will add to the previously announced gross recoverable resource estimate for the Stabroek Block of approximately 11 billion barrels of oil equivalent and we continue to see multibillion barrels of future exploration potential remaining.
Now turning to the Bakken, our largest operated asset, we have an industry-leading position with approximately 460,000 net acres in the core of the play. Severe weather in April and May caused widespread power outages lasting 4 to 6 weeks and production shut-ins throughout North Dakota.
Production recovery efforts took longer than expected for our company and the industry. Our Bakken operations are now recovering with approximately 50 new wells planned to be brought online in the second half of the year versus 32 in the first half.
Given the strength of the oil market and the world’s need for more oil supply, we added a fourth rig earlier this month, which will allow us to achieve net production of approximately 200,000 barrels of oil equivalent per day in 2024, a level which will maximize free cash flow generation, lower our unit cash cost and optimize our infrastructure.
As we continue to execute our strategy, we are dedicated to maintaining our industry leadership in environmental, social and governance performance and disclosure. On Monday, we announced publication of our 25th Annual Sustainability Report, demonstrating our long-standing commitment to sustainability and transparency. We continue to be recognized as an industry leader for the quality of our ESG performance and disclosure.
In May, Hess was named to the 100 Best Corporate Citizens list for the 15th consecutive year based on an independent assessment by ISS ESG, and we were the only energy company to earn a place on the 2022 list. Social responsibility is a fundamental part of our sustainability commitment. Earlier this month, we announced a multiyear national health care initiative with the government of Guyana and the Mount Sinai Health System to provide access to affordable and high-quality health care which is central to the government’s vision for long-term shared prosperity for the people of Guyana.
In summary, we continue to successfully execute our strategy to deliver industry-leading cash flow growth and financial returns to our shareholders, while safely and responsibly producing oil and gas to help meet the world’s growing energy needs. We increased our regular quarterly dividend by 50% in March and during the second quarter, commenced a share repurchase program, reflecting the financial strength of our business and our commitments to shareholders.
As our portfolio becomes increasingly free cash flow positive, we will continue both to invest to grow our company’s intrinsic value and to increase the return of capital to our shareholders through further dividend increases and share repurchases.
I will now turn the call over to Greg Hill for an operational update.
Thanks, John. Although in the second quarter, we experienced continued weather impacts in the Bakken and a ramp up of Liza Phase 2 that was modestly slower than expected.
Net production was up 10% from the first quarter and we anticipate company-wide net production to continue to build in the second half of the year as we bring more wells online in the Bakken, and Liza Phase 2 operates at nameplate capacity.
In the second quarter, company-wide net production averaged 303,000 barrels of oil equivalent per day, excluding Libya. In the third quarter, we expect company-wide net production to increase by approximately 10% from the second quarter and to average between 330,000 and 335,000 barrels of oil equivalent per day, excluding Libya.
In the fourth quarter, company-wide net production is expected to further increase to between 365,000 and 370,000 barrels of oil equivalent per day, excluding Libya. For the full year 2022, we now forecast net production to average approximately 320,000 barrels of oil equivalent per day, excluding Libya.
Turning to the Bakken. Second quarter net production averaged 140,000 barrels of oil equivalent per day. This was in line with our guidance and reflected the impact of severe weather in April and May. Production is now recovering and is expected to increase to between 155,000 and 160,000 barrels of oil equivalent per day in the third quarter.
For the fourth quarter, we forecast net production to further increase to between 160,000 and 165,000 barrels of oil equivalent per day. For the full year 2022, we now forecast Bakken net production to average between 150,000 and 155,000 barrels of oil equivalent per day. This reflects a volume reduction of approximately 7,000 barrels of oil equivalent per day under our percentage of proceeds contracts as a result of higher NGL prices.
Although NGL volume entitlements are lower, overall cash flow is substantially higher. In terms of drilling and completion costs, we are continuing to see upward pressure across our supply chains, particularly in oil country tubular goods. As a result, we have increased our full year average drilling and completion cost forecast by $100,000 per well to average $6.3 million per well in 2022.
I am proud of our team’s effectiveness in mitigating the impacts of inflation, tight supply chains largely through our distinctive lean culture. While we believe the industry is experiencing overall inflation of between 15% and 20%, our full year drilling and completion costs are forecast to increase by only about 8.5% year-over-year.
In the second quarter, we drilled 20 wells and brought 19 new wells online. In the third quarter, we expect to drill approximately 25 wells and to bring approximately 20 new wells online. And for the full year 2022, we now expect to drill approximately 95 wells and to bring between 80 and 85 new wells online, which is slightly lower than previous guidance due to the second quarter weather-related delays in mobilizing equipment.
Individual well results in terms of EURs and IP180s continue to meet or exceed expectations. Earlier this month, we added a fourth drilling rig in the Bakken. Through our strategic partnerships with Nabors and Halliburton we were able to secure a fully staffed, high spec class rig and a second completion crew.
Moving to a 4-rig program will allow us to grow net production to approximately 200,000 barrels of oil equivalent per day in 2024, which will optimize our in-basin infrastructure and drive further reductions in our unit cash costs.
Now moving to the offshore. In the deepwater Gulf of Mexico, second quarter net production averaged 29,000 barrels of oil equivalent per day compared to our guidance of approximately 30,000 barrels of oil equivalent per day. In the third quarter, we forecast Gulf of Mexico net production to average between 25,000 and 35,000 barrels of oil equivalent per day reflecting planned downtime at Tubular Bells and a Penn State Well being shut in due to a mechanical issue. This downtime will be partially offset by the planned start-up of the Lano 6 tieback in August, which logged 123 feet of high-quality Miocene pay.
For the full year 2022, our forecast for Gulf of Mexico net production is now approximately 30,000 barrels of oil equivalent per day. In June, we completed drilling operations on the Huron prospect on Green Canyon Block 69 with encouraging results. Hess is the operator with a 40% working interest and Chevron and Shell each have 30%.
The well encountered high-quality oil-bearing Miocene age reservoirs and established the existence of a working petroleum system. Well results are still being evaluated and an appraisal sidetrack is planned. In Southeast Asia, net production in the second quarter was 67,000 barrels of oil equivalent per day compared to our guidance of approximately 65,000 barrels of oil equivalent per day.
Phase 3 of the North Malay Basin development came online in June and is producing above expectations, and Phase 4 is on track to achieve first gas in early 2023. Third quarter net production is forecast to average approximately 55,000 barrels of oil equivalent per day, reflecting planned maintenance at both JDA and North Malay Basin.
Full year 2022 production is expected to average between 60,000 and 65,000 barrels of oil equivalent per day. Now turning to Guyana. In the second quarter, net production averaged 67,000 barrels of oil per day, reflecting a modest delay in the ramp-up of Liza Phase 2. Overall, the start-up has been very successful. In July, Liza Phase 2 reached its nameplate capacity of 220,000 barrels of oil per day or about 56,000 barrels of oil per day net to Hess.
For Liza Phase 1 production optimization work was completed in the second quarter, and the FPSO is now operating at or above its new gross production capacity of 140,000 barrels of oil per day. Earlier this month, SBM Offshore also completed the replacement of the flash gas compressor, which has resulted in high reliability and 0 routine flaring.
Third quarter net production from Guyana is forecast to increase to a range of 90,000 to 95,000 barrels of oil per day and average approximately 75,000 barrels of oil per day for the full year 2022. With regard to our third development of Payara, topside fabrication and installation on the Prosperity FPSO is well underway in Singapore and development drilling in Guyana continues at pace.
The project, which will have a gross production capacity of 220,000 barrels of oil per day is now more than 80% complete and is well on track to achieve first oil in late 2023. In April, we sanctioned a fourth development at the Yellowtail, which will develop approximately 925 million barrels of oil and have a breakeven Brent oil price of approximately $29 per barrel.
The project will have a gross production capacity of 250,000 barrels of oil per day and is on track to achieve first oil in 2025. As for our fifth development at Uaru Meco, the operator anticipates submitting the plan of development to the government of Guyana in the fourth quarter with first oil targeted for 2026, pending government approvals and project sanctioning.
Turning to exploration. Yesterday, we announced 2 new discoveries on the Stabroek Block. The Seabob-1 well encountered 131 feet of high-quality oil-bearing upper campaign sandstone reservoirs. The well is located in the southeastern part of the block, approximately 12 miles southeast of the Yellowtail field.
The Kiru-Kiru-1 well has also thus far encountered 98 feet of high-quality hydrocarbon-bearing upper campanion sandstone reservoirs. The well is currently drilling ahead to test deeper intervals and is located in the southeastern part of the block, approximately 3 miles southeast of the Cataback-1 discovery, both discoveries will add to the gross discovered recoverable resource estimate for the block of approximately 11 billion barrels of oil equivalent.
In terms of future drilling activity on the Stabroek Block, next up in the queue are Yarrow and Banjo. The Yarrow-1 well will test stacked Upper Campanian targets, up-dip of discoveries at Whiptail and Tilapia. The well is located 19 miles south of the Yellowtail 1 discovery well. The Banjo-1 well will also target stacked Upper Campanian targets west of Barreleye and up-dip of Mako. The well is located 8 miles northwest of the Barreleye-1 discovery well.
These wells will appraise the development potential of the inboard oil play in the southeast portion of the block. In addition, on Block 42 in Suriname, we will participate in the Zanderij-1 exploration well. The Shell operated well is expected to spud in late August and will test both Upper Campanian and deeper play stacked targets. Hess, Chevron and Shell each have a one third working interest.
In closing, our Bakken assets are now recovering from the severe weather impacts experienced in the first half of the year and we expect to see steady production growth in the coming quarters, particularly with the addition of the fourth rig. We had positive drilling results in the Gulf of Mexico at both Llano 6 and Huron and have a robust inventory of both infrastructure led tie back opportunities and exploration prospects. Malaysia continues to generate steady production and cash flow, and our extraordinary success in Guyana continues on all fronts. Our distinctive, long-lived portfolio uniquely positions us to deliver material and accelerating production and free cash flow growth and significant value to our shareholders.
I will now turn the call over to John Rielly.
Thanks, Greg. In my remarks today, I will compare results from the second quarter of 2022 to the first quarter of 2022. We had net income of $667 million in the second quarter compared with $417 million in the first quarter or $404 million on an adjusted basis.
Turning to E&P. E&P had net income of $723 million in the second quarter compared with $460 million in the first quarter. The changes in the after-tax components of E&P earnings between the second quarter and first quarter of 2022 were as follows: Higher realized selling prices increased earnings by $178 million; Higher sales volumes increased earnings by $170 million; Higher DD&A expense decreased earnings by $39 million; Higher cash costs decreased earnings by $39 million; All other items decreased earnings by $7 million for an overall increase in second quarter earnings of $263 million.
For the second quarter, our E&P sales volumes were underlifted compared with production by approximately 500,000 barrels, which decreased our after-tax income by approximately $15 million.
Turning to Midstream. The Midstream segment had net income of $65 million in the second quarter of 2022 compared with $72 million in the first quarter. Midstream EBITDA, before noncontrolling interest was $241 million in both the second quarter and first quarter of 2022.
Turning to our financial position. At quarter end, excluding Midstream, cash and cash equivalents were $2.16 billion, and total liquidity was $5.73 billion, including available committed credit facilities, while debt and finance lease obligations totaled $5.61 billion.
In April, we received total net proceeds of $346 million from the public offering of approximately 5.1 million Hess owned Class A shares of Hess Midstream and the sale of approximately 6.8 million Hess owned Class B units to Hess Midstream.
In the second quarter, we commenced common stock share repurchases with the purchase of approximately 1.8 million shares for $190 million under our existing $650 million board-authorized stock repurchase program. We intend to utilize the remaining amount under the stock repurchase program by the end of this year.
Total cash returned to shareholders in the second quarter amounted to $306 million, including dividends. Net cash provided by operating activities before changes in working capital was $1.46 billion in the second quarter compared with $952 million in the first quarter primarily due to higher realized selling prices and sales volumes.
In the second quarter, we sold 61 million-barrel cargoes of crude oil in Guyana, up from sales of 2.3 million barrels of crude oil in the first quarter. Changes in operating assets and liabilities during the second quarter of 2022, increased cash flow from operating activities by $46 million. E&P capital and exploratory expenditures were $622 million in the second quarter and $580 million in the first quarter.
In June, Moody’s Investors Service upgraded the senior unsecured ratings of Hess Corporation to BAA3 from BA1. All 3 major credit rating agencies now rate Hess as investment grade. In July, we replaced our $3.5 billion revolving credit facility expiring in May 2024 with a new $3.25 billion revolving credit facility expiring in July 2027.
Now turning to guidance. First, for E&P. Beginning in the third quarter, we will use the remainder of the previously generated Guyana net operating loss carryforwards. As a result, we will start to incur a current income tax liability.
Our third quarter Guyana net production guidance of 90,000 to 95,000 barrels of oil per day includes approximately 7,000 barrels of oil per day of tax barrels. Our full year 2022 Guyana net production guidance of approximately 75,000 barrels of oil per day includes approximately 6,000 barrels of oil per day of tax barrels. There were no tax barrels in the first or second quarters.
In both the third quarter and fourth quarter of this year, we expect to sell 81 million-barrel liftings from Guyana. Our E&P cash costs in the second quarter of 2022 were $13.90 per barrel of oil equivalent, including Libya, and $14.56 per barrel of oil equivalent, excluding Libya. We project E&P cash costs, excluding Libya, to be in the range of $14 to $14.50 per barrel of oil equivalent for the third quarter and in the range of $13.50 to $14 per barrel of oil equivalent for the full year, which is unchanged from previous guidance.
DD&A expense was $11.79 per barrel of oil equivalent, including Libya, and $12.34 per barrel of oil equivalent, excluding Libya, in the second quarter. DD&A expense, excluding Libya, is forecast to be in the range of $13 to $13.50 per barrel of oil equivalent for the third quarter and $12.50 to $13 per barrel of oil equivalent for the full year, which is updated from the prior guidance of $11.50 to $12.50 per barrel of oil equivalent. This results in projected total E&P unit operating costs, excluding Libya, to be in the range of $27 to $28 per barrel of oil equivalent for the third quarter and $26 to $27 per barrel of oil equivalent for the full year 2022.
Exploration expenses excluding dry hole costs, are expected to be in the range of $35 million to $40 million in the third quarter and in the range of $160 million to $170 million for the full year, which is down from our previous guidance of $170 million to $180 million. The midstream tariff is projected to be in the range of $305 million to $315 million for the third quarter and full year guidance of $1.190 billion to $1.215 billion remains unchanged.
E&P income tax, excluding Libya, is expected to be in the range of $170 million to $180 million for the third quarter and in the range of $540 million to $550 million for the full year, which is up from the previous guidance range of $460 million to $470 million, primarily due to higher commodity prices.
We expect noncash option premium amortization, which will be reflected in our realized selling prices, will be approximately $165 million for both the third and fourth quarters. Our E&P capital and exploratory expenditures are expected to be approximately $750 million in the third quarter and approximately $2.7 billion for the full year, which is down from previous guidance of $2.8 billion that I referenced in our last conference call.
The reduction is due to the phasing of activities in the Bakken and efficiencies across the portfolio. For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be in the range of $60 million to $65 million for the third quarter. The full year guidance range of $265 million to $275 million remains unchanged. For corporate, corporate expenses are estimated to be approximately $40 million for the third quarter and in the range of $135 million to $145 million for the full year, which is up from previous guidance of $120 million to $130 million due to higher legal and professional fees.
Interest expense is estimated to be approximately $85 million for the third quarter and in the range of $345 million to $350 million for the full year, which is in the lower end of our previous guidance range.
This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.
[Operator Instructions] Our first question comes from Arun Jayaram with JPMorgan.
John, I wanted to start with cash return. This quarter, you returned about 20% of your CFO, including dividends and the buyback and you acknowledge your plan to go ahead and complete the remaining authorization, which would point to about $460 million of buybacks plus the dividend.
I’m wondering as we think about your capital return framework, which includes the return of up to 75% of your free cash flow, how should we think about the pace of buybacks as we approach 2023?
Yes, John Reilly.
Yes. Thanks, Arun. So just to remind you what our — the capital return framework is our framework is set up on an annual basis. So we look at our annual free cash flow and we are planning to return — and we are committed to return up to 75% of that free cash flow. And that free cash flow is reduced for debt reductions, which we did have that $500 million in the first quarter.
So as we said, with our $650 million authorized in the $190 million done in the second quarter, you can expect the remainder to be done throughout the rest of this year, and it’s actually going to be above the 75% framework because of where commodity prices are, our discussions with the Board, our favorable balance sheet position. And look with Guyana ramping up and Bakken ramping up our free cash flow is improving, as you see from our second quarter results, so that we can give more than 75% this year with this favorable commodity price environment.
And so then coming to 2023, you really should think about, look, we just are starting capital return program. This is just the beginning, and we plan to continue it. So as we move into 2023, we are committed to that 75% framework. Again, if commodity prices are favorable, we can do more than that next year. But you should begin to think this is going to be a continued program.
And just remember now with Bakken, as we said, that’s going to 200,000 barrels a day. Guyana is going to be bringing on an FPSO almost once a year here for the coming years. So we’re going to have a growing free cash flow. So that 5% is going to be going on a bigger and bigger number as we move out. So I think that’s the strategic framework you should be thinking about.
Great. And maybe John Riley, a follow-up for you. $2.7 billion in CapEx update, a little bit lower than you told us last quarter. I was wondering if you could just provide us maybe some soft commentary around 2023 CapEx if you sustain 4 rigs in the Bakken and continue your E&D program in Guyana.
Go ahead, John. Thank you for the soft guidance, Arun, because that’s what we’ll do. As usual, we’ll provide the full guidance in January because we do have some moving parts like you said. But with the fourth rig in the Bakken and look, we did have some phasing of activities that are moving into 2023 you can at least expect an additional $150 million plus from the Bakken.
And this is before inflation, which I’ll talk about a little bit at the end. So the Bakken will be increasing with that fourth rig, some of the phasing as well. So you can think about that $150 million.
In Guyana, as you know, we’ve got a lot of things going on. So I did say this in the first quarter, there’s clearly going to be about 700 — several hundred million more in Guyana because we’d be developing Payara, right? We’re bringing that on in late 2023. We’ve got to develop with Yellowtail, the fifth FPSO, which Greg mentioned, Uaru and Meco, and we also have the gas to energy project going on in Guyana. So again, several hundred million more for Guyana, but we’ll fine-tune that as we go through the year.
Also, as you heard Greg mention, we had success at Huron well in the Gulf of Mexico. We’ll be looking at what we’re doing from an appraisal standpoint and what our Gulf of Mexico program, which typically, as we had mentioned, like to get some of these infrastructure-led tiebacks done as well as a greenfield. So we’ll be having some increase in Gulf of Mexico for 2023.
And then I mentioned it, of course, we’re monitoring the industry inflation. We are seeing it. Greg mentioned what’s happening with our D&C cost in Bakken. We are seeing it in rig rates, labor, steel costs. So we’ll continue to be looking at that and we’ll fine-tune it as we get to the end of the year. But kind of soft, those are the kind of numbers you can be looking at, Arun.
And what about the FPSO? Have you all made a determination with Exxon on buying those on your buy option?
No. That has not been finally determined yet, Arun, on the timing. The guidance I would give you right now is not to expect just in 2023. So if you’re putting in your models, you don’t pull 1 in 2023. I would expect 1 in early 2024.
But again, it’s still early days. We do not have that finalized yet.
Our next question comes from Doug Leggate with Bank of America.
I guess, could I go first to the Bakken on — obviously, you’ve given a fairly thorough explanation as to what’s been going on there with weather and power outages and so on. But I want to ask about any thoughts on the trajectory to 200,000 barrels a day.
Is there any reason why we should be rethinking the time line of that? Are you still confident in that? And what is your updated thoughts on the trajectory together?
No, Doug. I think we’re back on track in the Bakken. We’re back on that trajectory. As I mentioned in my opening remarks, we expect the third quarter to be up 10%. The fourth quarter to be up 10% from that.
And then you really see the fourth rig start to kick in because you’ll start completing wells for from that fourth rig in 2023. So that’s why we’re saying we’ll have the steady increase trajectory to 200,000 barrels a day, which we expect to hit in 2024. So it should be a smooth ramp from here.
Okay. Greg, I just wanted to kind of address that upfront. My follow-up, I’ll leave everyone else to ask on Guyana today. Greg, I want to ask you about Huron. This is perhaps a little bit more material news and perhaps your short comments might suggest.
Can you give us a little bit more color on pre-drill scale? And if you’re sidetracking, 1 assumes that you’re pretty encouraged with what you’re seeing. So what was the predrill target here? And what is this — you’ve talked about 1 potential hub development exploration well per year going forward. Does this qualify as a potential hub development?
Well, let me talk about — yes, let me talk about the well first. So it was drilled on Green Canyon Block 69 to a depth of 28,900 feet and the rig was released on June 14, 2022. So as I mentioned in my opening remarks, the prospect targeted a new Miocene sub-salt fairway in Northern Green Canyon.
Reason we’re really encouraged by the results that we discovered good, high-quality oil in good quality Miocene sands. And we — as I did mention, we’re also planning an appraisal sidetrack up dip on that well. I think the second thing that’s really exciting about it is a result of — as a result of what we’re seeing in Huron, we see additional prospectivity in that Northern Green Canyon area, and we have a very competitive leasehold position there. So 2 positive outcomes from Huron.
Doug, we don’t release predrill estimates, and the well is still under evaluation. So further information coming as we appraise that asset.
I would just add to that. I mean we’re encouraged by the prospectivity in this area. The fact that there’s a working petroleum system. So there’s going to be further drilling and appraisal ahead of us, and we’re encouraged by it.
If I may very quickly, Greg, you say you’re going to do an updip appraisal. Did you have an oil — water contact?
Well, still under evaluation, Doug.
Our next question comes from Paul Cheng with Scotiabank.
First 1 is for John Rielly. John, with the rising fear on recession, how does it or does it have all impact on the thinking or in your decision process — in you guys’ decision ports and on the budget?
Sure. So that’s one of the things I mentioned why, as Arun said, soft guidance and what our budget would be for next year. We are looking at that — obviously, it’s — there’s no change to our base program in the Bakken. We’re going to have the 4 rigs. We’re doing that. We want to optimize our infrastructure up there, lower our cash cost, and it’s the best return way to develop the Bakken. So there won’t be any change there.
And so we’ll continue to monitor the cost and update everyone on where the budget ends up with that. So on a go-forward basis, then Guyana, again, the plan is there unchanged. Obviously, just a phenomenal province for us for oil development, the returns there are excellent, and we will be trying to bring forward as much as we can to get this oil for the country of Guyana on as early as possible.
So again, Payara, Yellowtail, getting the fifth ship in for FID, try to get the development plan into the government. So no change there. Again, with Exxon, has been doing an excellent job managing the cost there. But we are susceptible to that cost inflation that everybody else is seeing.
So we’ll update again where that number comes. But as I said, we have about $1 billion this year in our plan in our original budget, and we’re not changing that in Guyana. So again, Exxon has done a really good job this year managing that inflation. And as I said, it will be several hundred million dollars more, but again, we’ll see where the inflation ends up.
And then kind of the new thing because we were just talking about a Gulf of Mexico and our program, we are looking at the rig rates and being able to get slots. So that’s something, again, that we will be looking at managing, but we do want to do this appraisal that we talked about, and we’d like to do some of our infrastructure-led tiebacks.
So — again, those are extremely good returns even if the cost inflation is a little bit higher. So I think you can take that again as our soft guidance on what we’re doing, and we keep practicing our lean culture and trying to get it as much as possible working with our strategic — So again, Exxon has done a really good job this year managing that inflation.
And as I said, it will be several hundred million dollars more. But again, we’ll see where the inflation ends up. And then kind of the new thing because we were just talking about Gulf of Mexico and our program, we are looking at the rig rates and being able to get slots. So that’s something, again, that we will be looking at.
Yes. And 1 other point, Paul. So — and it’s a great question. I think all companies are dealing with this recession risk, even though there’s an economic slowdown now. We certainly see the market getting tighter for the reasons that I mentioned between now and the end of the year.
Having said that, our Board will definitely stress test our budget for next year. Definitely, there will be a recession scenario in that, and we’ll definitely be prepared should there be a recession to stay ahead of it to keep the balance sheet strong so we can still invest in our high-return opportunity in Guyana, and we’ll also take steps as we normally do as we get to the end of the year to make sure we have some price protection on in terms of puts on the downside.
So we’ll be prepared in case a recession occurs. It’s certainly going to be one of the scenarios that the Board has with our senior leadership to make sure we’re financially disciplined going into next year.
Great. And going back to John Rielly, you mentioned some activity has been pushed from this year to next year. Can you quantify roughly how much?
Sure. So as Greg mentioned, right now with wells online, we’re a little bit down. I would say wells online. We’re only in, like, say, 5 range of wells online that are going to be moving to next year. Some of the wells drilled. So as Greg mentioned, there were 95 wells, that’s actually up from our original guidance of 90, but that didn’t include the fourth rig.
So the fourth — we should have gotten an additional, say, 14 to 15 wells drilled. And so we’re only getting 5. So we’ve got additional wells that are moving that way. So you’re looking at 9 or 10 wells to be drilled that are moving to next year, 5-ish kind of wells online moving to next year and just some other small infrastructure type things.
So altogether, you’re probably looking in that $40 million type range that got moved to next year.
Our next question comes from Jeanine Wai with Barclays.
We’d like to follow up on the Gulf of Mexico from Doug’s questions. There’s been some headlines that some of your partners there are looking to monetize their interest in 1 of your fields. And it sounds like you’re very positive on the goal for the near term.
I know you just mentioned increasing activity in ’23 and your side tracking well. Can you generally discuss what your medium-term plan is in terms of activity in the Gulf? And then our follow-up is what’s your appetite to grow your position there?
Yes, Greg, Wai, we appreciate it if you just go over our strategy. The role of the Gulf in our portfolio, the exploration acreage that we have. And I can comment on M&A side, Jeanine, in the normal course of business, we always look to optimize our portfolio, but we have not seen anything in the market, be it in the Gulf for or elsewhere that makes sense for us to do an acquisition.
We have better opportunities to invest in our portfolio of high return and low cost investments. So we’re much more focused on getting return from the inventory of investment opportunities that we have then looking to the outside. We don’t need M&A to grow the returns of our business and quite frankly, most of the stuff that we’ve seen would erode returns. We’re going to do that. We’re going to stay financially disciplined. But Greg, can you talk about the role of the Gulf in our portfolio.
Sure. Thanks, Jeanine. So the Gulf of Mexico for us, remains a very important part of the portfolio. It’s an important cash engine, and it’s a platform for growth for us. So — our objective in the Gulf is to add a minimum sustained production cash flow through tieback opportunities and also selectively pursuing hub class exploration opportunities. If we can grow it, we want to.
And as you recall, we’ve been selectively rebuilding our portfolio in the last 5 or 6 years, such that we acquired 60 new lease blocks in the Gulf we’ve got over 80 now in our portfolio, and that’s really a balance of high-return tiebacks and also hub class new exploration prospects.
So assuming those opportunities compete for capital, a good planning assumption for us going forward is that we would drill roughly 2 wells per year for the next several years that, again, is focused on both those tiebacks and new hub class opportunities with Huron being the first out of the gate, again, very encouraging results. And Huron, particularly for that Northern Green Canyon basin where we have a very competitive leasehold there. So we’re pretty excited about that.
Our next question comes from Ryan Todd with Piper Sandler.
Maybe just a couple of quick follow-ups on other questions. On the Gulf of Mexico, as you were talking about medium-term strategy, if you were to — I know this varies on a lot of things, but if you were to do that plan a couple of wells a year, is the general outlook that you’d probably hold production flat there over the medium term in the Gulf of Mexico that you could drive modest growth? Or how do you think about as you look out over the next few years, the trajectory of production there in the Gulf of Mexico?
Sure. I think for the next couple of years, you could assume our objective is really to hold it flat and we’ll do that through these infills and ILX, infrastructure-led exploration wells that are quick tiebacks.
Beyond that, we’re also going to be doing some hub class exploration prospects, obviously those wouldn’t feature those wouldn’t come in as growth until later in that period. So short term, hold it flat as a minimum longer-term grow it, assuming success from some of these sub-class exploration prospects.
Perfect. And then maybe a follow-up on an earlier comment. You talked a little bit about the dividend, the desire to grow it to a position of competitiveness. How would you define — I mean, you’ve obviously increased it materially earlier this year, but how would you define a competitive dividend?
What peer group are you looking at? And any thoughts on kind of the timetable of over which you’d like to grow that dividend to kind of a sustainable level where you’d like it to be?
Yes. I’m going to have John answer it, but I think the way to think about it is a sustainable and meaningful premium to the S&P dividend yield. That’s what we’re really looking at. We want to compete for the generalist investor, not just the oil and gas investor, but we want it to be something that also holds up under low oil prices. But John, why don’t you elaborate a little bit what our plans are.
Sure. So I mean John did give a good explanation on that, but that’s clearly what we’re looking to do, continual increases here. And John did mention it that we’d like to get our dividend to a level that is attractive to the income-oriented investors. So I think yield is an output, but you can think about the yield that the income-oriented investors are looking at.
So with our ability here, again, as I mentioned, Bakken growing to 200,000 barrels a day and then Guyana, Payara coming in late 2023 and then almost an FPSO a year here as we move out the next couple of years, we’re going to have a significant free cash flow that we’re able to continue to increase the dividend and we can kind of move that dividend as our cash flow grows.
But actually, the bigger part of our return will be share repurchases because that growing free cash flow when you put that 75% against that as we will grow that dividend, we want to make it sustainable in a low oil price environment, but the bigger portion ultimately will be share repurchases.
Our next question comes from Neil Mehta with Goldman Sachs.
I had a couple of questions on the macro. And the first is around price realizations, they were good in the quarter. And John, you had made the comment that what we see in the financial markets, it might be lower than what you’re realizing in the physical market. So can you just talk about that divergence and whether you’re able to realize something higher than the front price?
Yes. I mean obviously, this changes, as you know, Neil, it’s a great question, every day. But what we’ve been seeing really for the last 2 months is buyers for physical Brent or physical Brent equivalents is several dollars a barrel premium over the screen or the futures market.
There’s strong buying that’s out there. Obviously, not just because the world is short inventory and needs the current barrels. But obviously, what’s going on in Russia and Europe, has tightened the market even more, which you’re seeing more in the Brent price than you are in the WTI price on the screen. But several dollars a barrel, I think, is a good planning assumption for now.
And we’ll just have to see how the market evolves between now and the end of the year. One of the concerns we have is obviously, if more barrels are taken out of Russia. I think Russia is down in terms of their exports about 1 million barrels a day. If that number grows and the EU is talking about sanctioning more of those barrels, I think that physical premium will go up.
And the follow-up is on natural gas. And so we do love your perspective on how you’re thinking about U.S. natural gas, in particular — and if anything structurally changed in your view of mid-cycle? And then as it relates to your hedging position, remind us how open you are over the next couple of years? And can you participate in the strengthening commodity curve.
Yes, I’ll have John handle the hedging. And natural gas, obviously, is being impacted specifically in Europe, and the LNG trading business because Europe buys about 40% of their supply from Russia. Obviously, that continues to be interrupted. Very concerns about its availability going into the winter, you’re also starting to see the EU and European countries start to ration gas, and that’s having an impact on the European price, the Asian price because of the LNG factor.
And I think the U.S. has been relatively insulated from that because of shale gas and domestic production as well as the Freeport terminal, having had its problems and when that recovers. So I think the numbers for natural gas in Europe are somewhere between $50 and $60 an Mcf, where in the U.S., it’s closer to 9%. So the U.S. is still up but it’s much lower than the rest of the world, in part because we’re energy-independent. We’re a net exporter.
So I think as you think about natural gas going into the winter, that’s going to stay very tight both in the U.S. and even more so in Europe and Asia. When you look past that, I think a lot of that is a function of when does the Russian-Ukraine conflict get resolved, got willing sooner than later, where lives are saved on both sides for that matter. And then I think the natural gas business will start to normalize.
There’s plenty of natural gas out there, but it has to be falling for inventories to rebuild so that you get more back to equilibrium prices. But we see the natural gas market, both in the U.S. and the rest of the world, staying tight, certainly through this coming winter. John, do you want to hit the hedging question?
Sure. So for hedges for next year, we do not have any hedges on in 2023 or beyond at this point. Now, you know our strategy, and you should assume that we’ll continue with that strategy is to put a floor price on.
So as we get to the end of the year, we’ll use puts, obviously, where volatility is, that from everything that John has been discussing on this call and also just the time aspect of the put options. We’ll be putting them on closer to the end of the year or early into next year. That’s typically the time frame that we do that.
But we do want to put a floor on. You can expect us to do that again next year and years after to just again to provide that insurance, should prices — should there be a change? Should there be a recession or something happening that drops those prices, but we’ll do that towards the end of the year.
Our next question comes from Roger Read with Wells Fargo.
Maybe just follow up on some of the last discoveries here in Guyana and some of the stuff before. Where are you in terms of drill stem tests, flow rate tests, things like that as we try to think about some of the things that will eventually raise — more than likely raise the 11 billion-barrel resource target that’s out there.
Yes. So as we said, these 2 discoveries, Seabob and Kiru-Kiru, which are still underway, so those will be additive to the already announced 11 billion barrels gross recoverable hydrocarbons. I think the significant part about these discoveries is why they’re so encouraging is that if you look at Seabob, that is leading to a potential inboard oil play in the southeastern part of the Stabroek Block.
And in fact, as we look forward, the next 2 wells, Yarrow and Banjo will help further delineate that inboard oil opportunities. So there could be another oil FPSO centered on that inboard oil play. So as you mentioned, after we get these wells done, we’ll do some DSPs, et cetera, on them really trying to prove up really that inboard oil play. So very, very exciting.
Yes. So Guyana has been that way for several years now. It’s good to see it keep you on. The other question, if I could, just kind of going back to the inflation question. As you’re starting to look and understand all the things that are out there, recession, et cetera. But let’s assume the crude strip is right. We’re going to continue to see activity and probably some inflation next year. Where are you at this point in terms of getting a good handle on what 2023 underlying inflation might be in terms of — you talked about Guyana already, but lower 48 and Gulf of Mexico.
John, do you want to answer that part?
Sure. So I mean we are seeing, Roger, that just like our competitors, we’re seeing upward pressure onshore and offshore with steel prices, labor costs and rig rates. So there’s no question we are seeing that.
So we — as you mentioned, we talked about Guyana. So onshore, you heard Greg mention that the D&C cost did go from 6.2% to 6.3% this year. We are seeing inflation coming from 2023, these things continuing. So I can’t give the number. That’s why we’ll wait till the end of the year, but you should expect that 6.3% to be higher in 2023 when we get the full numbers in.
Again, we’re working hard to mitigate the effects through efficiency gains, working with our suppliers, contracts and all our relationships there. And with the strength of the oil prices, like you mentioned, I still think with that tightness going into 2023, we will continue to see that. But of course, with the higher oil prices, obviously, we’re getting much higher returns in cash flow.
So I can’t be exactly specific. That’s what I said earlier, but we’ll continue to work the contracts through the end of the year, and I’ll update everyone on our January call.
Yes. And I think, Roger, the other thing is Greg and his team moved expeditiously this secure excellent equipment with Nabors and also with — and cruise with Halliburton as well. So some of our competitors, I don’t think are as well positioned as we are to have high-quality equipment and people. And I think that will inure to our benefit as we go into next year to mitigate the cost pressures plus the fact that Greg and his team are leaders of the manufacturing and have a proven track record of mitigating cost increases. So the exact number, as John said, we’ll give you at the end of the year, but I think we’re staying ahead of it and taking steps to mitigate whatever that impact is.
Our next question comes from Vin Lovaglio with Mizuho.
The first question was just on debottlenecking work at Liza Phase 1. I was just wondering if you could remind me about the investment required to get those 20,000 barrels extra online? And then probably more importantly, your ability to carry over a similar debottlenecking work to future projects.
Yes, sure. So the investment level to get to that new nameplate of that new capacity of 140,000 barrels a day from the 120 on Phase I, very minimal. I mean this was some piping changes, et cetera. So you shouldn’t think about that as a major investment on Phase 1.
As we look forward to future phases, certainly in Phase II and also Payara, I think we could see the potential for additional debottlenecking for those 2 vessels. Beyond that, as your vessels get bigger, say, the 250 class, we’ll have to wait and see.
And I think the important thing to remember about these debottlenecking efforts is it’s going to be bespoke for each vessel. So it’s going to depend on the individual dynamics of that vessel operating as to how much additional capacity you can eke out of it. So hopefully, that answers your question.
Great. And the second 1 was just back to cash return and the regular dividend? I mean, obviously, the investment profile and the capital intensity of Guyana development is quite a bit different from U.S. unconventional.
Just wondering how this affects your thinking on regular dividends and if you think that the regular or the base dividend is 1 way that you can ultimately differentiate from your peer group and the E&Ps.
Yes. We certainly intend to increase the dividend each year and at a moderate pace, but 1 that builds value over time that will be sustainable, but also meaningful.
Our next question comes from David Deckelbaum with Cowen.
I really only had, I think, 1 additional follow-up to some of the other questions that were answered already. But as we think about — you’ve thrown out the 200,000 a day target in the Bakken as a most optimal level of performance for the asset.
Just given some of the inflation that we’re seeing there, some of the inflation that we’re seeing both on the unit cost size, is 200,000 still the right number? And is there — is that still a steady-state 4 rig program? Or just given the move in higher pricing if we were to believe in the long-term price at higher given some of the inflation, do all of these numbers move slightly higher?
No. Look, I think if you look at our portfolio, we’ve got 2,100 or more drilling locations that generate great returns at a $60 WTI. So obviously, at current prices, those returns are fantastic, right? And so certainly, the movement in the oil price from a return standpoint is outstripping any inflationary effects.
And the 200,000 barrel a day kind of plateau rate, if you will, for the Bakken is absolutely the optimum place to be because it really fills up all the infrastructure that we have in place in the Bakken. So you need to think about future wells as almost like a tieback in the Gulf of Mexico.
The infrastructure is already there. So the incremental returns are very high for those Bakken wells. So we’ll hold that with the portfolio we have, we’ll hold that for rigs and be able to hold that plateau at about 200,000 barrels a day for almost a decade, all the while, the Bakken generating significant amount of free cash flow during that period.
So at $60, it generates over $1 billion of free cash flow. Obviously, current price is much higher. So it becomes this massive cash annuity for the portfolio at that 200,000 barrels a day.
This concludes today’s conference. Thank you for your participation. You may now disconnect.