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Text: These risks include those set forth in the Risk Factors section of Hess' annual and quarterly reports filed with the SEC.
Also on today's conference call, we may discuss certain non-GAAP financial measures.
A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.
Today, I will review our continued progress in executing our strategy and our long-standing commitment to sustainability.
Greg Hill will then discuss our operations and John Rielly will cover our financial results.
Our strategy is to grow our resource base, have a low cost of supply and sustained cash flow growth.
Executing this strategy has positioned our company to deliver industry-leading cash flow growth over the next decade and has made our portfolio increasingly resilient in a low oil price environment.
Our strategy aligns with the world's growing need for affordable reliable and cleaner energy that is necessary for human prosperity and global economic development.
We recognize a climate change is the greatest scientific challenge of the 21st century and support the aim of the Paris Agreement and a global ambition to achieve net zero emissions by 2050.
The world faces the dual challenge of needing 20% more energy by 2040 and reaching net zero carbon emissions by 2050.
In the International Energy Agency's rigorous sustainable development scenario, which assumes that all pledges of the Paris agreement are met, oil and gas will be 46% of the energy mix in 2040 compared with approximately 53% today.
In the IEA's newest net zero scenario, oil and gas will still be 29% of the energy mix in 2040.
In either scenario, oil and gas will be needed for decades to come and will require significantly more global investment over the next 10 years on an annual basis than the $300 billion spent last year.
The key for our company is to have a low cost supply by investing only in high-return low cost opportunities.
The best rocks for the best returns.
We have built a differentiated and focused portfolio that is balanced between short cycle and long cycle assets Guyana is our growth engine and The Bakken, Gulf of Mexico and Southeast Asia are our cash engines.
Guyana is positioned to become a significant cash engine in the coming years, as multiple phases of low-cost oil developments come online, which we expect will drive our portfolio breakeven Brent oil price below $40 per barrel by the middle of the decade.
Based on the most recent third-party estimates, our cash flow is estimated to grow at a compound annual growth rate of 42% between 2020 and 2023, which is 75% above our peers and puts us in the top 5% of the S&P 500.
With a line of sight for up to 10 FPSOs to develop the discovered resources in Guyana, this industry leading cash flow growth rate is expected to continue through the end of the decade.
Investors want durability and growth in cash flow.
We are pleased to announce today that in July, we paid down $500 million of our $1 billion term loan maturing in March 2023.
Depending upon market conditions, we plan to repay the remaining $500 million in 2022.
This debt reduction, combined with the start-up of Liza Phase 2 early next year is expected to drive our debt-to-EBITDAX ratio under 2 times next year.
Once this debt is paid off and our portfolio generates increasing free cash flow, we plan to return the majority to our shareholders.
First, through dividend increases and then opportunistic share repurchases.
We expect to receive approximately $375 million in proceeds and our ownership in Hess Midstream on a consolidated basis, will be approximately 45% compared with 46% prior to the transaction.
On April 30, we completed the sale of our Little Knife and Murphy Creek nonstrategic acreage interest in The Bakken for a total consideration of $312 million effective March 1, 2021.
This acreage, most of which we were not planning to drill before 2026 was located in the Southern most portion of our Bakken position and was not connected to Hess Midstream Infrastructure.
The Midstream transaction and the sale of the Little Knife and Murphy Creek acreage bring material value forward and further strengthen our cash and liquidity position.
The Bakken remains a core part of our portfolio and our largest operated asset.
We have a large inventory of future drilling locations that generate attractive financial returns at $50 per barrel WTI.
In February, when WTI oil prices moved above $50 per barrel, we added a second rig, given the continued strength in oil prices, we are now planning to add a third rig in the Bakken in September, which is expected to strengthen free cash flow generation in the years ahead.
Key to our long-term strategy is Guyana with its low cost of supply and industry-leading financial returns.
We have an active exploration and appraisal program this year on the Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator.
We see the potential for at least six FPSOs on the block by 2027 and up to 10 FPSOs to develop the discovered resources on the block, and we continue to see multibillion barrels of future exploration potential remaining.
Earlier today, we announced a significant new oil discovery at Whiptail.
The Whiptail number 1 well encountered 246 feet of net pay and the Whiptail number 2 well, which is located three miles northeast of Whiptail-1 encountered 167 feet of net pay in high quality oil bearing sandstone reservoirs.
Drilling continues at both wells to test deeper targets.
The Whiptail discovery could form the basis for our future oil development in the Southeast area of the Stabroek Block and will add to the previous recoverable resource estimate of approximately 9 billion barrels of oil equivalent.
In June, we also announced the discovery at the Longtail-3 well which encountered approximately 230 feet of net pay including newly identified high quality hydrocarbon bearing reservoirs, below the original Longtail-1 discovery intervals.
In addition, the successful Mako-2 well, together with Uaru-2 well which encountered approximately 120 feet of high quality oil bearing sandstone reservoir will potentially underpin a fifth oil development in the area east of the Liza complex.
In terms of Guyana developments, the Liza Unity FPSO with a gross capacity of 220,000 barrels of oil per day is expected to sail from Singapore to Guyana in late August and the Liza-2 development is on track to achieve first oil in early 2022.
Our third oil development on the Stabroek Block at the Payara field is expected to achieve first oil in 2024, also with a gross capacity of 220,000 barrels of oil per day.
Engineering work for our fourth development on the Stabroek Block at Yellowtail is underway with preliminary plans for a gross capacity in the range of 220,000 to 250,000 barrels of oil per day and anticipated start-up in 2025 pending government approvals and project sanctioning.
Our three sanctioned oil developments have a breakeven Brent oil price of between $25 and $35 per barrel.
And according to a recent data from Wood McKenzie, our Guyana developments are the highest margin, lowest carbon intensity oil and gas assets globally.
Last week we announced publication of our 24th Annual Sustainability Report, which details our Environmental, Social and Governance or ESG strategy and performance.
In 2020 we significantly surpassed our five-year emission reduction targets reducing Scope 1 and 2 operated greenhouse gas emissions intensity by 46% and flaring intensity by 59% compared to 2014 levels.
Our five year operated emission reduction targets for 2025 which are detailed in the sustainability report exceed the 22% reduction in carbon intensity by 2030 in the International Energy Agency sustainable development scenario, which is consistent with the Paris Agreements ambition to hold the rise in global average temperature to well below 2 degrees centigrade.
We are also contributing to groundbreaking research being done by the Salk Institute to develop plants with larger root systems that are capable of absorbing and storing potentially billions of tons of carbon per year from the atmosphere.
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 14th consecutive year, based upon an independent assessment by ISS ESG.
And we were the only oil and gas company to earn a place on the 2021 list.
In summary, oil and gas are going to be needed for decades to come.
By continuing to successfully execute our strategy and achieve strong operational performance, our company is uniquely positioned to deliver industry-leading cash flow growth over the next decade.
As our term loan is paid off and our portfolio generates increasing free cash flow, the majority will be returned to our shareholders, first through dividend increases and then opportunistic share repurchases.
In the second quarter, we continued to deliver strong operational performance.
Companywide net production averaged 307,000 barrels of oil equivalent per day excluding Libya, above our guidance of 290,000 to 295,000 barrels of oil equivalent per day, driven by good performance across the portfolio.
In the third quarter, we expect companywide net production to average approximately 265,000 barrels of oil equivalent per day excluding Libya, which reflects the Tioga Gas Plant turnaround in the Bakken and planned maintenance in the Gulf of Mexico and Southeast Asia.
For full year 2021, we now forecast net production to average approximately 295,000 barrels of oil equivalent per day excluding Libya, compared to our previous forecast of between 290,000 and 295,000 barrels of oil equivalent per day, so we're now forecasting to be at the top of the range.
Turning to the Bakken.
Second quarter net production averaged 159,000 barrels of oil equivalent per day.
This was above our guidance of approximately 155,000 barrels of oil equivalent per day, primarily reflecting increased gas capture which has allowed us to drive flaring to under 5%, well below the state's 9% limit.
For the third quarter we expect Bakken net production to average approximately 145,000 barrels of oil equivalent per day, which reflects the planned 45 day maintenance turnaround and expansion tie-in at the Tioga Gas Plant.
For the full year 2021, we maintain our Bakken net production forecast of 155,000 to 160,000 barrels of oil equivalent per day.
In the second quarter, we drilled 17 wells and brought nine new wells online.
In the third quarter, we expect to drill approximately 15 wells and to bring approximately 20 new wells online.
And for the full year 2021, we now expect to drill approximately 65 wells and to bring approximately 50 new wells online.
In terms of drilling and completion costs, although we have experienced some cost inflation, we are confident that we can offset the increases through technology and lean manufacturing efficiency gains and are therefore maintaining our full year average forecast of $5.8 million per well in 2021.
We've been operating two rigs since February, but given the improvement in oil prices and our robust inventory of high return drilling locations, we plan to add a third rig in September.
Moving to a three rig program will allow us to grow cash flow and production, better 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 52,000 barrels of oil equivalent per day compared to our guidance of approximately 50,000 barrels of oil equivalent per day.
In the third quarter, we forecast Gulf of Mexico net production to average between 35,000 and 40,000 barrels of oil equivalent per day, reflecting planned maintenance downtime as well as some hurricane contingency.
For the full year 2021, our forecast for Gulf of Mexico net production remains approximately 45,000 barrels of oil equivalent per day.
In Southeast Asia, net production in the second quarter was 66,000 barrels of oil equivalent per day, above our guidance of approximately 60,000 barrels of oil equivalent per day.
Third quarter net production is forecast to average between 50,000 and 55,000 barrels of oil equivalent per day, reflecting planned maintenance at North Malay Basin and the JDA as well as Phase-3 installation work at North Malay Basin.
Full year 2021 net production is forecast to average approximately 60,000 barrels of oil equivalent per day.
Now turning to Guyana, in the second quarter gross production from Liza phase one averaged 101,000 barrels of oil per day or 26,000 barrels of oil per day net to Hess.
The repaired flash gas compression system has been installed on the Liza Destiny FPSO and is under test.
The operator is evaluating the test data to optimize performance and is safely managing production in the range of 120,000 to 125,000 barrels of oil per day.
Replacement of the flash gas compression system with a modified design and production optimization work are planned for the fourth quarter, which will result in higher production capacity and reliability.
Net production from Liza Phase-1 is forecast to average approximately 30,000 barrels of oil per day in the third quarter and for the full year 2021.
The Liza Phase-2 development will utilize the 220,000 barrels of oil per day Unity FPSO which is scheduled to sail away from Singapore at the end of August and first order remains on track for early 2022.
Turning to our third development Payara.
The Prosperity FPSO oil is complete and will enter the Keppel yard in Singapore following sale away of the Liza Unity.
Topsides fabrication has commenced the dynamic and development drilling began in June.
The overall project is approximately 45% completed.
The Prosperity will have a gross production capacity of 220,000 barrels of oil per day and is on track to achieve first oil in 2024.
As for our fourth development at Yellowtail.
The joint venture anticipate submitting the plan of development to the Government of Guyana in the fourth quarter, with first oil targeted for 2025, pending government approvals and projects sanctioning.
During the second quarter the Mako-2 Appraisal well on the Stabroek Block confirmed the quality, thickness and areal extent of the reservoir.
When integrated with the previously announced discovery at Uaru-2, the data supports a potential fifth development in the area east of the Liza complex.
Drilling continues at both wells to test deeper targets.
In terms of other drilling activity in the second half of 2021 after Whiptail-2, the Noble Don Taylor will drill the Pinktail exploration well, which is located five miles southeast of Yellowtail one, followed by the Tripletail-2 appraisal well, located five miles south of Tripletail-1.
The Noble Tom Madden will spud the Kaieteur Block-1 exploration well located 4.5 miles southeast of the Turbot-1 discovery in early August.
Then in the fourth quarter, we will drill our first dedicated test of the deep potential at the [Indecipherable] prospect located 9 miles northwest of Liza-1.
In the third quarter, The Noble Sam Croft will drill the Turbot-2 appraisal well then transition to development drilling operations for the remainder of the year.
The Stena Carron will conduct a series of appraisal drill stem tests at Uaru-1, Mako-2 and then Longtail-2.
In closing, we continue to deliver strong operational performance across our portfolio.
Our Offshore assets are generating strong free cash flow.
The Bakken is on a capital-efficient growth trajectory and Guyana keeps getting bigger and better, all of which positions us to deliver industry-leading returns, material cash flow generation and significant shareholder value.
In my remarks today, I will compare results from the second quarter of 2021 to the first quarter of 2021.
Adjusted net income was $74 million in the second quarter of 2021, compared to net income of $252 million in the first quarter of 2021.
E&P adjusted net income was $122 million in the second quarter of 2021 compared to net income of $308 million in the previous quarter.
The changes in the after-tax components of adjusted E&P results between the second quarter and first quarter of 2021 were as follows: Lower sales volumes reduced earnings by $126 million; higher cash costs reduced earnings by $48 million; higher exploration expenses reduced earnings by $10 million; all other items reduced earnings by $2 million, for an overall decrease in second quarter earnings of $186 million.
Second quarter sales volumes were lower, primarily due to Guyana having two, 1 million barrel liftings of oil, compared with three, 1 million barrel liftings in the first quarter and first quarter sales volumes included non-recurring sales of two VLCC cargos totaling 4.2 million barrels of Bakken crude oil, which contributed approximately $70 million of net income.
In the second quarter, our E&P sales volumes were under lifted compared with production by approximately 785,000 barrels, which reduced our after-tax results by approximately $18 million.
Cash costs for the second quarter came in at the lower end of guidance and reflect higher planned maintenance and workover activity in the first quarter.
In June, the US Bankruptcy Court approved the bankruptcy plan for Fieldwood Energy, which includes transferring abandonment obligations of Fieldwood to predecessors in title of certain of its assets, who are jointly and severally liable for the obligations.
As a result of the bankruptcy, Hess as one of the predecessors in title in 7 Shallow Water, West Delta 79-86 leases held by Fieldwood is responsible for the abandonment of the facilities on the leases.
Second quarter E&P results include an after tax charge of $147 million representing the estimated gross abandonment obligation for West Delta 79-86 without taking into account potential recoveries from other previous owners.
Within the next nine months, we expect to receive an order from the regulator requiring us along with other predecessors in title to decommission the facilities.
The timing of these decommissioning activities will be discussed and agreed upon with the regulator and we anticipate the cost will be incurred over the next several years.
The Midstream segment had net income of $76 million in the second quarter of 2021 compared to $75 million in the prior quarter.
Midstream EBITDA before noncontrolling interest amounted to $229 million in the second quarter of 2021 compared to $225 million in the previous quarter.
Now turning to our financial position.
At quarter end, excluding Midstream, cash and cash equivalents were $2.42 billion, which includes receipt of net proceeds of $297 million from the sale of our Little Knife and Murphy Creek acreage in the Bakken.
Total liquidity was $6.1 billion, including available committed credit facilities, while debt and finance lease obligations totaled $6.6 billion.
Our fully undrawn $3.5 billion revolving credit facility is committed through May 2024 and we have no material near-term debt maturities aside from the $1 billion term loan which matures in March 2023.
In July, we repaid $500 million of the term loan.
Earlier today Hess Midstream announced an agreement to repurchase approximately 31 million Class B units of Hess Midstream held by GIP and us for approximately $750 million.
We expect to receive net proceeds of approximately $375 million from the sale in the third quarter.
In addition, we expect to receive proceeds in the third quarter from the sale of our interest in Denmark for total consideration of $150 million with an effective date of January 1, 2021.
In the second quarter of 2021, net cash provided by operating activities before changes in working capital was $659 million compared with $815 million in the first quarter, primarily due to lower sales volumes.
In the second quarter, net cash provided by operating activities after changes in working capital was $785 million compared with $591 million in the first quarter.
Changes in operating assets and liabilities during the second quarter of 2021 increased cash flow from operating activities by $126 million, primarily driven by an increase in payables that we expect to reverse in the third quarter.
Now turning to guidance.
Our E&P cash costs were $11.63 per barrel of oil equivalent including Libya and $12.16 per barrel of oil equivalent, excluding Libya in the second quarter of 2021.
We project E&P cash costs, excluding Libya to be in the range of $13 to $14 per barrel of oil equivalent for the third quarter, which reflects the impact of lower production volumes resulting from the Tioga Gas Plant turnaround.
Full year cash cost guidance of $11 to $12 per barrel of oil equivalent remains unchanged.
DD&A expense was $11.55 per barrel of oil equivalent including Libya and $12.13 per barrel of oil equivalent excluding Libya in the second quarter.
DD&A expense excluding Libya is forecast to be in the range of $12 to $13 per barrel of oil equivalent for the third quarter and full-year guidance of $12 to $13 per barrel of oil equivalent remains unchanged.
This results in projected total E&P unit operating costs, excluding Libya to be in the range of $25 to $27 per barrel of oil equivalent for the third quarter and $23 to $25 per barrel of oil equivalent for the full year of 2021.
Exploration expenses excluding dry hole costs are expected to be in the range of $40 million to $45 million in the third quarter and full-year guidance is expected to be in the range of $160 million to $170 million, which is down from previous guidance of $170 million to $180 million.
And Midstream tariff is projected to be in the range of $265 million to $275 million for the third quarter and full-year guidance is projected to be in the range of $1,080 million to $1,100 million, which is down from the previous guidance of $1,090 million to $1,115 million.
E&P income tax expense, excluding Libya is expected to be in the range of $35 million to $40 million for the third quarter and full-year guidance is expected to be in the range of $125 million to $135 million, which is updated from the previous guidance of $105 million to $15 million reflecting higher commodity prices.
We expect non-cash option premium amortization will be approximately $65 million for the third quarter and full-year guidance of approximately $245 million remains unchanged.
During the third quarter, we expect to sell three 1 million barrel cargoes of oil from Guyana.
Our E&P capital and exploratory expenditures are expected to be approximately $575 million in the third quarter.
Full-year guidance, which now includes increasing drilling rigs in the Bakken to three from two in September, remains unchanged from prior guidance at approximately $1.9 billion.
We anticipate net income attributable to Hess from the Midstream segment to be in the range of $50 million to $60 million for the third quarter and full-year guidance is projected to be in the range of $275 million to $285 million, which is down from the previous guidance of $280 million to $290 million.
Corporate expenses are estimated to be in the range of $30 million to $35 million for the third quarter and full-year guidance of $130 million to $140 million remains unchanged.
Interest expense is estimated to be in the range of $95 million to $100 million for the third quarter and approximately $380 million for the full year, which is at the lower end of our previous guidance of $380 million to $390 million reflecting the $500 million reduction in the term loan.
This concludes my remarks, we will be happy to answer any questions.

user
qtrly net production from the gulf of mexico was 52,000 boepd.
qtrly net production from bakken was 159,000 boepd compared with 194,000 boepd in prior-year quarter.
net production, excluding libya, was 307,000 boepd in q2 of 2021, compared with 334,000 boepd in q2 of 2020.
2021 net production, excluding libya, is expected to be approximately 295,000 boepd.
excluding midstream segment, hess corporation had cash and cash equivalents of $2.42 billion at quarter-end.

assistant