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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.
Greg Hill then will discuss our operations and John Riley will cover our financial results.
With COP26 beginning this Sunday, it is appropriate to address the energy transition.
Climate change is the greatest scientific undertaking of the 21st century.
The world has two challenges to grow our global energy supply by about 20% in the next 20 years and to reach net zero emissions by 2050.
The International Energy Agency published its latest World Energy Outlook earlier this month, which provides four scenarios to shed light on these challenges.
It is important to remember that these are scenarios not forecast to help guide policymakers and business leaders in their decision making.
In all four scenarios, oil and gas will still be needed in the decades to come.
Significantly more investment will be required to meet the world's growing energy needs, much more in renewables and much more in oil and gas.
Our reasonable estimate for global oil and gas investment from these IEA scenarios is at least $400 billion each year over the next 10 years.
Last year, that number was $300 billion.
This year's estimate is $340 billion.
To ensure a successful an orderly energy transition, we need to have climate literacy, energy literacy and economic literacy.
Our strategy is to grow our resource base, have a low cost of supply and sustain cash flow growth.
While delivering industry-leading environmental social and governance, performance and disclosure by investing only in high-return, low cost opportunities, we have built a differentiated and focused portfolio that is balanced between short cycle and long cycle assets.
Our cash engines are the Bakken, the Gulf of Mexico and Southeast Asia, where we have competitively advantaged assets and operating capabilities.
Guyana is our growth engine and is on track to become a significant cash engine in the coming years, as multiple phases of low-cost oil developments come online.
Also, by adding a third rig in the Bakken in September and completing the turnaround and expansion of the Tioga Gas Plant, the Bakken is expected to generate significant free cash flow in the years ahead.
By successfully executing our strategy, our company is positioned to deliver strong and durable cash flow growth through the end of the decade.
Based upon the most recent sell side consensus estimates, our cash flow is estimated to grow at a compound annual growth rate of 42% between 2020 and 2023, which is 50% above our peers and puts us in the top 5% of the S&P 500.
As our portfolio generates increasing free cash flow, we will first prioritize debt reduction and then cash returns to shareholders through dividend increases and opportunistic share repurchases.
We have continued to maintain financial strength as well as managing for risk.
As of September the 30th, we had $2.4 billion of cash on the balance sheet.
In July, we prepaid half of our $1 billion term loan maturing in March 2023 and we plan to repay the remaining $500 million in 2022.
This debt reduction combined with the start up of lease of Phase 2 early next year, is expected to drive our debt to EBITDAX ratio under 2% and also enable us to consider increasing cash returns to shareholders.
In August, we completed the sale of our interest in Denmark for total consideration of $150 million effective January 1, 2021, and received $375 million in proceeds from Hess Midstream's buyback of Class B units from its sponsors Hess Corporation and Global Infrastructure Partners.
Earlier this month, our company also received net proceeds of $108 million from the public offering of Hess-owned Class A shares of Hess Midstream.
The Denmark sale and these Midstream monetizations brought material value forward and further strengthened our cash and liquidity position.
Key to our long-term strategy is Guyana, one of the industry's best investments.
On the Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator, we announced the 19th and 20th of significant discoveries during the third quarter at Whiptail and Pinktail.
And on October 7th, we announced the 21st significant discovery on the block at Cataback.
These discoveries will underpin our Q, our future low cost oil development.
We see the potential for at least six FPSOs on the Stabroek Block producing more than $1 million gross barrels of oil per day in 2027, and up to 10 FPSOs to develop the discovered resources on the block.
On October 7th, we increased the gross discovered recoverable resource estimate for the block to approximately 10 billion barrels of oil equivalent, up from the previous estimate of more than 9 billion barrels of oil equivalent.
And we continue to see multibillion barrels of future exploration potential remaining.
In terms of our current Guyana developments, gross production from the lease of Phase 1 complex average 124,000 barrels of oil per day in the third quarter.
The lease of Phase 2 development is on track for start-up in early 2022 with a gross production capacity of 220,000 barrels of oil per day and the leasing Unity FPSO arrived in Guyana on Monday.
Our third development on the Stabroek Block at the Payara field is on track to achieve first oil in 2024 also with a gross capacity of 220,000 barrels of oil per day.
Our three-sanctioned oil developments have a breakeven Brent oil price of between $25 and $35 per barrel.
The plan of development for our fourth development on the block at Yellowtail was recently submitted to the Government of Guyana for approval.
Pending government approvals, the project is envisioned to have a gross capacity of approximately 250,000 barrels of oil per day with first oil in 2025.
We are proud to be recognized as an industry leader in our environmental, social and governance performance and disclosure.
Earlier this month, our company received a AAA rating in the MSCI ESG ratings for 2021 after earning A ratings for the previous 10 consecutive years.
The AAA rating digit makes Hess as a leader in managing industry specific ESG risks relative to peers and reflects our strong management practices to reduce carbon emissions as well as our top quartile performance in areas such as biodiversity and land use, reduction of air and water emissions and waste, and making a positive impact on the communities where we operate.
In summary, we remain focused on executing our strategy and achieving strong operational and ESG performance.
Our company is uniquely positioned to deliver cash flow growth over the next decade.
That is not only industry leading, but which we believe will rank among the best in the S&P 500.
After our term loan is paid off and our portfolio generates increasing free cash flow, we will prioritize return of capital to our shareholders through dividend increases and opportunistic share repurchases.
In the third quarter, we continued to deliver strong operational performance, meeting our production targets despite extended hurricane-related downtime in the Gulf of Mexico and safely executing a major turnaround at our Tioga Gas Plant in North Dakota.
Companywide net production averaged 265,000 barrels of oil equivalent per day excluding Libya in line with our guidance.
In the fourth quarter and for the full year 2021, we expect companywide net production to average approximately 295,000 barrels of oil equivalent per day excluding Libya.
Turning to the Bakken, third quarter net production averaged 148,000 barrels of oil equivalent per day.
This was above our guidance of approximately 145,000 barrels of oil equivalent per day and primarily reflected strong execution of the Tioga Gas Plant turnaround and expansion, no small task in a COVID environment that required strict adherence to extensive safety protocols to keep more than 650 workers safe.
For the fourth quarter, we expect Bakken net production to average between 155,000 and 160,000 barrels of oil equivalent per day.
For the full year 2021, we forecast our Bakken net production to average approximately 155,000 barrels of oil equivalent per day, compared to our previous guidance range of 155,000 to 160,000 barrels of oil equivalent per day.
This guidance reflects an increase in NGL prices, which reduces volumes under our percentage of proceeds contracts, but significantly increases this year's earnings and cash flow.
In the third quarter, we drilled 18 wells and brought 19 new wells online.
In the fourth quarter, we expect to drill approximately 19 wells and to bring approximately 18 new wells online.
And for the full year 2021, we continue to 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 maintaining our full year average forecast of $5.8 million per well in 2021.
Since February, we've been operating two rigs.
But given the improvement in oil prices and our robust inventory of high return drilling locations, we added a third rig in September.
Moving to a three-year 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, third quarter net production averaged 32,000 barrels of oil equivalent per day, compared to our guidance range of 35,000 to 40,000 barrels of oil equivalent per day.
Our results reflected an extended period of recovery following Hurricane Ida, which caused power outages at transportation and processing facilities downstream of our platforms.
Production was restored at all of our facilities by the end of September.
In the fourth quarter, we forecast Gulf of Mexico net production to average between 40,000 and 45,000 barrels of oil equivalent per day.
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 third quarter was 50,000 barrels of oil equivalent per day in line with our guidance of 50, 000 to 55,000 barrels of oil equivalent per day, reflecting the impact of planned maintenance shutdowns and lower nominations due to COVID.
Fourth quarter net production is forecast to average approximately 65,000 barrels of oil equivalent per day and our full year 2021 net production forecast remains at approximately 60,000 barrels of oil equivalent per day.
Now turning to Guyana.
In the third quarter, gross production from Liza Phase 1 averaged 124,000 barrels of oil per day or 32,000 barrels of oil per day net to Hess.
Replacement of the flash gas compression system on the Liza Destiny with a modified design is planned for the fourth quarter and production optimization work is now planned to take place in the first quarter of 2022.
These two projects are expected to 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 fourth quarter and for the full year 2021.
Liza Phase 2 development will utilize the 220,000 barrels of oil per day Unity FPSO, which arrived in Guyana Monday evening.
Next steps will be more in line installation and umbilical and riser hook up.
First oil remains on track for first quarter 2022.
Turning to our third development at Payara, the Prosperity FPSO hull entered the Keppel yard in Singapore on August 1st.
Topside fabrication of dynamic and development drilling are underway.
The overall project is approximately 60% complete.
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 earlier this month, the joint venture submitted a plan of development to the Government of Guyana, pending government approvals and project sanctioning.
The Yellowtail project will utilize an FPSO with a gross capacity of approximately 250,000 barrels of oil per day.
First oil is targeted for 2025.
As John mentioned, we announced three discoveries since July.
In July, we announced that the Whiptail 1 and 2 wells encountered 246 feet and 167 feet of high quality oil bearing sandstone reservoirs respectively.
This discovery is located approximately four miles southeast of well 1 and 3 miles west of the Yellowtail.
In September, we announced that the Pinktail 1 well located approximately 22 miles southeast of Liza 1 encountered 220 feet of high quality oil bearing sandstone reservoirs.
And finally earlier this month, we announced a discovery of Cataback located approximately 4 miles east of Turbot 1.
The well encountered 203 feet of high quality hydrocarbon bearing reservoirs, of which approximately 102 feet was oil bearing.
These discoveries further underpin future developments and contributed to the increase of estimated gross discovered recoverable resources on the Stabroek Block to approximately 10 billion barrels of oil equivalent.
Exploration and appraisal activities in the fourth quarter will include drilling [Indecipherable] exploration well located approximately 11 miles northwest of Liza 1.
This well as a significant step out tests that will target deeper Campanian and Santonian aged reservoirs.
Appraisal activities in the fourth quarter will include drill-stem tests at Longtail 2 and Whiptail 2 as well as drilling the Tripletail 2 well.
In closing, we have once again demonstrated strong execution and delivery and are well positioned to deliver significant value to our shareholders.
In my remarks today, I will compare results from the third quarter of 2021 to the second quarter of 2021.
We had net income of $115 million in the third quarter of 2021, compared with a net loss of $73 million in the second quarter of 2021.
On an adjusted basis, which excludes items affecting comparability of earnings between periods, we had net income of $86 million in the third quarter of 2021, compared to net income of $74 million in the second quarter of 2021.
Third quarter earnings include an after-tax gain of $29 million from the sale of our interest in Denmark.
On an adjusted basis, E&P had net income of $149 million in the third quarter of 2021, compared to net income of $122 million in the previous quarter.
The changes in the after-tax components of adjusted E&P results between the third quarter and second quarter of 2021 were as follows.
Higher realized crude oil NGL and natural gas selling prices increased earnings by $110 million.
Lower sales volumes reduced earnings by $147 million.
Lower DD&A expense increased earnings by $37 million.
Lower cash costs increased earnings by $14 million.
Lower exploration expenses increased earnings by $10 million.
All other items increased earnings by $3 million.
For an overall increase in third quarter earnings of $27 million.
Sales volumes in the third quarter were lower than the second quarter, primarily due to hurricane-related downtime in the Gulf of Mexico, planned maintenance downtime and lower nominations in Malaysia and lower sales in the Bakken, resulting from the planned Tioga gas plant maintenance turnaround.
In Guyana, we sold three 1 million barrel cargoes of oil in the third quarter, up from two 1 million barrel cargoes of oil sold in the second quarter.
For the third quarter, our E&P sales volumes were under lifted compared with production by approximately 175,000 barrels, which had an insignificant impact on our after-tax results for the quarter.
The Midstream segment had net income of $61 million in the third quarter of 2021, compared with $76 million in the prior quarter.
Third quarter results included costs related to the Tioga Gas Plant maintenance turnaround that was safely and successfully completed.
Midstream EBITDA before noncontrolling interest amounted to $203 million in the third quarter of 2021, compared with $229 million in the previous quarter.
Turning to our financial position at quarter-end excluding Midstream, cash and cash equivalents were $2.41 billion and total liquidity was $6 billion, including available committed credit facilities, while debt and finance lease obligations totaled $6.1 billion.
During the third quarter, we received net proceeds of $375 million from the sale of $15.6 million Hess-owned Class B units of Hess Midstream and proceeds of approximately $130 million from the sale of our interest in Denmark.
In July, we prepaid $500 million of our $1 billion term loan and we plan to repay the remaining $500 million in 2022.
In October, we received net proceeds of approximately $108 million from the public offering of 4.3 million Hess-owned Class A shares of Hess Midstream.
Our ownership in Hess Midstream on a consolidated basis is approximately 44% compared with 46% prior to these two recent transactions.
In the third quarter, net cash provided by operating activities before changes in working capital was $631 million, compared with $659 million in the second quarter.
In the third quarter, net cash provided by operating activities after changes in operating assets and liabilities was $615 million, compared with $785 million in the second quarter.
Changes in operating assets and liabilities during the third quarter decreased.
Net cash provided by operating activities by $16 million compared with an increase of $126 million in the second quarter.
Now turning to guidance.
First for E&P, our E&P cash costs were $12.76 per barrel of oil equivalent including Libya and $13.45 per barrel of oil equivalent excluding Libya in the third quarter of 2021.
We project E&P cash cost excluding Libya to be in the range of $12 to $12.50 per barrel of oil equivalent for the fourth quarter and $11.75 to $12 per barrel of oil equivalent for the full year, compared to previous full year guidance of $11 to $12 per barrel of oil equivalent.
The updated guidance reflects the impact of higher realized selling prices in 2021, which significantly improved cash flow, but reduced volumes received under percentage of proceeds contracts and increased production taxes in the Bakken.
DD&A expense was $11.77 per barrel of oil equivalent including Libya and $12.38 per barrel of oil equivalent excluding Libya in the third 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 fourth quarter and the full year is expected to be in the range of $12.50 to $13 per barrel of oil equivalent.
This results in projected total E&P unit operating costs excluding Libya to be in the range of $25 to $26 per barrel of oil equivalent for the fourth quarter and $24.25 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 $50 million to $55 million in the fourth quarter and approximately $160 million for the full year, which is at the lower end of our previous full year guidance of $160 million to $170 million.
The Midstream tariff is projected to be approximately $295 million for the fourth quarter and approximately $1.95 billion for the full year.
E&P income tax expense excluding Libya is expected to be in the range of $35 million to $40 million for the fourth quarter and the full year is expected to be in the range of $135 to $140 million, which is up from previous guidance of $125 million to $135 million, reflecting higher commodity prices.
We expect non-cash option premium amortization will be approximately $65 million for the fourth quarter.
For the year 2022, we have purchased WTI collars for 90,000 barrels of oil per day with the floor price of $60 per barrel and a ceiling price of $90 per barrel.
We have also entered into Brent collars for 60,000 barrels of oil per day with a floor price of $65 per barrel and a ceiling price of $95 per barrel.
The cost of this 2022 hedge program is $161 million, which will be amortized ratably over 2022.
During the fourth quarter, we expect to sell two 1 million barrel cargoes of oil from Guyana.
Our E&P capital and exploratory expenditures are expected to be approximately $650 million in the fourth quarter.
Full year guidance remains unchanged at approximately $1.9 billion.
For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be approximately $70 million for the fourth quarter and the full year is projected to be approximately $280 million, which is at the midpoint of our previous guidance of $275 million to $285 million.
Turning to corporate, corporate expenses are estimated to be in the range of $30 million to $35 million for the fourth quarter and the full year is expected to be in the range of $125 million to $130 million, which is down from our previous guidance of $130 million to $140 million.
Interest expense is estimated to be in the range of $90 millon to $95 million for the fourth quarter and the full year is expected to be in the range of $375 million to $380 million, compared to our previous guidance of approximately $380 million.
This concludes my remarks.
We will be happy to answer any questions.

user
q3 net profit 115 million usd versus -243 million usd loss year ago.
net production, excluding libya, was 265,000 boepd in q3 of 2021, compared with 321,000 boepd in q3 of 2020.
qtrly net production from bakken was 148,000 boepd compared with 198,000 boepd in prior-year quarter.
qtrly net production from gulf of mexico was 32,000 boepd, compared with 49,000 boepd in prior-year quarter.
q3 2021 e&p results include a pre-tax gain of $29 million associated with sale of corporation's interests in denmark.
on an adjusted basis, corporation reported net income of $86 million, or $0.28 per common share, in q3 of 2021.

assistant