Shale Companies Prepare For Their Best Quarter Ever
After a decade of losses and shareholder frustration, the U.S. shale patch is generating record amounts of cash flows and is earning record profits this year as oil prices soar while firms prioritize returns to investors. The public independent U.S. shale producers already had a blockbuster first quarter, with many generating record cash flows and profits and vowing to increase shareholder returns after years of corporate losses and little payback to investors. Moreover, analysts say the second quarter will be even better for the shale patch. The first earnings results announced at the end of last week and earlier this week suggest that Q2 will be the best quarter for shale profits ever. Independent producers are joining Big Oil—including U.S. supermajors ExxonMobil and Chevron—in reporting all-time high earnings and boosting payouts to shareholders through higher dividends and stepped-up share buybacks. The record cash flows and profits are unlikely to go unnoticed by the Biden Administration, which has been chastising domestic oil producers for rewarding shareholders instead of “lowering the costs at the pump for Americans.” Phenomenal Cash Flows Combined free cash flow at the top 28 independent U.S. oil producers is set to exceed $25 billion for the second quarter, estimates compiled by Bloomberg showed at the start of the shale earnings season. Free cash flow is set to be over $100 billion for the full-year 2022, more than double the FCF the shale patch generated last year. This year’s projected FCF will also be nine times higher than the combined annual cash flows between 2018 and 2020, per Bloomberg Intelligence data. “Even if the cost structure is trending higher, the amount of free cash flow generated will be phenomenal,” Paul Cheng, a New York-based analyst at Scotiabank, told Bloomberg. Production in the U.S. shale patch is also growing, but at a slower pace than in the 2018-2019 run-up to the pandemic. That’s due not only to spending discipline where firms prefer to trim debt and repay shareholders instead of growing production at all costs, as they did for nearly a decade before COVID created a new crisis and a new reality. Galloping costs, sold-out fracking equipment and crews, and supply-chain delays and bottlenecks are also reasons for slower U.S. shale production growth this year despite $100 a barrel oil. The latest Dallas Fed Energy Survey showed that the business activity index in the energy firms operating in Texas, northern Louisiana, and southern New Mexico jumped in the second quarter to the highest level in six years, but costs continued to escalate, and supply chain delays were worsening. Shale firms note that there is intense inflationary pressure on costs amid supply chain bottlenecks, high inflation, and growing wages in a tight market for skilled workers. “Those Returns Are Fantastic” Yet, some companies say that in terms of returns, the high oil prices more than offset inflation. “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,” Hess Corporation’s chief operating officer Greg Hill said on the company’s earnings call last week. “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,” Hill added. Hess Corp’s core shale operations in the Bakken are generating significant amounts of cash flow these days, the executive said. At $60 oil, the Bakken generates more than $1 billion of free cash flow for Hess, Hill said, noting that with current much higher oil prices, the company’s position in the North Dakota basin “becomes this massive cash annuity for the portfolio.” This week, Devon Energy and Diamondback Energy both reported on Monday solid Q2 earnings and increased returns to shareholders. Devon Energy raised its fixed-plus-variable dividend to $1.55 per share, up by 22 percent from the previous quarter, and raised its full-year 2022 production forecast by 3 percent to a range of 600,000 – 610,000 Boe per day due to “better-than-expected well performance year-to-date and the impact from a bolt-on acquisition in the Williston Basin.” The company raised its upstream capital guidance to a range of $2.2 billion to $2.4 billion for 2022, up from $2.1 billion, and expects its capital to be fully funded from operating cash flow, which is expected at nearly $9 billion at current strip pricing. Diamondback, for its part, generated a record $1.3 billion in free cash flow for Q2, exceeding last quarter’s prior FCF record by 35%. The Board approved a $2-billion increase to Diamondback’s share repurchase authorization to $4.0 billion. “Beginning this quarter, we have committed to return a minimum of 75% of our Free Cash Flow to stockholders,” chairman and CEO Travis Stice said. U.S. shale firms are finally reaping the benefits of triple-digit oil prices as they continue to prioritize returns to shareholders and reduction of debts to going into more debt in order to post production records.
Several refining projects are scheduled in Asia and the Middle East
In Asia and the Middle East, at least nine refinery projects are beginning operations or are scheduled to come online before the end of 2023. At their current planned capacities, they will add 2.9 million barrels per day (b/d) of global refinery capacity once fully operational. In the International Energy Agency’s (IEA) June 2022 Oil Market Report, the IEA expects net global refining capacity to expand by 1.0 million b/d in 2022 and by an additional 1.6 million b/d in 2023. Net capacity additions reflect total new capacity minus capacity that has closed. The scheduled expansions follow a period of reduced global refining capacity. Net global capacity declined in 2021 for the first time in 30 years, according to the IEA. The new refinery projects would increase production of refined products, such as gasoline and diesel, and in turn, they might reduce the current high prices for these products. China’s refinery capacity is scheduled to increase significantly this year. The Shenghong Petrochemical facility in Lianyungang has an estimated capacity of 320,000 b/d, and they report that trial crude oil-processing operations began in May 2022. In addition, PetroChina’s 400,000 b/d Jieyang refinery is expected to come online in the third quarter of 2022. A planned 400,000 b/d Phase II capacity expansion also began operations earlier this year at Zhejiang Petrochemical Corporation’s (ZPC) Rongsheng facility. Outside of China, the 300,000 b/d Malaysian Pengerang refinery (also known as the RAPID refinery) restarted in May 2022 after a fire forced the refinery to shut down in March 2020. In India, the Visakha Refinery is undergoing a major expansion, scheduled to add 135,000 b/d by 2023. New projects in the Middle East are also likely to be an important source of new refining capacity. The 400,000 b/d Jizan refinery in Saudi Arabia reportedly came online in late 2021 and began exporting petroleum products earlier this year. More recently, the 615,000 b/d Al Zour refinery in Kuwait—the largest in the country when it becomes fully operational—began initial operations earlier this year. A new 140,000 b/d refinery is scheduled to come online in Karbala, Iraq, this September, targeting fully operational status by 2023. A new 230,000 b/d refinery is set to come online in Duqm, Oman, likely in early 2023. These estimates do not necessarily include all ongoing refinery capacity expansions. Moreover, many of these projects have already been subject to major delays, and the possibility of partial starts or continued delays related to logistics, construction, labor, finances, political complications, or other factors may cause these projects to come online later than estimated. Although the potential for project complications and cancellations is always a significant risk, these projects could otherwise account for an increase of nearly 3.0 million b/d of new refining capacity by the end of 2023.
Russian state-energy giant Gazprom saw its natural-gas production in July slump to its lowest level since 2008
Russian state-energy giant Gazprom saw its daily natural-gas production slump to its lowest level since 2008, according to a Bloomberg calculation published on Monday. The fall in output came as Russia slowed gas flows to Europe, citing technical challenges arising from sanctions over the Ukraine war. Gazprom’s production in July was 774 million cubic meters a day — 14% lower than in June, according to Bloomberg calculations. The company’s production this year-to-date is 12% lower than the same period in 2021. Overall, Gazprom’s July exports to countries outside the former Soviet Union dropped about a quarter from June, even as daily supply to China increased steadily, per Bloomberg. Europe depends on Russia for 40% of its natural-gas needs, such as cooking in homes and firing up power stations. As Russia is a major natural-gas supplier to Europe, the natural-gas crunch has sent prices soaring this year, in turn supporting the Kremlin’s coffers. Since it invaded Ukraine on February 24, Russia’s revenue from oil and gas exports to Europe have more than doubled compared to the average in recent years, the International Energy Agency wrote on July 18. While the upcoming winter will be challenging for Europe, it’s the Russian economy that stands to be “hurt the most” in the long run by the shifting natural-gas supply chains, a Yale University analysis found. That’s because “the importance of commodity exports to Russia far exceeds the importance of Russian commodity exports to the rest of the world,” the Yale researchers wrote in the analysis, released July 20. The European Union has agreed to end almost all its oil imports from Russia by the end of this year and has said it will cut coal imports starting in mid-August. European countries including Germany and Italy are also working to wean themselves off Russian gas. To mitigate the impact from lower energy sales to Europe, Russian President Vladimir Putin is hawking Russia’s energy exports to other markets, such as Asia — but at a discount. “It now deals from a position of weakness with the loss of its erstwhile main markets,” the Yale team wrote, adding that Russia’s strategic position as a commodities exporter had “irrevocably deteriorated.”
IndianOil Targets Green Hydrogen Meeting 10% Of Requirements By 2030
To start with, the nation’s largest oil firm is setting up green hydrogen plants at its Panipat and Mathura refineries, IOC said in its latest annual report Indian Oil Corporation (IOC) is targeting to replace at least a tenth of its current fossil-fuel-based hydrogen at its refineries with carbon-free green hydrogen as part of a decarbonization drive. To start with, the nation’s largest oil firm is setting up green hydrogen plants at its Panipat and Mathura refineries, IOC said in its latest annual report. “The company is venturing into green hydrogen production and is targeting 5 per cent of hydrogen produced by it as green hydrogen by 2027-28 and 10 per cent by 2029-30,” it said. Hydrogen is the cleanest known energy source but it barely exists in a pure form on Earth. It either is bounded with oxygen in water or with carbon to form hydrocarbons like fossil fuels. Once separated from other elements, hydrogen’s utility increases: it can be converted into electricity through fuel cells, it can be combusted to produce heat or power without emitting carbon dioxide, used as a chemical feedstock, or as a reducing agent to reduce iron ores to pure iron for steel production. Most of the hydrogen currently produced is grey which is produced from fossil fuel and as carbon emissions. Green hydrogen is produced using electrolysis powered by renewable energy to split water molecules into oxygen and hydrogen, creating an emissions-free fuel. As part of its decarbonisation drive, IOC is looking to replace hydrogen made by unabated fossil fuels with green hydrogen. Petroleum refining accounts for almost 42 per cent of total global hydrogen demand. “At present, the refineries are the major consumption centres for hydrogen, used for desulfurisation. The current dominant hydrogen production process is highly carbon-intensive being based on the Steam Methane Reforming process. “On the other hand, green hydrogen i.e. hydrogen produced from electrolysis of water, using renewable energy, has a zero-carbon profile, making it the preferred form of hydrogen in the context of a carbon neutral future,” IOC said. In the annual report, IOC Chairman Shrikant Madhav Vaidya said to meet the net-zero commitment, the Indian government has announced the Green Hydrogen and Ammonia Policy to boost green hydrogen production to 5 million tonne by 2030 and make India an export hub for this clean fuel. “Aligning with the national priority, Indian Oil will be producing green hydrogen in stages at the Mathura and Panipat refineries. As a first step, we will be implementing a 5 KTA (40 MW) green hydrogen plant at Mathura Refinery and a 2 KTA (16 MW) plant at Panipat Refinery,” he said. To sync with the entire hydrogen value chain, the firm has forged crucial collaborations to develop green hydrogen production assets, associated renewable assets and manufacture electrolysers. “This will be a gamechanger as electrolysers contribute to approximately 30 per cent of the overall cost of green hydrogen,” he said. IOC, he said, is also exploring multiple hydrogen production pathways, including solar electrolysis, biomass gasification and bio-methanation. “The hydrogen produced will be used for fuelling 15 fuel cell buses to establish the efficacy, efficiency and sustainability of the fuel cell technology and hydrogen production processes. In addition, we will commission a hydrogen dispensing station at the Gujarat Refinery to enlarge hydrogen-based mobility coverage,” he said. IOC said it is looking to expand its footprint in the renewable power space from the present level of about 240 MW capacity. While renewable energy plants currently produce electricity equivalent to 5 per cent of its electricity consumption, IOC is targeting nearly 5 GW of renewable electricity generation capacities by 2025 for use at its oil refineries.