U.S. natgas companies put hydrogen to the test
NEW YORK, At least two dozen U.S. energy firms, including Dominion Energy Inc and Sempra Energy , have started producing hydrogen or testing its viability in natural gas pipes to take advantage of existing infrastructure as the world prioritizes lower-carbon fuels. Nations worldwide are trying to reach net-zero carbon emissions by 2050, but that will rely heavily on technology – like hydrogen – that is in developmental stages. Utilities have a potential advantage if they find that clean-burning hydrogen can be successfully transported in existing gas pipes and power plants. But governments need legislation and regulation to encourage energy companies to spend billions in order to reduce production costs for green hydrogen, analysts said, before it can displace fossil fuels. Almost all of the world’s hydrogen production is currently through fossil fuels, and large utilities are currently mostly testing blends of natural gas and hydrogen in their pipelines. The companies experimenting with hydrogen are in early stages. Canada’s Enbridge Inc is blending up to 2per cent hydrogen into its natural gas distribution systems in Ontario, and just received approval to blend hydrogen in Quebec. “We are looking to understand the potential either with the existing system or, as we’re continuing to modernize the gas pipeline system, to ensure that new construction is hydrogen-ready,” said Pete Sheffield, Enbridge’s chief sustainability officer. Sempra’s Southern California Gas (SoCalGas) utility, which supplies gas to 22 million consumers, is working on pilot programs to test the fuel in its pipelines and see how a blend with natural gas affects the company’s pipes, as well as appliances and other equipment. The first project would blend hydrogen in a mostly residential area that SoCalGas can isolate from the rest of its distribution system, said Jawaad Malik, chief environmental officer. Virginia-based Dominion is testing a 5per cent hydrogen blend in a training facility in Utah and recently proposed a similar pilot in North Carolina, said Dominion spokesperson Aaron Ruby. Hydrogen is only considered clean if it is produced using low- or no-carbon emitting energy sources like biomass, nuclear, renewables or fossil fuels paired with carbon capture technology. “These types of proposals have not yet shown a path to a deeply decarbonized gas system,” said Julie McNamara, senior energy analyst for the Union of Concerned Scientists. Almost every gas turbine used to produce power can burn fuels containing about 5per cent to 10per cent hydrogen, said Jeff Goldmeer, General Electric’s emergent technologies director for decarbonization. That would cut carbon dioxide emissions from natural gas from the power sector, which has been one of the fastest growing sources of demand for gas. Roughly 36per cent of energy-related carbon emissions come from fossil fuel-fired electricity generation, according to the International Energy Agency (IEA). A RISE IN PILOT PROGRAMS To reach net-zero emissions by 2050, global hydrogen use needs to expand to more than 200 million tonnes in 2030 from less than 90 million tonnes in 2020, according to the IEA. Reaching that goal will be difficult. Hydrogen production and transport costs more than natural gas, for now. Evercore ISI analysts said in a report this week that green hydrogen could become cost-competitive with less clean versions by 2030. GE has more than 75 turbines worldwide that use or have used fuels containing hydrogen, which have produced more than 450 terawatt-hours (TWh) of power. U.S. utility-scale facilities generated about 4,009 TWh of electricity in 2020, according to U.S. federal data. Technology will have to advance further to burn hydrogen as a viable fuel rather than just as a small percentage of a natural gas blend. “Clean hydrogen will be constrained in supply for the foreseeable future,” said McNamara of the Union of Concerned Scientists. “Blending it at a low level into a gas pipeline that should be transitioned to electrification is just not the right pathway to be taken today.
Green to Greener: GAIL eyes 1 GW renewable energy capacity, to set up biogas, ethanol plants
GAIL (India) Ltd will invest about Rs 5,000 crore to build a portfolio of at least 1 gigawatts of renewable energy and set up compressed biogas as well as ethanol plants as it steps up efforts to expand the business beyond natural gas. As part of a push to embrace cleaner forms of energy, GAIL will be laying pipeline infrastructure to connect consumption centers to gas sources and spend as much as Rs 4,000 crore on renewable energy, GAIL Chairman and Managing Director Manoj Jain said. “We are a business that is already eco-friendly – gas. And now we want to leverage our position to go greener in line with the vision of the government and the Prime Minister to cut carbon emissions and pollution,” he said. While electricity generated from solar energy or through wind power is the cleanest form of energy, converting municipal waste into compressed biogas will supplement the availability of cleaner fuel to automobiles and households. Also, it plans to set up ethanol units that can convert agriculture waste or sugarcane into less polluting fuel that can be doped in petrol, helping cut India’s import dependence, he said. While the renewable energy push would cost Rs 4,000 crore, setting up at least two compressed biogas plants and an ethanol factory would entail an investment of about Rs 800-1,000 crore, he said. India, which imports 85 per cent of its crude oil needs, is stepping up efforts to explore new forms of energy to clean up the skies and reduce dependence on imported fuels. “We have 120 MW of renewable energy capacity which we want to scale up to 1GW in next 3-4 years,” he said. GAIL will bid for a 400 MW solar power capacity being auctioned by SECI (formerly Solar Energy Corporation of India) in Rewa, Madhya Pradesh. The company had in 2019, won a bid for 874 MW operational wind power projects of IL&FS for Rs 4,800 crore. But IL&FS’ other partners used the first right of refusal to block GAIL’s bid, he said. “We are open to acquisitions and will look at any asset that makes commercial sense. We had almost got the IL&FS project,” he said. GAIL has signed up with state-run power gear maker BHEL for renewable energy foray. The tie-up looks to leverage the competitive strengths of both companies. GAIL will be the project developer and BHEL will be a project manager and EPC (engineering, procurement and construction) contractor. Jain said GAIL is setting up its first compressed biogas (CBG) plant in Ranchi at a cost of Rs 200-300 crore. The facility will produce five tonnes of CBG per day and approximately 25 tonnes of bio-manure using municipal waste. “The gas produced will be fed into the city gas network supplying CNG to automobiles and piped natural gas to households. This will help reduce pollution,” he said. GAIL has floated an expression of interest (EoI) seeking partners for the setting up of CBG plants. It also plans to set up an ethanol manufacturing unit, he said. The move by GAIL, which commands a 75 per cent market share in gas transmission and more than 50 per cent share in gas trading in India, is seen as part of the government’s vision to prepare for the energy transition process, under which the share of gas in the energy mix is sought to be raised to 15 per cent by 2030, from the current 6.2 per cent. GAIL recently signed an agreement with Carbon Clean Solutions Ltd. Under this, CCSL will initially build four CBG plants using its own funding, technology, and expertise. These plants will be based on 10-year CBG offtake agreements with GAIL or its associated companies. Depending on the success, the partnership will be scaled up to many more such plants. GAIL owns and operates a network of 13,340 km of high-pressure trunk pipelines. In addition, it is working on multiple pipeline projects, aggregating over 7,500 km. It owns a petrochemical plant at Pata in Uttar Pradesh and is setting up a new one in Maharashtra .
Govt issues draft notification on ethanol blending in petrol
Paving the way for the transformation of the fossil fuel ecosystem in the country, the Ministry of Road Transport and Highways has issued a draft notification for facilitating use of a blend of 12 per cent and 15 per cent ethanol in gasoline as automotive fuels. Comments have been invited from stakeholders within a period of 30 days. “The newly manufactured gasoline vehicles fitted with spark ignition engine compatible to run on ethanol gasoline blends of E-12 and E-15 shall be type approved as per prevailing gasoline emission norms,” the draft notification said, Recently, Road Transport and Highways Minister Nitin Gadkari had said the government will take a decision over flex-fuel engines as it is considering making these mandatory for the automobile industry. “…I am going to issue an order to the industry that only petrol engines will not be there, there will be flex-fuel engines, where there will be choice for the people that they can use 100 per cent crude oil or 100 per cent ethanol,” he had said. “I am going to take a decision within 8-10 days and we will make it (flex-fuel engine) mandatory for the automobile industry,” he had further said. Gadkari had mentioned that automobile makers are producing flex-fuel engines in Brazil, Canada and the US providing an alternative to customers to use 100 per cent petrol or 100 per cent bio-ethanol. Recently, Prime Minister Narendra Modi said the target date for achieving 20 per cent ethanol-blending with petrol has been advanced by five years to 2025 to cut pollution and reduce import dependence. The government last year had set a target of reaching 10 per cent ethanol blending in petrol by 2022 and 20 per cent doping by 2030. Gadkari had said ethanol is a better fuel than petrol, and it is an import substitute, cost effective, pollution-free and indigenous. “It (making flex-fuel engines mandatory) is going to boost the Indian economy because we are a corn surplus, we are a sugar surplus, and a wheat surplus country. We don’t have places to stock all these foodgrains,” he had noted.
Soaring pump prices a threat to India’s recovery and inflation
Indian pump prices are in unchartered territory as ever-increasing government levies coincide with crude’s recovery from the depths of the Covid-19 pandemic. Fuel costs have been ratcheted up to current levels by the combined effects of rising benchmark Brent prices and numerous tax hikes over the past few years. The record-high gasoline and diesel prices are leaving some Indian car owners unable to afford the cost of using their vehicles and spurring the country’s transport industry to agitate for change. Buying gasoline in major Indian cities such as Mumbai costs almost twice as much as in New York, casting a shadow on the recovery across Asia’s second-largest oil guzzler as virus-related movement restrictions are eased. The federal government kept upping taxes last year even as it put the country into a national lockdown and global crude prices collapsed. Mumbai gasoline costs have risen by more than 25per cent over the past three years, while diesel prices have climbed by a third over the same period, according to data from Indian Oil Corp. The run-up in prices is adding to inflationary pressures to the Indian economy amid a broad commodity rally. Biggest Drivers In India’s capital of New Delhi, gasoline prices have jumped almost 20per cent year-to-date, alongside a similar surge in diesel costs. Federal taxes on gasoline, which powers scooters and motorcycles, have more than tripled over the last seven years. Those on diesel, the country’s most-used fuel, have swelled by seven times over the same period. Higher prices are hitting the country’s burgeoning middle class, the engine that’s driven India’s economic and oil demand growth in recent times. Rahul Srivastava, a 48-year-old former executive at an advertising agency in New Delhi, upgraded to a shiny new sedan just a month before the country went into a nationwide lockdown last year. Now he’s considering selling his vehicle. “Driving the car is now a luxury for me,” said Srivastava, who turned to stock trading after losing his job and is now making about a fifth of what he used to. “Earlier, I would tank up whenever I needed to refill and it would cost me 3,000 rupees ($40). Last time, refilling less than half the car’s tank cost me more than $25. I now drive only when it’s absolutely necessary.” Unfortunately for Srivastava, truck drivers, and millions of others, India’s budget deficit ballooned to a record last year, and fuel taxes represent a reliable source of income that’s been hard for the government to ignore. The taxes are eroding disposable incomes and feeding inflationary pressures, according to ICRA Ltd., the local unit of Moody’s Investors Service. “Definitely, the high prices will have an impact on the growth and return to normalcy,” said Prashant Vasisht, Vice President at ICRA. “Prices above a particular level do pinch and people travel less and try to save on the fuel cost.” Demand Impact While India’s economy is now grinding its way back from a 7.3per cent contraction in gross domestic product in the year to March, millions remain under pressure. Unemployment is still rising, and the Pew Research Center estimates the nation’s middle class shrank by 32 million people in 2020. “High prices do have an impact on fuel demand,” said Senthil Kumaran, head of South Asia oil at FGE. “But, at this point the price effect will be less significant as the country is still coming out of the second-wave lockdowns. Pent-up demand will outshine high retail prices, so, it won’t pause the demand recovery. But if high prices continue through July, then it will impact more.” With fuel prices soaring, India’s truckers have had enough. Drivers have limited ability to pass on the rising prices, which account for about 70per cent of the cost of operating a truck, according to the All India Motor Transport Congress, which represents more than 14 million truckers and bus and tourist vehicle operators. “The record high diesel and gasoline rates have impacted the livelihoods of millions of small transport operators and wage earners, who are struggling to make ends meet,” said Kultaran Singh Atwal, president of AIMTC. The group plans to go on a nationwide protest this week, and follow that with a general strike if the government doesn’t reduce fuel prices, he said.
Pradhan puts ONGC, OIL on notice: perform or get shipped out
Petroleum Minister Dharmendra Pradhan on Tuesday put state-owned ONGC and OIL on notice saying oil and gas reserves they hold need to be monetised through joint ventures with domain experts or the government will take them away and auction them. Speaking at BNEF Summit, he said state-owned firms cannot indefinitely sit on resources when the nation is a net importer of oil and gas. Despite India bidding out acreages to private and other companies since the 1990s, Oil and Natural Gas Corporation (ONGC) and Oil India Ltd (OIL) hold a “sizeable number of acreage for years,” he said. “We have asked them to do two things – do it yourself, (produce oil and gas) through some joint venture (with domain experts and foreign companies) (and) through a new business model. But the government cannot permit you to hold resources for an indefinite time,” he said. ONGC and OIL, which discovered and brought to production all of India’s eight sedimentary basins, produce about three-fourths of the nation’s oil and gas. The two, especially ONGC, have faced criticism ranging from not being able to quickly bring discoveries to production to lower recovery. Pradhan said India needs energy for its ambitious economic growth agenda. “We want to reduce import dependency. We want to monetise our own resources.” “So we have given policy guidance to our state-owned oil companies – either you do on your own through new partners and new economic model, (else) the government will after a particular period intervene and use its authority to bid out the resources,” he said. The government has already taken away dozens of small and marginal discoveries from the two firms and auctioned them in what is known as Discovered Small Field (DSF) rounds. DSF offers pricing and marketing freedom to operators, something which ONGC and OIL do not have currently, constraining their efforts to monetise smaller discoveries. But now Pradhan has indicated the government would not hesitate to take away larger idle discoveries and auction them to private and foreign players. Earlier this month, the minister had stated that the Directorate General of Hydrocarbons (DGH), the oil ministry’s technical arm, had the “full mandate” to identify unmonetised major fields that could be offered for bidding. “Resources don’t belong to a company. They belong to the nation and the government. They cannot lie with a company indefinitely. If somebody cannot monetise them, we will have to bring a new regime,” he had said on June 10. The statement comes weeks after his ministry told ONGC to sell a stake in producing oil fields such as Ratna R-Series in western offshore to private firms and get foreign partners in KG basin gas fields. had on April 25 reported a seven-point action plan, ‘ONGC Way Forward’. It was drawn by the ministry that called for the firm to consider a sale of a stake in maturing fields such as Panna-Mukta and Ratna and R-Series in western offshore and onshore fields like Gandhar in Gujarat to private firms while divesting/privatizing ‘non-performing’ marginal fields. It wanted ONGC to bring in global players in gas-rich KG-DWN-98/2 block where output is slated to rise sharply next year, and the recently brought into production Ashokenagar block in West Bengal. Also, identified for the purpose is the Deendayal block in the KG basin which the firm had bought from Gujarat government company GSPC a couple of years back. This proposal is the third attempt by the oil ministry to get ONGC to privatise its oil and gas fields. In October 2017, the DGH had identified 15 producing fields with a collective reserve of 791.2 million tonnes of crude oil and 333.46 billion cubic meters of gas, for handing over to private firms in the hope that they would improve upon the baseline estimate and its extraction. A year later, as many as 149 small and marginal fields of ONGC were identified for private and foreign companies on the grounds that the state-owned firm should focus only on bid ones. The first plan could not go through because of strong opposition from ONGC, sources aware of the matter said. The second plan went up to the Cabinet, which on February 19, 2019, decided to bid out 64 marginal fields of ONGC. But that tender got a tepid response, they said. The sources added that ONGC was allowed to retain 49 fields on the condition that their performance will be strictly monitored for three years. ONGC produced 20.2 million tonnes of crude oil in the fiscal year ending March 31 (2020-21), down from 20.6 million tonnes in the previous year and 21.1 million tonnes in 2018-19. It produced 21.87 billion cubic meters of gas in 2020-21, down from 23.74 bcm in the previous year and 24.67 bcm in 2018-19.
Rs 1.75 lakh crore disinvestment target on track: Chief Economic Advisor
The target of mopping up Rs 1.75 lakh crore from disinvestments of some of the public sector companies, including LIC and BPCL during the current fiscal, is on track and groundwork is being prepared for the goal, Chief Economic Advisor Krishnamurthy Subramanian said on Monday. On the COVID-19 pandemic, Subramanian said the impact of the second wave is lesser than that of the first one. In an interactive session, organised by Federation of Telangana Chambers of Commerce and Industry, the CEA said robust GST collections, over Rs one lakh crore per month for eight months in a row shows that consumption is picking up indicating positive signal for growth. “There has to be a lot of work which is going on and this year there is actually a lot of emphasis on achieving these targets. Remember that Rs 1.75 lakh crore, a good part of it will be from LIC’s IPO (Initial Public Offering).Second is Bharat Petroleum (BPCL) privatisation. And these two together itself can account for a large part of (disinvestment target),” he said. The Centre budgeted Rs 1.75 lakh crore from stake sale in public sector companies and financial institutions, including 2 PSU banks and one insurance company, in the current fiscal year. The disinvestment plan includes strategic sale of IDBI Bank, BPCL, Shipping Corp, Container Corporation, Neelachal Ispat Nigam Ltd, among others, and also legislative amendments required for LIC IPO would be brought in 2021-22, Finance Minister Nirmala Sitharaman had said in her budget speech. “I think this year very likely will be the year of which will be remembered for privatisation. We still have nine more months. I am quite confident that we will achieve the target (of Rs 1.75 lakh crore ),” the CEA said replying to a query. Earlier in his speech, he said every rupee spent by governments on “freebees” would contribute only Rs 0.98 to the country’s economy against Rs 4.50 when used on capital expenditure.
To fulfil Oil Ministry’s grand vision, ONGC must take a slick new avatar
The Ministry of Petroleum & Natural Gas would like the public sector energy giant ONGC to reassess its role with an ultimate aim of becoming a resource owner, functioning like a holding company. ONGC should focus on strategising, exploring and developing India’s energy space while monetising and divesting its resources and generating funds to reinvest, according to the Ministry. It wants ONGC to adopt a new business model by divesting non-core activities such as drilling, logging and field services to separate domain companies. ONGC’s performance as an oil and gas explorer has been reviewed by the Ministry on a regular basis for some time now. “In global post Covid-19 recovery phase, India is one of the most promising developing economies with a high growth potential and ONGC should take advantage of this opportunity,” an official involved with the process told BusinessLine. Clean energy “While developed countries may switch to renewables and other cleaner energy sources due to climate concerns, India still needs fossil fuels to meet its growing energy requirements. There is an urgent need to aggressively explore unappraised/unexplored sedimentary hydrocarbon areas in the next three years. Given the expected spurt in economic growth post Covid-19 recovery, there is high potential to attract investment, talent and resources in India,” the official added. Today, almost 80 per cent of India’s crude oil requirement are met through imports. Minister for Petroleum and Natural Gas Dharmendra Pradhan has been raising concerns at global platforms about the spike in global oil crude prices. In fact, on June 24, at a high level consultation meeting with OPEC Secretary General Mohammed Sanusi Barkindo, Pradhan flagged the rising crude oil prices and its impact on consumers and economic recovery. He emphasised that high crude prices are exerting significant inflationary pressure. “ONGC, being the flagship central public sector enterprise, has grown up manifold and has resources, (but) it has not explored aggressively. Further, the engagement of ONGC on a large number of small fields has reduced its flexibility and project implementation capability. Today 80 per cent of ONGC’s production comes from only 24 fields, while remaining 190 fields contribute only 20 per cent,” he said. An official added: “It is time ONGC refocussed on core activity by acquiring more data and explore more. It should also monetise the resources/facilities and generate funds. The company should de-risk itself by inviting partners and move to new areas for exploration and business. Basically, it should first consolidate activities geographically/basin wise to achieve speed, efficiency and cost effectiveness.” New business models There is a need to develop new business models for monetisation of stranded assets/discoveries/spare facilities. Business models such as Design, Finance, Built and Operate as well as Annuity & Securitisation based models for development are to be explored, the official added. “ONGC should now take the role of nurturing, handholding and expanding exploration and production activities in India by bringing small and medium-sized companies. This can be done by having partnership (technology/ finance/ consultancy/project execution/ management) with global players for difficult plays (HP-HT, ultra-deepwater exploration areas), new basinal areas (Gujarat Kutch, Bengal Basin) and for enhancing production from existing major fields,” the official explained.
Norway’s Equinor aims to triple UK hydrogen production capacity
Norwegian oil and gas firm Equinor said on Tuesday it had raised its hydrogen production goal in the United Kingdom to 1.8 gigawatts (GW), following a visit of Britain’s Business Secretary Kwasi Kwarteng to Oslo. Equinor said it planned to add 1.2 GW of low-carbon hydrogen production capacity mainly to supply Keadby Hydrogen, the world’s first major 100% hydrogen-fired power plant it is developing jointly with British utility SSE. Pending support from the British government, the plant could start operations before the end of the decade, it added. Equinor’s Chief Executive Anders Opedal, who took part in a meeting with Kwarteng and Norway’s Oil and Energy Minister Tina Bru, said its projects would help the UK achieve its climate goals. “Our low-carbon projects in the UK build on our own industrial experience and will play a major role in setting the UK’s industrial heartlands in a leading position,” Opedal said in a statement. Britain has a target to reach net-zero carbon emissions by 2050 and 5 GW of clean hydrogen capacity by 2030, and is providing financial support to a number of decarbonisation projects. Equinor is already planning to build a 0.6 GW capacity plant in north-eastern England to produce so-called “blue” hydrogen from natural gas, while capturing associated carbon dioxide (CO2) emissions. It is also involved in a project to develop CO2 transport and storage infrastructure in the region. Clean hydrogen, produced from water by using renewable electricity or from natural gas in combination with carbon capture and storage (CCS), is seen vital to decarbonise industries such as steel and chemicals. Today most hydrogen is produced from natural gas, while associated CO2 emissions are released into the atmosphere.
Crude oil price drifts near 2018 highs ahead of OPEC+ meeting
Oil prices hit and then recoiled from highs last seen in October 2018 on Monday as investors eyed the outcome of this week’s OPEC+ meeting as the United States and Iran wrangle over the revival of a nuclear deal, delaying a surge in Iranian oil exports. Brent crude for August had slipped 1 cent to $76.17 a barrel by 0619 GMT while U.S. West Texas Intermediate crude for August was at $74.09 a barrel, up 4 cents. Oil prices rose for a fifth week last week as fuel demand rebounded on strong economic growth and increased travel during summer in the northern hemisphere, while global crude supplies stayed snug as the Organization of the Petroleum Exporting Countries (OPEC) and their allies maintained production cuts. The producer group, known as OPEC+, is returning 2.1 million barrels per day (bpd) to the market from May through July as part of a plan to gradually unwind last year’s record oil output curbs. OPEC+ meets on July 1 and could further ease supply cuts in August as oil prices rise on demand recovery. “Demand recovery has caught everyone by surprise and OPEC needs to respond,” Howie Lee, economist at Singapore’s OCBC bank, said. “There is some leeway for easing supply curbs given how high prices are, and we might see a 250,000 bpd increase from August.” ANZ and ING expect OPEC+ to increase output by about 500,000 bpd in August, which is likely to support higher prices. “Anything less than this amount would likely be enough to see bulls push the market higher in the near term,” ING analysts said in a note. One Singapore-based oil analyst said oil prices are unlikely to see a big correction unless OPEC+ increase supplies by 1 million bpd or more. Negotiations over the revival of Iran’s nuclear deal are expected to resume in coming days. A monitoring agreement between Tehran and the U.N. nuclear watchdog lapsed last week. A weaker U.S. dollar and a reversal of risk appetite in global markets also supported dollar-denominated commodity prices. The United States added 13 oil and gas rigs in June, up for an 11th month in a row along with higher oil prices, although it was the smallest monthly increase since September 2020, Baker Hughes data showed on Friday.
U.S. shale industry tempers output even as crude oil price jumps
Even with oil prices surging toward $75 a barrel, U.S. shale producers are keeping their pledges to hold the line on spending and keep output flat, a departure from previous boom cycles. This year’s run up in crude prices, and oil output curbs imposed by the OPEC+ producers group, historically would have triggered a drilling boom. But investors are demanding financial returns over more volume and energy financiers are shifting to renewables, so shale firms are determined to stay disciplined. “I’m still confident the producers will not respond” to the run-up in prices, said Scott Sheffield, chief executive of Pioneer Natural Resources, the largest producer in the Permian Basin shale field. A focus on shareholder returns has kept spending low, he said in an interview with Reuters. Last week, benchmark U.S. crude futures traded above $73 a barrel, the highest since October 2018. Back then there were 1,052 U.S. rigs drilling https://graphics.reuters.com/USA-OIL/ENERGY/nmovaxkjepa but today there are much less than half that many: around 470, according to Baker Hughes data. Shale output remains well below the January 2020 peak of 9.18 million barrels per day (mbpd), with production from the seven largest fields this month running 7.77 mbpd, or 15.4% below that level, according to U.S. government data. Overall U.S. first-quarter oil production averaged 83% of last year’s peak. The U.S. recently raised its 2021 average production outlook to 11.08 mbpd due to higher crude prices, but it remains about 200,000 bpd below last year’s average. “Oil prices will probably break $80 a barrel here shortly and I don’t see any rig adds,” Sheffield said. A spike in oilfield activity could drive up service prices, which are already up about 6%. Pioneer may reduce its active rigs as its operations have become more efficient, he said. OPEC EASING CUTS Shale’s restraint is key to OPEC’s next step. The oil producers’ group has gradually added more production, confident U.S. shale will not return to an era of explosive growth. It will meet Thursday and consider furthering unwinding cuts from August. “So far, activity levels support the capital discipline narrative,” said Jonathan Godwin, a senior associate at data provider Enverus. Frack fleet activity has held steady since jumping 20% at the start of the year, he said. In the United States, closely held companies have contributed substantially to rig additions this year, but Sheffield said those smaller firms should not drive up volumes enough to ruffle OPEC+ producers. “The quality of the acreage for privates is not as good as the publics,” Sheffield said, estimating private companies account for 40% to 50% of U.S. rig count. “We’re not seeing the upward pressure we would normally have predicted based on $73 oil,” said Paul Mosvold, president and COO of driller Scandrill, which operates super-spec drilling rigs, equipment in high demand since the oil market recovered. Mosvold reported a slight uptick in calls as oil prices have climbed, but said they are “not substantial.”