Could Iraq Dethrone Saudi Arabia As Largest Oil Producer?
Iraq’s Oil Minister, Ihsan Abdul-Jabbar, last week stated that the country aims to increase its crude oil production to 6 million barrels per day (bpd) by the end of 2027. This sort of statement, with the amount or year changed slightly in each variant, has been made by several oil ministers on several occasions, but with oil prices still at supportive levels for producers this latest statement prompts three key questions: can it be done; can even more be done; and will it be done? The answer to the first question is yes. As analysed in depth in my new book on the global oil markets, Iraq – even more so than Iran – remains the greatest relatively underdeveloped oil frontier in the world. Officially, according to Energy Information Administration (EIA) figures, Iraq holds a very conservatively estimated 145 billion barrels of proved crude oil reserves (nearly 18 percent of the Middle East’s total, and around 9 percent of the world’s). Currently, it is producing around 4.1-4.2 million bpd, compared to its April OPEC quota of 4.414 million bpd, and its quota is due to increase to 4.5 million bpd in June. Although Iraq is currently only managing to produce around 4.1-4.3 million bpd, this shortfall is largely attributable to field outages in the south for maintenance reasons, most notably the 400,000 bpd West Qurna 2 oilfield being offline for 12 days of maintenance, and to ongoing upgrading work being done on its export infrastructure. From 2015 to 2020, Iraq crude oil production was frequently recoded at over 4.5 million bpd, with its highest monthly production being 4.83 million bpd in December 2016, according to OPEC figures. In the relatively short-term, certainly before the end of 2027, there certainly appears scope to increase crude oil output from several fields in Iraq – concentrating on those in the south, given ongoing difficulties in the semi-autonomous region of Kurdistan in the north – without too much in the way of costly and time-consuming build-out of the country’s fundamental oil infrastructure. Last August, Iraq approved plans to enable BP to spin off its operations in the supergiant Rumaila oil field with the creation of Basra Energy Ltd that would hold BP’s interest in the site and be jointly owned by China National Petroleum Corp (CNPC). This is expected to release a considerable new line of financing for the field, which has been producing around 1.4-1.5 million bpd for many years, since its discovery in 1953. With remaining recoverable crude oil of around 17 billion barrels, the field has a plateau target of 2.1 million bpd. As with the vast majority of Iraq’s oil fields both north and south, the lifting cost for oil remains the lowest in the world at around U$2-3 pb, on a par with that of Saudi Arabia. Recent increases in Rumaila’s crude oil output can be attributed to improvements put into place by BP and CNPC, including the renovation of the Qarmat Ali Water Treatment Plant. This is now capable of treating up to 1.3-1.4 million bpd of river water, allowing for greater extraction of oil from the field’s Mishrif reservoir (triple the amount, in fact, that was extracted in 2010). According to industry figures, Rumaila requires around 1.4 barrels of water for each barrel of oil produced from the north of the field, whilst the Mishrif formation in the south will require much higher water injection rates to support production. The Qarmat facility has also supported, and will continue to support, crude oil production increases at the adjunct Zubair field, principally operated by ENI (plus KOGAS and Iraqi partners), as around 14 percent of the water from the Qarmat Ali Water Treatment Plant goes to Zubair. With an initial target of 201,000 bpd, Zubair now produces around 360,000 bpd, and is due to receive a further boost from the construction of a 380 megawatt power plant. These advances are likely to increase oil production to around 600,000 bpd, and there is even further scope for major production increases, given Zubair’s initial plateau target of 1.2 million bpd. Pressure has been brought by Iraq’s Oil Ministry in recent weeks on the developers of several fields in the ThiQar province, most notably Gharraf and Nasiriya. In the context of this 6 million bpd crude oil production target, the Oil Ministry has called on Japan’s Japex to speed up its work increasing production at the 1 billion+ barrels of oil reserves Gharraf field, up from the current 90,000 bpd to at least 230,000 bpd. This was the original plateau figure, after the initial target of 35,000 bpd had been reached. As an incentive, good progress on Gharraf would be regarded positively by Iraq’s Oil Ministry in assigning favourable development contracts on the nearby 4.36 billion-barrel Nasiriya oilfield. Such increases, although they would allow Iraq to hit its 6 million bpd target, pale into insignificance when considering question two: can even more be done? The answer here, again, is yes. In 2013, Iraq launched its ‘Integrated National Energy Strategy’ (INES), which formulated the three forward oil production profiles for Iraq. The INES’ best-case scenario was for crude oil production capacity to increase to 13 million bpd (at that point by 2017), peaking at around that level until 2023, and finally gradually declining to around 10 million bpd for a long-sustained period thereafter. The mid-range production scenario was for Iraq to reach 9 million bpd (at that point by 2020), and the worst-case INES scenario was for production to reach 6 million bpd (at that point by 2020). These figures were based on solid facts and figures from several renowned and trusted external sources, as also analysed in depth in my new book on the global oil markets. According to a limited-circulation report produced at around the same time by the International Energy Agency (IEA), a 1997 detailed study by respected oil and gas firm, Petrolog, had already provided figures that were in line with the Iraq Oil Ministry’s later statements that
ONGC Offers Stake In KG Block To Foreign Firms
State-owned Oil and Natural Gas Corporation (ONGC) is offering a stake to foreign companies in its ultra deepsea gas discovery and a high-pressure, high-temperature block in the KG basin as it looks for financial and technological help to bring the challenging fields to production. ONGC has floated an initial tender seeking interest of global majors with “requisite technical expertise and financial strength” to join as partners in development of the Deen Dayal West (DDW) block as well as ultra-deep discoveries in Cluster-III of its KG-D5 area. Expressions of Interest (EoIs) have been invited by June 16, according to the tender floated by the company. While ONGC had made a gas discovery UD-1 in the KG-D5 block in water depth of 2,850 metres (almost 3 kilometers), the firm had in August 2017 paid Rs 7,738 crore for buying 80 per cent stake in the DDW block from Gujarat government firm GSPC. On the one hand, ONGC does not have the requisite technology and expertise to develop the UD discovery, which lies about 150-km from the coast, while on the other hand it hasn’t had much success in DDW block which holds reserves at high pressure and high temperature (HPHT). ONGC is seeking technology partners and service providers for the development of the two and is willing to offer an equity stake to firms interested, the tender document said.
Shell in talks with Indian consortium to sell Russian LNG plant stake: Report
Shell is in talks with a consortium of Indian energy companies to sell its stake in a major liquefied natural gas plant in Russia which the British company abandoned following Moscow’s invasion of Ukraine, three sources told Reuters. The consortium’s potential interest in the Russian plant shows how India is willing to move in on energy assets and cheap oil supplies coming on the market as a result of Western companies pulling back from Russia. Shell in February said it would exit all its Russian operations, including its 27.5% stake in the Sakhalin-2 LNG plant on Russia’s eastern flank, amid an exodus of Western companies from the country. The world’s largest liquefied natural gas trader wrote down $3.9 billion on Russian assets after its decision to leave. The company has recently entered talks with a group of Indian companies, including ONGC Videsh and Gail to acquire the stake, the sources said. Shell declined to comment. ONGC, Gail and other state-run Indian companies did not respond to Reuters’ request for comment. Shell is also asking the Indian group for separate bids for long-term deals it has with Sakhalin 2 to supply it with LNG cargoes and crude oil, two of the sources said. The Indian government has asked state-run energy companies to evaluate the possibility of buying Russian assets from European oil majors including BP, Reuters reported last month. It was unclear if the talks between Shell and the Indian consortium will lead to a deal, whose value remains unclear after Shell took the writedown on its Russian assets. Any sale agreement would also require Moscow’s approval, the sources said. Shell is currently not in talks with other companies, including Chinese energy groups, on selling the Sakhalin-2 stake, one of the sources said. Sakhalin-2 is controlled and operated by Russian gas company Gazprom. Other stakeholders in the project include Japan’s Mitsui & Co and Mitsubishi Corp. Shell earlier this month agreed to sell its Russian retail and lubricants businesses to Lukoil.
India’s renewables increase and take some pressure off coal
Continued warm weather drives India’s power demand. Seasonal increase in renewables started. Coal-fired power generation for May declines from April, but stocks are still low. Gas-fired power generation shows little movement, indicating no spot LNG used as fuel. High power demand driven by warm weather India’s power demand for May 1-17 is estimated at 196 aGW and is higher than expected. The strong demand is driven by sustained warmer-than-normal weather. Temperatures for the first half of the month were 2 C higher year on year for India, while certain regions, such as Delhi, were 4 C higher. The May development is a continuation of the situation in April, when a temperature-driven increase in power demand set a new all-time high record and averaged 194 aGW. The hot weather in Delhi is expected to get a relief over the next few days as rain is forecast for May 20-24. Renewables have started seasonal increase, effectively easing coal demand Renewables generation has started its seasonal increase and are estimated at 25 aGW for the first part of the month, which is an increase of 9 aGW year on year. The majority of the increase is from wind, which at 12 aGW has almost doubled year on year. Hydro is also higher at 18 aGW, which is 3 aGW higher on the year. The combined increase from renewables and hydro has taken some pressure off coal-fired power generation, which averaged 137 aGW for May 1-17, a decline of about 5 aGW from April. Gas-fired power generation continues to stay stable and low at close to 3 aGW, which most likely means spot LNG is still absent from the fuel mix since October 2021 Outlook for summer S&P Global Commodity Insights assumes normal temperatures going forward and expects power demand for May to September at 182 aGW, which is an increase of 10 aGW year on year. In May 2021, there was a nationwide lockdown for several weeks, which limited power demand. S&P Global expects gas-fired power generation to continue to stay low around 3 aGW, assuming demand for gas averaging 17 million cu m/d, which is 9 million cu m/d lower on the year. Coal-fired power generation is expected to be 125 aGW, which is an increase of 8 aGW, or about 7% on the year. As discussed in the May 12 International Thermal Coal Scorecard, India’s Ministry of Power issued a directive May 3 asking state-operated utilities to increase coal imports to ensure India’s utilities have 50% of target coal tonnes (38 million mt, so 19 million mt) by end-June. This has Indian buyers reportedly issuing tenders and booking imports, for example, from the US Northern Appalachia exporters, and purchasing other material from port stocks. India is expected to import 11-13 million mt of thermal coal in April and May 2022 ahead of the monsoon season. S&P Global expects summer-22 imports to average around 14 million mt/month through September, though significant downside risk remains to this forecast. Seaborne imports continue to be constrained by elevated seaborne spot price levels throughout 2022 and this forecast remains above the previous year average of 12 million mt/month for the same period. Indonesia, South Africa, and Australia remain the top suppliers of Indonesian imports.
India aims to ease oil price pain through tax cuts, new term crude deals
From cutting taxes on retail oil products to scouting around for attractive term crude deals, India is stepping up efforts to ensure that surging world prices do not stand in the way of the fragile economic recovery as well as a revival in domestic oil product consumption. Government officials in India said they believe that current oil prices were not sustainable over the longer term, but they were also unanimous in their view that it was crucial to implement fiscal measures now to ensure that inflation stays under control, instead of waiting for oil prices to cool. “Oil prices are a big concern for the government and the economy now because of its cascading effect. Not only pump prices and transportation costs go up, but prices of various other goods and services are affected,” Dharmakirti Joshi, chief economist at CRISIL, a unit of S&P Global, said. According to Platts Analytics of S&P Global Commodity Insights, Dated Brent prices are expected to average $103/b in 2022, up from $71/b in 2021, before easing to $90/b in 2023. “We estimate that every $10 per barrel rise in the price of Brent crude would raise the headline consumer price index by about 40 basis points. The weakening of the Indian rupee will also add to the imported cost of crude and commodities,” Joshi added. Inflation, based on CPI, has risen consistently for the past seven months, reaching an eight-year high of 7.8% in April. Excise duty cuts On May 21, India’s federal government decided to cut the excise duty on petrol and diesel in an attempt to rein in high levels of inflation. It was the second duty cut in a little over six months. The duties on petrol and diesel were cut by Rupees 8/liter and Rupees 6/liter, respectively. “The decisions along with steps to curb the price rise on key infrastructure material such as cement, steel and plastics will bring wide-scale relief to millions of Indian families and provide pivotal support to the Indian economy amid a challenging global inflationary environment,” oil minister Hardeep Singh Puri said after the excise duty cuts were announced. CRISIL’s Joshi added that while the government’s top priority was battling inflation, the excise duty cut on fuels would also mean revenue loss. “But the space to address this issue is extremely limited. You either let fiscal deficit to go up or cut capital expenditure. The government may watch oil prices for some more time before taking additional measures.” India’s sustained uptrend in oil consumption came to a halt and slipped into the red in April from March levels as rising domestic retail fuel prices on the back of surging crude took a toll on gasoline, diesel and LPG demand. Domestic oil product demand fell 4% month on month to 18.64 million mt, or 4.9 million b/d, in April, recent data from the Petroleum Planning and Analysis Cell showed. “I am not convinced international crude prices would continue above $110 a barrel. Global crude prices should come down in the near to medium term. High oil prices will lead to recession. Our job is to insulate the country against the expected recession,” a top official at the petroleum ministry said. The official added that it was difficult to believe that the recent high crude prices were due to lack of investment in the exploration and production segment worldwide. “The current high crude prices reflect the mismatch between demand and supply of crude in global markets.” New crude term deals The Indian government and refinery officials said India was looking for new term crude deals that would make commercial sense. “There are discussions on a government-to-government (G-to-G) level. We are open to any kind of opportunity and if something is done on a G-to-G level, we would obviously be a part of that,” P.K. Joshi, chairman of state-run Hindustan Petroleum Corp. Ltd., said. “Any opportunity coming in the future of utilizing Russian crude, definitely we will be utilizing that depending on technical and economical requirements.” “It should make sense in terms of freight, insurance, and various factors,” he added. India is also eyeing term crude deals with Brazil, but analysts said high shipment costs, the long sailing period and limited bandwidth with the South American producer to commit plentiful volumes beyond its traditional Asian customers will keep the size of any new term deals relatively small. While it currently costs less than $4/mt and takes about four to six days to ship crude oil from the Middle East, it costs $15-$20/mt and takes more than 25 days to ship from Brazil to Asian destinations, market sources said. HPCL officials said they expect crude prices to hover in the range of $105-$115/b in June, and $103-$111/b in the July-September quarter.