Expect High LNG Prices For Years To Come
Since Russia’s invasion of Ukraine upended global energy markets, the LNG industry has been grappling with many uncertainties. In fact, the only real certainty is that spot LNG prices will remain elevated for years to come, even if they don’t hit the most recent record highs again. Key demand centers in Europe and Asia are facing their own set of uncertainties at the end of the heating season and ahead of next winter, the peak demand period in the northern hemisphere. Uncertainties range from how much Europe will have managed to fill its storage capacity by next November, to how much Asia will buy on the spot market to stock for the winter after lackluster demand so far this year. LNG supply and demand will also depend on whether Russia will cut off supply to more EU customers after halting deliveries to Poland, Bulgaria, and Finland, and on how cold next winter will be in Europe and Asia. “We have massive uncertainty over what will happen next,” Steve Hill, Executive Vice President at Shell Energy, said at this week’s World Gas Conference in South Korea. “If we convert the Russian pipeline gas volume into Europe in 2021 into an LNG equivalent, and add on the LNG volumes delivered into Europe in 2021, that’s 200 million tonnes of LNG equivalent. That’s half the size of the current (global) LNG industry,” Hill said, as carried by Reuters. It’s clear that Europe will not be able to replace all the Russian pipeline gas with LNG soon. The world just doesn’t have that much supply capacity and will not have it until some point in the middle of this decade. Larger volumes of LNG are expected to hit the market in 2026 and afterward, when the U.S. projects under development and Qatar’s expanded capacity come on stream. Since the energy crisis of last autumn, Europe has displaced Asia as the growth driver of LNG demand and is no longer “the market of last resort” for LNG cargoes. The Russian invasion of Ukraine has further spurred Europe to start reducing its heavy reliance on Russia’s piped gas, without which the continent currently risks a severe industrial slowdown and a rush to secure heating for next winter. As of May 26, gas storage capacity in the EU was 44.45% full, while in the UK, this capacity is over 91% full, according to data from Gas Infrastructure Europe. Storage levels in Europe are back to normal levels for this time of the year, but there is nothing normal in the global energy market this year, so LNG demand in Europe is expected to remain high through the start of the next winter season. Moreover, the EU member states are now required to reach a minimum 80% gas storage level by November 1 to protect against potential interruptions to supply. From 2023, the target will be raised to 90% full gas storage by November 1. “Filling the EU’s gas storage before the next winter is crucial for ensuring our security of supply,” European Commissioner for Energy Kadri Simson said last week. While Europe will continue to race to buy much higher volumes of LNG compared to last year, the demand outlook in Asia is less certain. Asian LNG imports fell 10% year-on-year in Q1 2022, with Chinese, Japanese, and Indian imports down 11%, 14%, and 25%, respectively, Wood Mackenzie has estimated. Overall Asian LNG demand is now expected to be flat this year compared to 2021, WoodMac says. High spot LNG prices have priced out Asian buyers, while market volatility and uncertainties, and concerns about energy security have prompted a growing number of buyers to seek long-term contracts. The race for LNG supply could give rise to the second wave of U.S. LNG projects, but new supply will take time to develop, Kateryna Filippenko, Principal Analyst, Global Gas Supply, at Wood Mackenzie, said last week. But much of this new LNG supply, including from projects that have taken FIDs in previous years, is likely to come only after 2026. Until around 2026, “Europe will have to compete with Asia for the marginal LNG molecule to satisfy demand – just as it is right now,” Filippenko noted. “Competition between Europe and Asia for limited LNG will be intense until a new supply wave arrives after 2026. Prices will inevitably remain elevated until then.”
L&T ahead for NEOM $6.4-bn hydrogen renewables facilities: MEED
Saudi Arabia’s NEOM Green Hydrogen Co. is understood to have selected India’s Larsen & Toubro to build solar and wind plants for supplying electricity to the city’s $6.4-billion green hydrogen-based ammonia plant, MEED reported. ACWA Power, one of the three equity partners in NGHC along with Air Products and NEOM Co., is responsible for supplying the energy to the project. The Riyadh-based firm declined to comment on the news when contacted by Arab News. According to MEED, L&T, along with Energy China and Power China, submitted a proposal for an engineering, procurement and construction contract to build the renewable energy infrastructure. The contract covers the construction of 2,930 MW solar power generation plant, a 1,370 MW wind power farm and a 400 MW battery energy storage system, according to a source familiar with the plan. The package also includes a 190-kilometer power transmission network. The planned wind and solar power plants are to be located in northwest Saudi Arabia in proximity to the hydrogen plant, which is to be built at OXAGON industrial zone in NEOM.
BPCL rationing fuel: Dealers
Several fuel dealers across the state have complained that Bharat Petroleum Corporation Limited (BPCL) has reduced the supply of petrol and diesel. According to the dealers, many oil companies, mainly BPCL, have been following a ‘ration system’ to reduce losses due to rise in crude oil prices in the global market. “BPCL in Karnataka and elsewhere has started rationing petroleum products or is not supplying them to its retail outlets of late, resulting in them going dry and inconveniencing the public,” said Akhila Karnataka Federation of Petroleum Traders (AKFPT) in a statement.“Products are not being supplied despite advance payment and dealers are forced to be at the mercy of company officials for obtaining intermittent supplies…,” it added. BPCL officials were unavailable for comment.
Enbridge to deliver natural gas to Venture Global’s LNG facility
Pipeline operator Enbridge Inc said on Thursday it would deliver 1.5 billion cubic feet per day of natural gas to Venture Global’s Plaquemines liquefied natural gas (LNG) facility in Louisiana. Earlier this month, Enbridge outlined expansion plans to meet soaring global demand for LNG following sanctions on Russia, one of the largest crude exporters in the world. Enbridge said the gas would be supplied through its two projects, Gator Express Meter Project and Venice Extension Project, which are expected to be in service by 2023 and 2024, respectively, at an estimated cost of $400 million. “Enbridge is excited to continue working with Venture Global on their second LNG project to bring clean, reliable natural gas to the U.S. Gulf Coast for export to global markets,” said Cynthia Hansen, Enbridge executive vice president and president, Gas Transmission & Midstream. Venture Global LNG said on Wednesday it had made a final investment decision (FID) to build the proposed Plaquemines LNG export plant.
Govt withdraws offer to sell its entire 53% stake in BPCL
The government on Thursday withdrew its offer to sell its entire 53 per cent stake in BPCL, saying that majority of bidders have expressed their inability to participate in the current privatisation process due to prevailing conditions in the global energy market. The government had planned to sell its entire 52.98 per cent stake in Bharat Petroleum Corporation Ltd (BPCL) and invited Expressions of Interest (EoIs) from bidders in March 2020. At least three bids came in by November 2020. However, the privatisation was stalled after two bidders walked out over issues such as lack of clarity in fuel pricing, with just one bidder left in the fray. The Department of Investment and Public Asset Management (DIPAM) said in response to the invitation, multiple EoIs were received from interested parties. Qualified Interested Parties (QIPs) had initiated due diligence of the company. However, the multiple COVID-19 waves and geopolitical conditions affected industries globally, particularly the oil and gas industry. “Owing to prevailing conditions in the global energy market, the majority of QIPs have expressed their inability to continue in the current process of disinvestment of BPCL,” it said. In view of this, the group of ministers on disinvestment has decided to call off the present EoI process for the strategic disinvestment of BPCL and the EoIs received from QIPs shall stand cancelled, DIPAM said. “Decision on the re-initiation of the strategic disinvestment process of BPCL will be taken in due course based on review of situation,” it added. Shares of BPCL settled at Rs 324.25, down 0.54 per cent over its previous close on the BSE. The privatisation of India’s second-largest state oil refining and fuel marketing company had not attracted much interest initially due to the volatile global oil price scenario and later because of lack of clarity in domestic fuel pricing. The government was to seek financial bids once bidders completed due diligence and the terms and conditions of the share purchase agreement were finalised. Mining mogul Anil Agarwal’s Vedanta group and US venture funds Apollo Global Management Inc and I Squared Capital Advisors had expressed interest in buying the government’s 53 per cent stake in BPCL. But the two funds withdrew after failing to rope in global investors amid waning interest in fossil fuels. Public sector fuel retailers, which control 90 per cent of the petrol and diesel market, sell these fuels at prices below the cost. As the government takes a fresh look at BPCL privatisation, including revising the terms of sale, it may offer a 26 per cent stake along with management control in the company, considering the geopolitical situation and energy transition, a source said. This will limit the amount of money a bidder has to put upfront to buy the company. BPCL is India’s second-largest oil marketing company after Indian Oil, and with refineries in Mumbai, Kochi and Madhya Pradesh, it has the third-largest refining capacity after Reliance and Indian Oil.
Indian diesel to be piped in Bangladesh by Oct
Diesel import from India through an under-construction cross-border pipeline is set to begin by October, propping up drives for feeding growing fuel demand in Bangladesh. A high-powered delegation from the state-run Bangladesh Petroleum Corporation (BPC) will visit India next week to evaluate progress in the ongoing construction works of the oil pipeline, a senior BPC official told the FE Wednesday. Around Indian Rupees 3.46 billion is being provided under the Indian line of credit (LOC) to implement the130-kilometer-long India-Bangladesh Friendship Pipeline. Of the oil line, 125 kilometers will be constructed inside Bangladesh and 5.0 kms on India’s side. Bangladesh currently imports around 2,200 tonnes of diesel every month from Numaligarh Refinery Ltd (NRL) to through West Bengal Railway and the BPC carries the fuel through Bangladesh Railway to Parbatipur oil depot in the country’s northern region. The BPC will, however, import as high as around 1.0 million tonnes of diesel annually through this pipeline. Initially, the petroleum corporation will import around 250,000 tonnes of diesel per year during the initial three years of its operation. The volume will be gradually increased to 400,000 tonnes per year during the first five years, from where the import quantity will increase to around 1.0 million tonnes a year. Bangladesh will import diesel from India at least for 15 years under the pipeline deal. “The country’s diesel import might go beyond the already-agreed 15 years following mutual decision,” said the official. The BPC has agreed to purchase Indian diesel from NRL at a premium rate of US$5.50 per barrel to Mean of Platts Arab Gulf (MoPAG) constant for 15 years on cost-and-freight (CFR) basis. MoPAG is the benchmark in oil-pricing formula prepared by Platts, a US-based energy information provider. The cross-border pipeline passes through Panchagarh, Nilphamari and Dinajpur to Parbatipur oil storage. The Indian fuel oil will be consumed by clients in Bangladesh’s northern region, once the pipeline is commissioned. Diesel demand is around 1.10 million tonnes in the country’s 16 northern districts, where natural gas has yet to reach. Bangladesh earlier imported diesel from India only for a brief period and in a small quantity of 3,500 tonnes from the state-run Bharat Petroleum Corporation Ltd (BPCL) in 2007. The petroleum corporation (BPC) also imported around 400,000 tonnes of diesel from Indian Oil Company Ltd during 2005-06, said sources.
Buyers Scramble To Lock In Long-term Contracts In Red-Hot LNG Market
The long-term LNG contract is back. Buyers of liquefied natural gas in Europe and Asia are increasingly committing to long-term purchase agreements, unlike in the past few years when spot contracts gained a significant market share as customers sought flexibility in delivery clauses and lower prices than the oil-linked prices in the long-term deals. Buyers, especially in Asia, frequently took advantage of spot cargo deliveries to replenish their stocks ahead of the winter heating season. This year everything changed in the energy market after Russia invaded Ukraine. The war in Ukraine and Europe’s now irreversible pledge to eliminate dependence on Russian pipeline gas sparked energy security concerns globally and a rush to spot contracting that sent spot LNG cargo prices to record highs. Buyers returned to long-term contracts in order to secure long-term supply of non-Russian gas and to insulate themselves from spiking volatile spot prices. In just a few months, the global LNG market turned from a buyer’s market to a seller’s market, with LNG suppliers commanding a tight market as buyers scramble to secure gas from providers other than Russia. Europe’s race to fill gas inventories ahead of next winter amid high uncertainty over whether—or rather when—Russia would cut off gas deliveries to more buyers in Europe, priced out the more-sensitive spot buyers in Asia, while Europe is politically motivated to procure more LNG supply. The Return Of The Long-Term Contract Several deals for long-term LNG supply were announced this week alone. Buyers in both Europe and Asia have announced a flurry of such contracts in recent weeks, mostly with U.S. sellers, which actually need long-term commitments for their supply in order to secure financing and proceed with the many projects for new LNG export terminals. Just yesterday, Venture Global LNG announced a final investment decision (FID) and successful closing of the $13.2 billion project financing for the initial phase of its Plaquemines LNG export facility and the associated Gator Express pipeline—the largest project financing in the world closed so far this year. In addition, the company has executed 20-year Sales and Purchase Agreements for 80% of the full 20.0 MTPA project. TotalEnergies signed on Tuesday a deal with South Korea’s Hanwha Energy Corporation for the supply of 600,000 metric tons of LNG per year over 15 years, starting in 2024. “It is significant that we have secured business stability by signing a long-term contract with our long-lasting partner TotalEnergies, even though the volatility of the LNG market has increased more than ever due to the recent unstable international situation,” said Hanwha Energy CEO Jung In Sub. Top U.S. LNG exporter Cheniere Energy announced on Wednesday a 20-year deal with POSCO Holdings, South Korea’s largest steelmaker and owner of the country’s first private LNG terminal. Cheniere will supply LNG starting in late 2026 on a free-on-board basis, with the purchase price for LNG indexed to the Henry Hub price, plus a fixed liquefaction fee. The deal is subject to Cheniere making a positive final investment decision to construct the Corpus Christi Stage III Project, expected this summer. On the same day, Sempra Infrastructure signed a heads of agreement with Germany’s RWE for the long-term supply of LNG on a free-on-board basis from the Port Arthur LNG Phase 1 project under development in Jefferson County, Texas. “Our partnership can contribute largely to securing significant LNG volumes for the RWE portfolio on a long-term basis while building the basis for supplying low carbon gas in the future,” said Andree Stracke, CEO of RWE Supply & Trading. In the most curious about-face showing how energy security and Europe’s drive to break free from Russian gas dependence have upended the LNG market, France’s Engie—which had abandoned talks on an LNG deal with U.S. NextDecade in 2020 due to environmental concerns—signed this month a preliminary 15-year deal with the same firm for supply from the Rio Grande LNG export project in Brownsville, Texas. Assuming the achievement of further LNG contracting and financing, NextDecade expects to make a positive FID on at least two trains of Rio Grande LNG in the second half of 2022. Long-Term Deals Gain Momentum Following the highest level of long-term LNG contracting in five years in 2021, demand for long-term LNG deals continues to gain momentum this year as large volumes have been signed and prices for oil-linked deals under negotiation are rising, Wood Mackenzie said in a report last week. “Many traditional LNG buyers will neither procure spot gas or LNG nor renew or sign additional LNG contracts with Russian sellers. Spot prices have also been high and volatile, pushing many buyers towards long-term contracts,” Wood Mackenzie principal analyst Daniel Toleman said. “Additionally, some buyers are returning to long-term contracting on behalf of governments to protect national energy security.” In early May, Sempra Infrastructure’s chief executive Justin Bird said that the market is seeing a dramatic shift toward long-term contracting. “There has been a dramatic shift in the market in the recent days. Specifically, we’ve seen a significant amount of long-term contracts,” Bird said on Sempra Infrastructure’s Q1 earnings call. “So yes, you are seeing a lot of parties, given the volatility in both TTF and JKM. And frankly, the high forwards, you’re seeing a definite renewed interest in parties willing to go long term. And those are the conversations that we are having.”
Rise in global prices derails govt’s clean energy plans
Before gas prices spiked, India planned to reduce its carbon footprint by 33-35% of its 2005 levels by 2030, part of its commitment at the Paris climate conference seven years ago. India made a commitment at the COP-26 summit in November last year to achieve net zero carbon emission by 2070. Skyrocketing international fossil fuel rates, particularly of natural gas, due to the Russia-Ukraine war and a supply squeeze by energy exporting countries have compelled India to change its clean energy transition road map and revert to using both domestic and imported coal in a big way to meet its energy needs, a top government functionary said. “As far as fulfilling Paris commitment is concerned, India was among top three countries (in doing so). Natural gas was to play a major role in transition from coal to clean energy. But due to rising prices of natural gas, the country is forced to raise domestic coal production. Even many developed nations and emerging economies are going back to coal,” this person added on condition of anonymity. Union finance minister Nirmala Sitharaman spoke of India’s changed position due to factors beyond its control at international fora including those organised by the International Monetary Fund (IMF), the World Bank and the Atlantic Council during her recent visit to the US. Before gas prices spiked, India planned to reduce its carbon footprint by 33-35% of its 2005 levels by 2030, part of its commitment at the Paris climate conference seven years ago. India made a commitment at the COP-26 summit in November last year to achieve net zero carbon emission by 2070. Adequate availability of energy at an affordable rate is one of most important factors for India, which is the world’s fastest growing economy. “While imported natural gas prices are rising relentlessly, domestic production of natural gas is either stagnant or declining. In this situation, India is left with no option but to increase its reliance on coal,” the functionary l said. India, which is the world’s third largest consumer of fossil fuel, imports 85% of crude it processes and 54% of its natural gas requirement. The functionary said India has made it clear that its refiners and energy firms would import oil and gas from Russia based on their commercial judgement because the country has to tap all sources to meet its energy requirements. “We may also revive the Rupee-Ruble payment system, as this mechanism already exists and its validity has not expired.”
ONGC To Invest Rs 310 billion In Finding Oil, Gas
n a statement, ONGC said its board held a meeting on Thursday to firm up its ‘Future Exploration Strategy’. India’s top oil and gas producer ONGC on Thursday said it will invest Rs 310 billion over the next three years in exploring the Indian sedimentary basin for fuel reserves which could augment the nation’s production in its attempt to be self-reliant in the energy sector. In a statement, ONGC said its board held a meeting on Thursday to firm up its ‘Future Exploration Strategy’. “The company has drawn up a comprehensive roadmap to further intensify its exploration campaign, allocating a capital expenditure of about Rs 310 billion in the next three fiscal years during FY 2022-25. This is 150 per cent of its exploration expenditure of Rs 206.70 billion in the last three fiscals during FY 2019-22,” it said. ONGC said it also plans to leverage international collaborations with reputed global majors for this, for which talks are in an advanced stage. However, it did not elaborate. India is 85 per cent dependent on imports to meet its oil needs and half of the natural gas requirement is shipped from abroad. Finding and producing more oil and gas domestically will cut this reliance, helping insulate the domestic market from volatility in international energy prices. “This exploration intensification includes activities funded through ONGC’s internal program as well as funded and facilitated by the government,” the statement said. Under the internal program, ONGC is trying to probe around 1,700 million tonnes of oil and oil equivalent gas (MMTOE) of yet-to-find (YTF) reserves during FY 2022-25. The activities here include a state-of-the-art 2D and 3D seismic survey, followed by drilling of around 115-120 wells with an estimated outlay of Rs 100 billion every year for the next three years. In addition, the government’s facilitation has resulted in the release of about 96,000 square kilometers of area so far, which was earlier demarcated as a ‘No Go’ zone. This will further help ONGC achieve its acreage acquisition program of bringing around 5,00,000 sq km under active exploration by 2025. Under a government-funded program for appraisal of unapprised offshore areas till the Exclusive Economic Zone (EEZ), 70,000 line kilometers (LKM) of state-of-the-art 2D broadband seismic data acquisition, processing and interpretation (API) will be done in three sectors — west coast, east coast and Andaman offshore. ONGC will complete the technical bid opening (TBO) for seismic data acquisition by June 2022. In Andaman Basin, ONGC presently holds two blocks for exploration under the Open Acreage Licensing Policy (OALP). “Government of India has also acquired seismic data in some sectors within ‘No-Go’ areas and few prospects are already identified,” it said without giving details. ONGC plans to drill six wells in the next three years (two under ONGC committed work program and four through government funding). Reputed global companies/consultants are being invited for the assessment of the basin for future exploration and exploitation plan. “ONGC’s internal program has three components – re-exploration of mature basins, consolidation of emerging basins and probing of emerging and new basins,” the statement said.
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