The UK Government should update its “vague terminology” on carbon capture usage and storage (CCUS) deployment in the UK to create clear policy drivers that transform the technology into a primary tool to meet national and international climate change targets.

That is one of the key takeaways from the Business, Energy and Industrial Strategy (BEIS) Committee’s new report, released today (25 April) which notes that the UK could not credibly adopt a net-zero emissions target with CCUS playing a key role.

The UK Government has confirmed that it is seeking advice from the Committee on Climate Change (CCC) on how best to bolster its carbon reduction targets and create a net-zero economy, with a formal response from the CCC set to be published next week.

The report notes that a failure to deploy CCUS in the UK could double the costs of meeting the 80% emissions reduction envisioned through the Climate Change Act, rising from approximately 1% of GDP annually to 2% in 2050.

The report notes that the UK has a “favourable environment” to establish CCUS as a technology. Five clusters – Teesside, Humberside, Merseyside, South Wales, North East Scotland – have been identified as well suited to early CCUS deployment, which aligns to Energy Minister Claire Perry’s vision of a “just and fair” low-carbon transition across all areas of the UK.

However, policymakers have been criticised over their approach to CCUS. A stark warning from the CCS taskforce was issued based on the need to move timeframes forward for CCUS. The taskforce criticised ministers for closing the £1bn competition fund for CCS in 2015, citing claims that the decision could cost the UK an additional £30bn if it is to meet its 2050 carbon targets.

The new report analyses commitments made under the Clean Growth Strategy, which committed up to £20m for viable CCUS schemes as the UK forges ahead with its coal plant phase out by 2025.

Late last year, the UK Government unveiled plans to “make CCUS technologies a reality”, including an aim to bring the nation’s first large-scale CCUS facility online by the mid-2020s. However, government ambitions largely focus on using CCUS as an add-on for current power generation methods. The BEIS Committee report claims that it can instead be a key tool for decarbonisation and “presents an opportunity to reduce the overall cost of meeting the UK’s emissions reduction targets”.

“Whilst we strongly support cost minimisation, we disagree with the CCUS Action Plan’s stipulation that deployment ‘at scale’ should be supported only if ‘sufficient’ cost reductions are achieved. Such vague terminology gives no certainty to investors and does little to ensure that CCUS can contribute to meeting the UK’s overarching climate change targets at least cost, given its existing status as the cheapest — or only — decarbonisation option in many industrial applications,” the report states.

Benefit analysis

Specifically, the report called for an urgent consultation to allocate funding for CCUS industry clusters, ideally ahead of future Contract for Difference (CfD) auctions. The forthcoming Comprehensive Spending Review should also focus on CCUS, the report states, in order to denote its wider benefits in extending lifetimes for select industries that would otherwise be decommissioned under national climate policy requirements.

The Committee also recommends the Government task the National Instructure Commission – or a third party – to conduct cost-benefit analysis as to how CCUS can be used to decarbonise industrial emissions.

Anna Turley, Labour MP for Redcar and Member of the Business, Energy and Industrial Strategy Committee, said: “The UK has an opportunity to lead the world in the development of a new CCUS industry. In addition to helping to tackle UK carbon emissions, CCUS can play a crucial role in delivering much-needed investment in skills and infrastructure and supporting regional growth and jobs.

“The current Energy Minister has been a champion for CCUS, and there have been some encouraging recent developments, but the CCUS industry has been the victim of years of turbulent policy support and suffered a series of false dawns. The Government now needs to give the ‘green light’ to CCUS and ensure that we seize the domestic growth and jobs opportunities of this modern, green industry.”

Public debt in Greece and Italy, the two most indebted countries in the eurozone, grew last year while the bloc as a whole saw its liabilities decrease, the European Union statistics office said yesterday.
Rome’s growing debt, which is also higher than Brussels had predicted, is seen as further stretching EU fiscal rules that require countries with high debts to gradually bring them down.
Italy, whose eurosceptic government adopted free-spending policies last year that have so far had little impact on growth, had debt equivalent to 132.2% of national output in 2018, or €2.3tn ($2.5tn), up from 131.4% in the previous year, Eurostat said.
Up to 0.2% of the Italian debt was due to derivative contracts, which are usually used to hedge against risks but triggered losses for 4.7bn euros in 2018, Eurostat data show.
Other eurozone countries have reduced their debt thanks to derivatives.
Although Rome has decreased its losses on derivatives from the €5.4bn posted in 2017, the negative impact over the country’s debt has exceeded 25bn since 2015, data show.
The European Commission, which monitors eurozone states’ budgets, refrained in December from starting disciplinary steps against Italy over its growing debt. It predicted then that Italian debt would be 131.1% of gross domestic product in 2018 — lower than yesterday’s data showed.
The Commission has said it will reassess Rome’s compliance with EU fiscal rules, including the requirement to cut debt, in June, taking into account the final debt data from Eurostat.
A spokeswoman for the EU executive declined to comment on the new figures released by Eurostat.
She said Brussels’ new evaluation of Italy’s position will also be based on new forecasts due in May of debt developments, and on Italy’s report on its fiscal plans for the next three years which Rome had just submitted.
Italy’s 10-year government bond yield jumped to its highest in seven weeks yesterday, pushed up mostly by unease over government infighting and an upcoming ratings review.
Italy bucked the eurozone trend, as overall debt in the 19-country currency bloc fell to 85.1% of GDP last year from 87.1% in 2017, Eurostat said.
The bloc’s aggregated budget deficit also dropped to 0.5% of GDP from 1.0% in 2017.
The fall coincided with Germany’s reduction of its debt to 60.9% of GDP, from 64.5% in 2017.
The bloc’s largest economy also widened its public surplus to 1.7% of output from 1.0% in 2017.
In Greece, debt climbed to 181.1% of GDP in 2018, the largest ratio in the eurozone.
The increase from 176.2% in 2017 was mostly due to the last instalment of eurozone creditors’ loans as part of the country’s third bailout programme which ended last summer.
The recent exit from the bailout programme exempts Greece from the normal application of EU rules that require countries with public debt above the 60% of GDP threshold allowed by EU law to cut the excess by 5% a year. Cyprus, another of the bloc’s most indebted countries, saw its debt rise to 102.5% of GDP from 95.8%.
Portugal, which was also bailed out during the eurozone’s debt crisis, saw its debt fall to 121.5% of output from 124.8%, while Belgium’s debt declined to 102.0% of GDP last year from 103.4% in 2017.
French public debt was stable at 98.4% of output, while the country’s budget deficit dropped to 2.5% of GDP from 2.8% in 2017.

The Gas Exporting Countries Forum’s (GECF) Monthly Gas Lecture in Doha focused on climate change and was led by two experts from Unesco and Qatar University.

The lecture held at the forum’s headquarters was a result of the collaboration between Unesco’s local office and Qatar University.

In his introduction, GECF secretary-general Dr Yury Sentyurin said, “It is not because we are in this industry that we are not focused on the environment. Quite the contrary. Natural gas is the cleanest fossil fuel and contrary to what some people’s perception is, one of the safest fuels overall. Compared to other fossil fuels, natural gas releases the lowest amount of carbon dioxide into the air after combustion, in fact, 50% less than coal and 20%-30% less than oil.”

“We consider it as our duty to act within the limits of our authority to reverse the consequences of climate change,” Sentyurin added.

Donia Abdelwahed, programme assistant (Science) at the Unesco Cluster Office for GCC and Yemen provided an introduction on Unesco’s work in the field of natural resources management and response to climate change.

Donia said, “We are all to a certain extent responsible for climate change and its impact on the environment. As a society we are all jointly suffering its consequences too.”

She pointed out that “it is part of Unesco’s role to urge stakeholders to strike a balance between development and preservation so that future generations can enjoy the same things we have been able to.”

In the light of their work towards achieving the UN’s Sustainable Development goals, an objective shared by the GECF, Unesco’s Qatar office is collaborating with Qatar University on preservation of the coral reef ecosystem in Qatar.

In line with this, the second part of the lecture was done by Dr Radouan Ben-Hamadou, associate professor (Marine Science) and head, Department of Biological and Environmental Sciences at Qatar University.

The lecture entitled “The use of decommissioned oil and gas platforms for the restoration of the coral reef ecosystem in Qatar” was introduced by Donia.

Ben-Hamadou’s presentation explored the feasibility of the ‘rigs-to-reefs’ concept in Qatar, which turns decommissioned oil and gas platforms into artificial reefs.

He said that even though corals can adapt to extreme environments, they have “reached a breaking point” and are “dying at a rapid rate”.

But he also mentioned that before any changes can be suggested, they need to understand the working of the ecosystem.

This is why they have been working for several years in collaboration with all stakeholders, including industry, to see how man-made structures can be turned from a threat into an opportunity.

Great strides have been made in the process and the opportunity could be a win-win situation for all parties involved, as the rigs-to-reef project will not only restore the ecosystem but could also provide significant savings on decommissioning costs for oil and gas companies.

GECF said, “Considering the forum represents 19 gas producing and exporting countries, jointly covering 70% of the proven global gas reserves, this research is clearly relevant to the GECF. Therefore, in his closing remarks, Sentyurin expressed his support of the initiative and his desire to enhance the Secretariat’s collaboration with Unesco’s Doha office.”

Chevron Corp yesterday said it will buy oil and gas producer Anadarko Petroleum Corp for $33bn in cash and stock in a deal that doubles down on its bet on US shale and propels the company into the ranks of the world’s “supermajor” crude pro- ducers. The deal makes Chevron the sec- ond-largest major by crude produc- tion, behind Exxon Mobil Corp, up from fourth. It expands Chevron’s role in two areas where US energy output is surging — shale from the Permian Ba- sin of west Texas and New Mexico, and liquefi ed natural gas (LNG) — which have helped make the US one of the world’s largest energy exporters. “Chevron now joins the ranks of the UltraMajors — and the big three be- comes the big four,” said Roy Martin, senior analyst at consultants Wood Mackenzie. “The acquisition makes the majors’ peer group much more polar- ised. ExxonMobil, Chevron, Shell and BP are now in a league of their own.”

US crude production stands at a record 12mn barrels a day (bpd), and the nation is the third-largest producer of LNG, the super-cooled fuel that is see- ing record demand as a cheaper, cleaner alternative for countries that still rely heavily on coal for power generation. Chevron’s pledge to restrain expendi- tures has make it a favourite among en- ergy stocks, with its shares up 13.8% this year. It plans to sell some $15bn in assets over time to off set the Anadarko deal. Still, investors sent Chevron shares down 5.2% to $119.44 yesterday. Chev- ron chief executive Mike Wirth called the deal a “great fi t” for the company. “This is really about creating share- holder value,” Wirth said in an inter- view. “It’s a great combination.

That’s what drives this.” The deal is the oil industry’s largest since Royal Dutch Shell bought BG Group in 2016, and it sparked speculation that other shale producers are in play. Shares of Apache Corp, which also has extensive acreage in the Permian Basin, rose 1.8%, while Pioneer Natu- ral Resources Co jumped 9%. With oil prices surging this year, Chevron and larger rival ExxonMobil have been in- creasing investment in the Permian Basin, the most prolifi c shale oil fi eld in the country. Their eff orts coincide with a pull- back by the smaller companies that revolutionised the industry through advances in horizontal drilling and hydraulic fracking. They have had to curtail spending due to investor dissat- isfaction with weak returns. Chevron, which already has 2.3mn acres in the Permian Basin, said the Anadarko deal would give the com- bined company a 75-mile (120-km)- wide corridor across the Permian’s Delaware basin, on the Texas-New Mexico border. “We will now see Chevron emerging as the clear leader among all Permian players, both in terms of production growth and as a cost leader,” said Rys- tad Energy head of analysis Per Magnus Nysveen, noting that Anadarko’s acre- age is in the “sweetest spot” of the Per- mian’s Delaware Basin. Anadarko also has a Mozambique LNG project, part of one of the indus- try’s largest planned current invest- ments, which Wirth said he still ex- pects to move to fi nal approval “sooner rather than later” this year.

Expenses from that project are ex- pected to reach $4bn over several years. The tie-up with Anadarko adds to Chevron’s deepwater investments in the Gulf of Mexico and gives it a stake in growing oil and gas production in the US Rocky Mountains in Colorado. At the end of 2018, Exxon and Chev- ron accounted for about one-fi fth of Permian output, where produc- ers pump around 4mn barrels per day (bpd) currently. IHS Markit expects it to hit 5.4mn bpd in 2023, more than the total pro- duction of any Opec country other than Saudi Arabia. “It will be a continuous shift toward larger companies in basically all seg- ments of the shale industry,” said Ar- tem Abramov, head of shale research for Rystad Energy. Shares of Anadarko surged 32% yes- terday morning, refl ecting the 39% premium off ered by Chevron compared to Thursday’s closing market price. The $65 per share off er was struc- tured as 75% stock and 25% cash. The deal includes taking on $15bn of Anadarko’s debt.

A rebound in oil prices poses a risk to India’s benign inflation expectations that last week allowed the central bank to deliver its second rate cut of 2019.

With crude at a five-month high, many investors are turning less confident about the Reserve Bank of India’s pace of monetary easing, though a slowdown in economic growth and subdued inflation still support an easing bias.

The low headline print gave Governor Shaktikanta Das and the rate-setting panel the space to cut rates by 25 basis points each in February and April to support the economy. Some economists see room for one more reduction provided food and fuel costs don’t spike. Data on Friday showed headline inflation quickened to a five-month high of 2.86 percent in March from 2.57 percent in February.

The RBI last week cut its inflation forecast to a range of 2.9 percent to 3 percent in the April-September period, compared with a February projection of 3.2 percent to 3.4 percent, while seeing price growth this year within its 4 percent medium-term target. It separately cut economic growth forecast to 7.2 percent for the year that began on April 1, down from 7.4 percent previously.

“The recent rise in crude prices, if sustained,” could pose a challenge to both economic growth and inflation outlook, said Dharmakirti Joshi, chief economist with Crisil Ltd. in Mumbai.

Forecast for Brent, the benchmark for half the world’s oil, has been lifted on the back of production cuts, and the RBI sees prices being pushed up further should the U.S.-China trade tensions be resolved swiftly. The two sides are nearing a trade deal, with talks aimed at clinching one within the next month continuing.

A recent study by the central bank showed a $10 rise from $65 a barrel will lead to a 49 basis points increase in headline inflation, while a similar increase from $55 a barrel would give around a 58 basis-point boost to consumer prices.

Oil’s charge higher has also offset any gains from a rising currency on imported inflation. The rupee climbed 2.3 percent against the dollar in March, making it the best performer in Asia. The currency is up more than 7 percent from its October low, leading to a view among economists like Kotak Mahindra Bank Ltd. Economist Upasna Bhardwaj that some of the impact from the rising currency could help ease inflation.

A 2018 working paper, co-authored by Monetary Policy Committee member Michael Patra, showed that a 1 percent change in the exchange rate translates into a 15 basis-point move in headline inflation over a period of five months.

“We see room for 25 basis points of rate in 2019 given the benign near term headline trajectory,” Bhardwaj said. “Nonetheless, the trajectory on crude oil price increase needs to be watched closely.”

Still, others see the rupee’s role being countered by oil.

“It appears on balance that the recent hardening of oil prices would have negated the impact of rupee appreciation to a large extent,” said Gaurav Kapur, chief economist at IndusInd Bank Ltd. in Mumbai.

The head of LNG Canada said he does “not see a single scenario” that would stop the nation’s largest infrastructure project from getting built, dispelling concerns that the $30bn gas export facility is at risk of mounting opposition from pipeline foes.
The liquefied natural gas project in northern British Columbia was approved by Royal Dutch Shell Plc and four Asian partners in October after obtaining the support of the province and 20 First Nation groups. But it continues to face a legal challenge disputing the constitutionality of the project’s approval, as well as protests by a group of indigenous holdouts.
“I do not see a single scenario that would cause the construction of this pipeline to be stopped,” Andy Calitz, LNG Canada’s chief executive officer, said in an interview in Vancouver.
TransCanada Corp is planning to build the pipeline that will carry the gas from western Canada’s prolific Montney shale formation to the coastal export facility in Kitimat. The whole project – including the gas fields, pipeline and liquefaction terminal – fall within British Columbia and was authorised by the provincial regulator.
But a private citizen in Smithers, Michael Sawyer, mounted a legal challenge saying the pipeline is a federal undertaking and should have sought approval from the National Energy Board. The federal regulator agreed in December to consider the jurisdictional challenge and has requested evidence from the parties involved with final oral arguments set for March.
“It’s a complex world – the paths are not clear,” Calitz said. Any decision by the federal regulator could later be appealed in the courts. “But what I am clear about is that this pipeline, by the time that happens, will be in advanced construction.”
Separately, TransCanada is seeking to sell a stake in the pipeline project. That move was long contemplated and doesn’t indicate that there are growing concerns about the project’s risks, Calitz said.
“It has always been a part of the financing strategy for the project,” Calitz said. “It has no impact on either the construction or the capacity or any other aspect of the project.

Almost 1,500 miles from Moscow, the tiny port of Sabetta nestles in a desolate Russian Arctic peninsula. A former outpost for Soviet geologists, it’s now the site of Russia’s most ambitious liquefied natural gas project, operated by a company that only entered the market just over a year ago.
Several times a week, a giant tanker leaves this remote place carrying the super-chilled fuel to buyers in Europe and Asia. It’s not the only LNG plant beyond the Arctic Circle, but it’s by far the largest.
Novatek PJSC, the main shareholder of the Yamal LNG plant, says plans for further projects will transform Russia into one of the biggest exporters of the fuel within a decade. Already the world’s top exporter of pipeline gas and second-biggest shipper of crude oil, exports from Sabetta are giving Russia another conduit into the world economy for the country’s unrivalled energy resources.
“Russia can be in the top four main LNG exporters,” Novatek’s chief financial officer Mark Gyetvay said in an interview in London.
Novatek has demonstrated that it’s possible to produce and liquefy the fuel in such harsh conditions at competitive prices and ship it to markets thousands of miles away in Europe and Asia. That’s helped by receding Arctic ice which is allowing a specially built fleet of strengthened tankers to ship fuel along Russia’s northern coast.
President Vladimir Putin has been a long-standing supporter of developing oil and gas resources locked under the region’s permafrost. When opening the first production train of the Yamal LNG project in late 2017, Putin said the region gives Russia the opportunity to take up the fuel’s “niche it deserves.”
“We can boldly say that in this century and the next, Russia will expand thanks to the Arctic,” he said at that time.
Novatek, whose biggest shareholders include Russian billionaires Leonid Mikhelson and Gennady Timchenko, as well as French energy giant Total SA, became Russia’s top LNG producer after starting up its plant in the Yamal peninsula almost two years ago. The facility reached its full capacity at the end of 2018, ahead of schedule, doubling Russia’s share of the global LNG market to 8%.
The gas producer has aggressive plans to command a 10th of the global market by 2030, Gyetvay said, and position Russia as one of the world’s largest exporters alongside the US, Qatar and Australia.
All three of Yamal LNG’s production units, with a combined actual capacity of 17.5mn tonnes a year, are now online. Novatek is attracting partners for a second plant, the so-called Arctic LNG 2 project, which is expected to come online in 2022.
The company is also considering commissioning a third facility and may increase its LNG production target for 2030 by about 20%, to as much as 70mn tonnes a year.
Novatek’s resource base at two Arctic peninsulas – Yamal and Gydan – allows the company to raise production volumes to as much as 140mn tonnes a year in future, according to its chief executive officer Mikhelson.
Russia, the world’s largest gas exporter, has been slow to join the global LNG boom as it has focused investment on pipeline supplies to Europe. Until recently, the country had just one liquefaction project in operation, the Gazprom PJSC-led Sakhalin 2 project near Japan with an annual capacity of about 10mn tonnes.
The country has now taken an interest in the market for tanker-borne fuel amid growing global LNG demand and more difficult relations with its customers in the European Union.
Russia’s Energy Ministry pegs total gas in place within the region at about 210tn cubic meters, or over 70% of the nation’s total. Novatek’s Arctic gas reserves are “conservatively” estimated at about 3.3tn cubic meters, Gyetvay said.
“We believe that Russia could be the fourth or even the third” biggest holder of LNG production capacity, said Karen Kostanian, Moscow-based oil and gas analyst for Bank of America Merrill Lynch.

https://www.gulf-times.com/story/628789/Russia-eyes-greater-energy-dominance-as-Novatek-ta

President Vladimir Putin kept his options open on whether to extend Russia’s joint oil-production cuts with OPEC beyond June, saying he wanted to continue cooperation with the group but also highlighting the many uncertainties in the market.

Russia is comfortable with current oil prices, which rose to a four-month high above $70 a barrel in London on Monday, Putin said at the International Arctic Forum in St. Petersburg on Tuesday. The president also said he doesn’t support an “uncontrollable” increase in the cost of crude that could hurt his country’s other industries.

“We’ll coordinate with OPEC and take a decision depending on the market situation,” at the next meeting in June, Putin said.

Russia, one of the architects of the deal between the Organization of Petroleum Exporting Countries and its partners, has taken a wait-and-see approach on whether to extend the cuts. The political situation in Venezuela, Libya and Iran will need to be considered before a decision is taken, Putin said. Saudi Arabia, which has cut output more than agreed, doesn’t plan to deepen its curbs as the markets are “healthy.”

“Of course, we are closely monitoring the market together with our partners, first of all, with the main oil producers, Saudi Arabia and countries of the Persian Gulf,” Putin said.

Venezuela, Iran

U.S. sanctions have eliminated a significant volume of oil exports from Venezuela and Iran, helping drive up the price of international benchmark Brent crude by more than 30 percent this year. Meanwhile, Libya’s output has been frequently disrupted as armed factions battle for political supremacy.

The Russian president also highlighted the possibility that any of those countries could become a bearish influence on prices. If the U.S. were to seize Venezuelan crude and sell it on the global market, or decide to loosen sanctions on Iran to foster a political compromise, inventories could start to increase again, Putin said. The situation in Libya could also normalize, allowing the country to boost exports, he said.

Russia will also take into account its domestic oil companies’ plans while deciding on the future of the OPEC+ deal, Putin said.

“We understand that output shouldn’t stop, investment should come into the sector, otherwise that also may create problems both for us and global energy,” Putin said.

https://www.bloomberg.com/news/articles/2019-04-09/putin-keeps-options-open-on-possible-extension-of-opec-oil-cuts

The world’s biggest energy companies are finally ready to invest in new gas export projects. Now they just need to figure out who will build them, and for how much.
After four years of belt-tightening, oil and gas firms are expected to start spending again, with as much as $144bn of investments in new liquefied natural gas developments in line to be approved by the end of this year. Meanwhile, the engineering, procurement and construction sector that erects these projects has been weakened by the cost-cutting, with shrinking order books and solvency questions.
While the order binge could provide a lifeline to EPC companies, it may see too many projects chasing too few builders, increasing risks for energy firms seeking to keep costs under control. In the last LNG building boom, for instance, projects in Australia alone went over budget by a combined $40bn.
“We have a new wave of LNG projects coming and a decimated construction sector,” said Saul Kavonic, an energy analyst at Credit Suisse Group AG. “There’s real risk as we go into this next wave that engineering and construction constraints mean a return of project delays and cost inflation.”
Natural gas is core to future growth for energy giants, with consumption seen growing faster than oil and coal as policies shift toward lower carbon emissions. Royal Dutch Shell Plc and Exxon Mobil Corp have in the past six months sanctioned new LNG plants in Canada and Texas, the first final investment decisions since 2015 for onshore greenfield projects. The amount of new production capacity investments this year could set a record, according to Wood Mackenzie Ltd.
That’s welcome news to oil and gas EPC companies, which have seen their order books dry up since the oil price crash in 2014. Six of the top publicly traded firms had a combined backlog of more than $120bn in 2014. That fell to about $66bn last year, according to filings from the companies, which now number five after an acquisition.
“The market has gone through a shake-up,” said Peter Coleman, chief executive officer of Australia’s Woodside Petroleum Ltd, which is planning an expansion at its Pluto LNG project. “Some people are still in balance sheet repair, and it hasn’t finished yet. We are watching that very closely.”
The sharpest pain is being felt by Chiyoda Corp and McDermott International Inc, which have suffered from cost overruns related to their work on the Cameron LNG project in Louisiana. Chiyoda in February requested financial aid from Mitsubishi Corp, its largest shareholder, and the company plans to be more selective when choosing future LNG projects and joint venture partners, Tomoyuki Tsukamoto, head of investor relations at Chiyoda, said by phone. McDermott declined to comment.
“We have to recognise that our workforce and our capacity are limited,” Tsukamoto said. “We have to select the most appropriate projects for us.”
A weaker construction sector will be good for the remaining EPC companies, as they’ll have more leverage when it comes to negotiating, said Kavonic. That will mark a reversal from the past few years, when spending cutbacks forced service and construction firms to slash margins and take on more risk to win a limited number of jobs.
While construction companies have worked to lower costs for customers, some energy firms anticipated those numbers would keep dropping, Bechtel Group Inc LNG General Manager Darren Mort said in a phone interview. As projects get closer to final investment decisions, companies are reining in those expectations for more appropriate pricing levels, he said.
“Some of the aggressive numbers don’t seem to be getting the traction that they thought they would,” Mort said. “If they really had some reality to them, we’d be seeing FIDs on that basis.”
San Francisco-based Bechtel is privately held, so its financial data aren’t as accessible as some competitors. The firm has avoided any recent high-profile construction problems and Mort said its finances and capabilities remain strong.
The earlier a company is able to start construction, the less chance that firms push for higher rates, Credit Suisse’s Kavonic said. Shell’s decision to go ahead with LNG Canada in October means the project, which will be built by Fluor Corp and JGC Corp, could be more competitive globally by missing any cost inflation, he said.“The faster projects FID, the better rates they’ll get from the EPC contractors,” said Fauziah Marzuki, an analyst with BloombergNEF in Singapore. “Once the contractors realise they’ll be a bit stretched, they’ll start to factor in bigger contingency costs and margins.

https://www.gulf-times.com/story/628787/Big-Oil-haunted-by-cost-risks-as-144bn-LNG-tab-loo