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    Quality and quantity in the EPC boom [NGW Magazine]

Summary

Too many projects chasing too few engineers can create cost inflation – as Australia saw. Might history repeat itself, or have the projects anticipated the squeeze? (This article is featured in NGW Magazine Vol. 3, Issue 18)

by: William Powell

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Featured Articles, Africa, Americas, Asia/Pacific, Middle East, Europe, Premium, NGW Magazine Articles, Volume 3, Issue 18, Exploration & Production, Liquified Natural Gas (LNG), Australia, France, Netherlands, Peru, Russia, Saudi Arabia, Spain, United Arab Emirates, United States

Quality and quantity in the EPC boom [NGW Magazine]

A looming shortage of engineers, top-rank construction site teams and growing lead times for supplies could delay major infrastructure projects, according to some of the largest engineering, procurement and construction (EPC) companies.

The cost overruns and time blow-outs for LNG projects in Australia last decade were legendary, but could repeat themselves in the US in the coming years, as a big cluster of LNG export projects line up for final investment decisions. Many are in a small region of the US Gulf Coast, making for challenging logistics in terms of sourcing materials and labour without pushing up costs.

But they will have to take their place in the growing queue, a panel comprising senior engineering, procurement and construction companies told delegates at the Gastech conference in Barcelona in mid-September. There are sizeable ethylene, mining and other heavy engineering projects in the US and Saudi Arabia, for example, that all need the same kinds of pumps, compressors and other equipment as the oil and gas industry. “Are we ready for the boom?” asked Fluor’s CEO David Seaton, questioning the ability to find the equipment – and the people ready to assemble it, perhaps in incongenial surroundings, for today’s generation of young engineers – at an affordable price.

There is also a sense that the supply side has not been enjoying the higher free cash flow available to the majors as oil continues to rise. Some of the gains might have to be shared equitably, as the French major Total has demonstrated with its 15% pay award for offshore workers late September.

Quality or timing?

Execution risk remains high if the project developer focuses solely on keeping the dollars/ton of annual output capacity as low as possible. But the need to be early to market is greater than ever, since the likelihood is that not all the discussed projects are needed. They are chasing mostly the same customers, so there is a sense of urgency.

This creates tension between the client’s demands for speed and the EPC contractor’s need to earn money with a good margin. This can lead to corners being cut in the construction, design or the materials used. And contractors might sign up to projects they do not have the full capacity to execute, or try to save money by contracting out parts of the project to lower-cost, perhaps worse regulated industries in other countries.

Senior executives also warned against rushing into signing contracts without considering the risks if they failed, and whether their customers’ balance sheets might be better able to manage the risks. “We do not have a crystal ball to see what will happen in the next four or five years,” said McDermott’s CEO David Dickson. “We have concerns about the supply chain, the construction of equipment and the delivery of services.” He said project developers needed to put numbers in a spreadsheet but they did not then allow for the unexpected.

Fresh from the takeover of CB&I which completed in May, he said that company had lost a lot by wrongly estimating the costs and the schedules, discounting as a result. “We want to avoid the mistakes made in the past,” he said (see below).

Simplification

A partial solution to the tightness is standardisation instead of bespoke parts; and modularisation, instead of building on site. This latter practice has taken a lot of the costs out of the business since the 2014 oil price collapse. Another is to widen the range of manufacturers on the customer’s list of acceptable counterparts: if the best company for a certain item is not on the list, there should be the means to include it.

Being the cheapest was not necessarily the answer as so many other factors would determine success: saving $50mn early on could cost hundreds of millions later, warned Bechtel’s oil, gas and chemicals head Alastair Cathcart.

Seaton said that pushing for the fastest scheduling time and getting things out of sequence as a result was a risk.

Seaton also said that US immigration laws could limit the number of skilled workforce and hence the EPC sector’s ability to execute. “We have the obligation to attract and train staff, we need the ability to put them into the fray early on,” he said.

In this context, the UK government’s advisers on immigration said mid-September that a cap on highly-skilled migrants should be scrapped if the UK leaves the European Union next year, while the government itself released an updated list of ‘shortage occupations’ which includes mechanical and electrical engineers in the oil and gas industry.

KBR CEO Stuart Bradie said that the industry had been slow to pick up on innovation: customers have been driving down the $/mt cost but what was really wanted was mature customers who were looking for certainty. “This last cost cycle has honed the EPC: we will not sign up to unachievable costs or schedules. Most heroes die on the battlefield,” he said, agreeing with Seaton’s remark that “enthusiasm is not a strategy.” Several of the executives drew the distinction between avoiding approaches that had never been tried before; and the need to push back against customers who did not want to change their system – a common approach when considering standardisation.

The CEO of Spain’s Tecnicas Reunidas Juan Llado Arburua, which with a partner has recently been awarded a $1bn contract to expand Abu Dhabi-based Adnoc LNG’s facilities, said the EPC sector was trained to take risks but it was not trained to act as insurance companies.

Novatek cuts costs at Arctic

According to Kvaerner, which did three studies for Novatek’s planned Arctic 2 LNG but lost out on front-end engineering and design to Italian Saipem, using a gravity-based system (GBS) will cut costs dramatically relative to the onshore Yamal LNG plant. The plant may be built offsite and towed to its place of work, saving the need to build accommodation in a remote area of the Yamal Peninsula.

It can use any technology and made of concrete, it is resistant to ice; by definition there is also no need to buy land; and its maintenance is relatively light. It may have a design life of 50-70 years. It may take five years from EPC award to first LNG, and could be shorter than onshore.

Novatek’s CFO Mark Gyetvay said construction costs would be a third lower, thanks to the GBS. Overall project costs are lower, at an estimated $25.5bn, compared with the $27bn of the smaller Yamal LNG. It will also use different gas reserves.

Having trans-shipment capacity at Kamchatka, on the opposite side of Russia, would also represent a saving: CEO Leonid Mikhelson said the more expensive Arc-7 winterised tankers should be only used where needed: in the Arctic Sea. The journey from Kamchatka to Japan (three days) or to southern China (seven days) would be done by cheaper tankers, and should save about 7% on shipping.

The company is planning 20mn mt of storage at Kamchatka, in the far eastern Russia, in two equal phases, the first 10mn mt  to be ready no later than the start-up of production at Arctic 2 LNG. That is enough to hold more than half a year’s output from Yamal LNG. Novatek did not explain why so much is needed or how the costs would be recovered, given the relatively short time that a cargo of LNG is stored before being reloaded and taken to the regasification terminal. Ship to ship transfers are also an option and something Novatek has done at Montoir in northern France, Rotterdam in the Netherlands, and Zeebrugge in Belgium.

McDermott’s costly purchase

McDermott CEO David Dickson explained to NGW the company’s reason for buying CB&I: “Our principal area of expertise has been from the wellhead to the beach or the refinery while CB&I has experience of the LNG business: that was one of our reasons for buying CB&I,” he said. Combined, the two companies have turnover of $10bn/yr and employ 40,000 people. “The job today is to get the merger settled and integrate the two companies and look at the strategic plan,” he said.

Among CB&I’s achievements are Peru LNG export plant and the US liquefaction trains at Cameron and Freeport; it is also part of the consortium in the Anadarko liquefaction project, onshore Mozambique. However, since the purchase, McDermott has pulled back from a major liquefaction project in the US, suspecting CB&I price might have been too low for the risks involved.

Another possible market for cheap feedstock in a relatively high oil price environment is gas-to-liquids. Dickson though says that technology only works economically when oil is around the $100/barrel mark or higher. South African Sasol cancelled a $13-15bn gas-to-liquids (GTL) project in Louisiana last November.

The Anglo-Dutch major Shell, which also abandoned a GTL project in Louisiana but a few years before Sasol, is nevertheless still considering GTL in east Africa. “The technology belongs to Shell and our role would be to support it, work on it so it makes economic sense, and convert it into pre-Feed and Feed and then progress to EPC,” he said. But generally customers are not driving costly and lengthy GTL projects, and Shell declined to comment on the status of its work with McDermott.

CB&I had bought Lummus from ABB in 2007 and that gave it the technology needed for GTL, refining, petrochemicals and plastics. “We are working with Saudi Aramco converting crude to plastics, helping them to improve the efficiency. We are very heavily involved in refining technology, which is now about raising the efficiency of plants. We are also working on raising the standardisation of equipment, modularising it and improving productivity,” he said.

McDermott was awarded a key $500-750mn project late 2017 on the $3.4bn Total-operated Tyra gas redevelopment offshore Denmark – much of which will be done in 2020-21 – that it said marks a return for McDermott to North Sea EPC work after a long absence.

The US contractor has been working on digitalisation for some time, taking the lead on projects such as the BP-operated Tortue field offshore west Africa. “We have created a digital twin of the offshore facilities for BP so that it can check onshore the offshore status of operations. It can direct a worker to any part of the site offshore to where there might be a problem. We are seeing a lot of interest in that: digitalisation gives a lot of control on the scheduling cost of large EPC projects and it allows lifecycle management,” he said.

McDermott has not become involved in the gas advocacy side of the industry: “We are not an operator: we are there to deliver solutions. We are not there to fly the flag for gas: that is our customers’ job. We focus on developing technology that they need for that, such as stopping flaring and designing carbon capture and storage projects and power generation from CO2.”


STILL IN THE FRAME FOR RIO GRANDE

CB&I had been working on an exclusive basis for NextDecade to convert the front-end engineering and design (Feed) into an engineering, procurement and construction contract for the 27mn mt/ year Rio Grande LNG project.

Rio Grande includes plans for up to six liquefaction trains, with a nominal output capacity of 4.5mn metric tons/year. Dickson explained: “They wanted us to sign for the EPC price by the end of June but we had only completed the takeover on May 10, and that was not enough time to evaluate a multi-billion dollar contract. We are still in the running for the NextDecade EPC if we can put together a plan at the right cost and we believe we could present a lower-risk execution – it is a very good project but we are no longer the sole source.”

NextDecade told NGW that both sides had deliberately decided not to proceed with the signature of the EPC contract and it entered into talks with other companies. It announced September 4 that Fluor, Bechtel and McDermott were in the running, the latter uniquely however needed a joint venture partner. “We had to ensure we had a contractor with the right technical and financial capacity for Rio Grande,” a spokesman told NGW, “and McDermott agreed it needs a partner.” The other two bidders however do not, he said. NextDecade has access to very cheap feedstock gas near existing or planned infrastructure. The planned plant is north of the Mexican border. Dickson said: “We would use a construction yard just south of the border and ship the modules north – Tampico is only two days’ sailing away. Nafta talks between the US and Mexico are almost complete, there won’t be any tariff issues on imports.

“In the US the question is, what can we do with the gas? It is technically free, as the International Energy Agency executive director Fatih Birol says. The US can create value from liquefaction. The alternative is to break it up and reform it into chemicals, as the Middle East is doing.”