Upstream delivery finally hits the mark

According to industry analyst Wood Mackenzie, upstream oil and gas companies are increasingly delivering major capital projects on time and on budget.

The successful execution of projects is of crucial importance to an upstream industry adapting to lower prices. The downturn forced companies to evaluate and improve how they manage their major capital investments.

The sector has a reputation for missing projected deadlines. The top 15 project overruns of the last decade were a cumulative USD80 bn over budget. “The scale of under-performance was staggering,” said Angus Rodger, research director, Wood Mackenzie. “Surveying the last decade of project delivery, the average development started-up six months later than planned and USD700 mn over budget. That is a huge amount of value destruction.”

However, recent performance indicates that the tide has turned. Wood Mackenzie said there is a growing list of mid to large-scale projects that have been delivered on target over the past 12 months. This includes areas previously notorious for cost blow-outs, such as the Arctic and Caspian. Examples of improved execution include deepwater developments such as BP’s West Nile Delta and Atoll, along with Eni’s Zohr and Cape Three Points projects; LNG (Novatek’s Yamal), shallow-water gas (BP’s Shah Deniz Phase two) and subsea tie-backs such as Woodside’s Persephone and Wintershall’s Maria.

Better upstream execution

Wood Mackenzie said the transition to a simpler, lower-cost business model has aided new project delivery. Most recently, Shell brought its deepwater Kaikias field in the Gulf of Mexico onstream nearly one year ahead of schedule. Wood Mackenzie identified six key factors, that in most recent cases, combined to create better project execution:

1. Spare capacity through the supply chain. This leads to better performance and lower costs. For example, in some basins, such as the Gulf of Mexico and pre-salt Brazil, drilling efficiency has improved dramatically;

2. Service sector collaboration and alignment on contracts, albeit mostly for projects developed in northern Europe;

3. Improved project management. Companies have more people looking at fewer things, while under-utilised service companies can offer their best teams for each major contract;

4. Greater corporate discipline. Tougher pre-final investment decision (FID) screening and more stringent hurdle rates have increased attention on execution and cost control;

5. More pre-FID planning. More contracts are ‘signed and sealed’ pre-sanction, often with preferred partners versus putting everything out to bid;

6. Reduced scope. More tie-backs and brownfield projects are using existing infrastructure.

While there have been a few large-scale oil developments sanctioned in recent years, it is not many by industry standards. It is in the LNG sector where there are clear signs that companies are re-engaging with giant, capital-intensive projects. This includes new developments in Canada, Mozambique, Qatar, Papua New Guinea, Russia and Australia.

“There is a looming wave of big pre-FID LNG developments building on the horizon, all aiming for sanction between 2018 and 2020. After a fallow period in new LNG project sanctions, and megaprojects in general, the next 18 months will likely see a step change. This will be the real test of whether the industry has addressed the issue of poor delivery,” Rodger said.

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BP's West Nile Delta project. Photo credit: BP
BP’s West Nile Delta project. Photo credit: BP

Mexico eyes up major energy projects

A number of major Mexican oil, gas and energy projects have taken shape in the past week. Italian oil major Eni expects to invest USD1.8 bn in three oilfields offshore Mexico by 2040, according to a development plan approved by Mexico’s oil regulator.

The plan covering the Amoca, Mizton and Tecoalli shallow water fields is the second of its kind approved by Mexico’s National Hydrocarbons Commission (CNH). The deal follows the 2013 agreement that has led to more than 100 oil and gas contracts being awarded to international investors in a series of auctions.

Eni forecasts initial crude oil production of 8,000 barrels per day (bpd) in early 2019 from its Amoca and Mizton fields, and ramping up to 90,000 bpd by 2022, according to CNH.

Initial production at the Tecoalli field is expected in 2024. The development plan includes 32 wells, four platforms, plus a gas pipeline connecting to the coast, as well as the acquisition of a floating, production, storage and offloading (FPSO) vessel.

Eni expects to take the final investment decision (FID) in the fourth quarter of 2018, although some initial investments to fund long lead items and to start the construction of the first platform for the early production have already been authorised.

Mexico unveils investment strategy

The Mexican government also unveiled a USD16 bn investment plan to boost the domestic oil production, refinery capacity and hydropower generation. President-elect Lopez Obrador pledged to increase oil production by 600,000 bpd in two years. He said about USD9.5 bn would be invested in refinery modernisation projects. USD8.6 bn of the budget will be allocated to a new refinery in Dos Bocas, Tabasco.

Meanwhile, McDermott also won a contract award from Pemex for subsea pipeline flowline installation in support of its Ayatsil field. It is located 50 miles (80.5 km) northwest of Ciudad del Carmen in the Bay of Campeche offshore Mexico.

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Oil majors evolve and emerge stronger

Tom Ellacott, head of corporate research at Wood Mackenzie, highlights how oil majors have repositioned themselves since the 2014 oil price crash, and how they will emerge stronger from the market downturn.

He said that despite severe pressure on finances and low oil prices, majors have seized the moment during the downturn to adjust their business models. Today, their prospects are markedly improved with high-graded portfolios, improved production profiles, and more resilient future cashflows.

Oil majors adapt

First, the majors reacted to the industry downturn by selling non-core assets – some USD27 bn worth, such as Shell’s disposal of Canadian oil sands assets. The assets divested were typically low margin or peripheral upstream assets.

Secondly, the majors have dominated investment decisions approved since 2014 and account for two thirds of reserves sanctioned for extraction. “Final investment decisions (FID) are happening because of lower costs, much of it cyclical but with structural elements; project re-scoping and re-engineering are showing the way forward,” said Ellacott. However, more work is needed to create a pipeline of big, commercial deepwater projects.

Chevron, Shell and ExxonMobil also have exposure to US tight oil and are all ramping up spending, said Ellacott. Tight oil and unconventional gas will become increasingly important to these three companies – contributing at least a quarter of ExxonMobil’s total output by the mid-2020s.

Acquisition trail

Mergers and acquisitions (M&A) seen in the sector have shared traits. The deals have been made to bolster existing portfolio strengths, and include low breakeven/long life assets.

Shell’s acquisition of BG Group in 2016 was the standout transaction, which closed at approximately USD82 bn. The deal positioned Shell in prime Brazil oil projects while expanding its liquefied natural gas (LNG) business.

ExxonMobil’s acquisition of BOPCO, in a deal estimated to be as much as USD6.6 bn, elevated its modest Permian exposure to a leading growth platform. Papua New Guinea and Mozambique are long-life developments and broaden the company’s options for medium-term LNG development.

In terms of exploration, Ellacott says  ExxonMobil is the standout performer notching up five discoveries in Guyana, holding over 2.5 bn barrels. The wider industry’s lack of appetite for conventional exploration leaves the door wide open for the majors to reload portfolios.

ExxonMobil, Total, Statoil and Eni acquired vast positions in under-explored basins during the downturn – much of it with low commitments, providing options for medium-term resource renewal.

DRO opportunities

Finally, the majors have all been active in accessing discovered resource opportunities (DRO). Oil companies bid to develop and produce existing, large oil or gas fields, negotiating terms with the host government. Total (Abu Dhabi, Iran), BP (Abu Dhabi, Azerbaijan), Chevron, ExxonMobil and Statoil (Azerbaijan) have all signed concessions in the last three years.

Wood Mackenzie research suggests returns from DROs awarded since 2014 are attractive, and in some cases better than can be achieved through mergers and acquisitions. This may indicate the industry downturn has shifted negotiating power towards the operator.

“We are witnessing the early stages of the industry preparing for the long haul – the challenges of the energy transition and the attendant risks of peak oil demand, disruption from renewables and electric vehicles, and perhaps sustained pressure on oil and gas prices,” Ellacott said.

Wood Mackenzie's Tom Ellacott discusses how oil majors have adapated to their new environment.
Wood Mackenzie’s Tom Ellacott discusses how oil majors have adapted to their new environment.

TechnipFMC wins ENI Ghana E&P deal

TechnipFMC has been awarded a contract by ENI Ghana E&P for the onshore part of the Offshore Cape Three Points development of the Sankofa field, offshore Ghana.

TechnipFMC will perform the project management, engineering, supply, construction and commissioning for the onshore receiving facilities, located in Sanzule.

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Source: TechnipFMC