Lower for longer oil prices are leading operators to reconsider the structure of project contracts. Many are leaning toward supplier-led solutions to cut costs and boost reliability. Karen Boman reports (First published in the January 2018 OE, access the full issue here).
The days of the bloated mega-project are long gone. The downturn has been severe and long-lasting and exploration and production (E&P) companies are seeking to make project costs more sensible and generate long-term savings.
At higher commodity prices, it wasn’t difficult for E&P companies to make profit under the traditional approach of contracting services, says Edward Hernandez, partner – vice president, Americas, with io Oil & Gas Consulting. E&P firms also worked on projects in a traditional stage-gate approach as they received funding to get through each stage.
Quad 204 was one of seven BP projects brought online in 2017, and boasts the largest harsh environment FPSO.
Photo from BP.
“There really wasn’t a lot of shared risk (amongst operators and suppliers) in upstream development; the E&P company owned the risk and managed their own internal economic model,” Hernandez says. With no share in the asset once production flowed, Hernandez says this was the primary reason why mega-projects experienced schedule and cost overruns. “Engineering companies were selling man-hours, not really solutions, and their stake in the overall project outcome was limited,” Hernandez says.
However, “it’s a fact that if you look at most mega-projects, more than two-thirds of upstream sector projects were over budget and late,” Hernandez says. “There were many projects where engineering was achieved over a year period and then the design changed and engineering was redone and redone. There was a lot of recycle.”
Now, E&P companies must cut costs to make projects economically feasible at lower breakeven oil prices. Companies are looking to include suppliers earlier in the development process to ensure that the asset will operate to design life or longer, and use tried and true designs over bespoke.
For example, when BP sought to expand its Thunder Horse project in the US Gulf of Mexico (GoM), the supermajor made sure to standardize components and work with contractors that had previously provided equipment on the field.
Steve Raymer, Thunder Horse South Expansion project manager, BP, told OE in May 2017, that for the project, BP wanted to use what Thunder Horse already had. “We had an existing subsea tree design,” he said. “We had existing subsea equipment, the same manifold design. We did not redesign anything from scratch where we had the opportunity to use something that we already had.”
But to get to this point, Hernandez says that operators had to look at their work processes to see where they were leaving money on the table.
“We (io) saw that everybody has their own standards,” Hernandez says. Companies then sought to reduce goldplating by using off-the-shelf solutions. They also revisited their portfolios, opting to focus on the top three or five projects to reduce their exposure to so many different types of developments, he adds (Click the link to read BP's discussion on "Collaborative contracting").
E&P companies then re-examined how they worked with suppliers, Hernandez says, who also were suffering from the market downturn, to ensure they could get a standard solution for the best price for the desired outcome. This included encouraging suppliers to invest in equipment leasing to increase their chances of landing contracts.
Financing models also are being framed such that consortium members are risking not only their profits, but also potential loss in the asset’s commercialization. This brings more certainty to project outcomes since each member must ensure success to guarantee they do not lose money, Hernandez says.
In terms of project economics, each of the stakeholders have to give up some profit, but may still come out ahead because of greater certainty, less delays, less recycle, and lower cost of capital than private equity.
“Obviously, there is always an added cost of finance or shared investment, but now with the consortium approach, the license holder can keep a big sum of money off of its balance sheet and use for other developments,” Hernandez says.
For deepwater projects, E&P companies traditionally would go to an engineering company to design all subsea infrastructure, from wellhead to risers, and an entirely separate engineering company to design facilities, infrastructure and so on, Hernandez says. These firms would do a tremendous amount of design work, then go to the E&P company, saying that this is what each part of the project should look like. But, when E&P firms would speak directly with the suppliers and contractors, they would often tell E&P firms they couldn’t provide exactly what was specified, requiring changes in engineering due to excessive cost in manufacture, construction or installation.
The deepwater Gunashli platform in the Caspian Sea, offshore Azerbaijan, where BP is trialing one of two digital product lifecycle management pilots. Photo from BP.
Today, io sees E&P firms going straight to suppliers, constructors and installation companies to conduct front-end engineering packages, many times with a financing scheme around it. These companies then come to the table with the best technical solution and financing arrangement with a shared risk approach. Once a project comes onstream, a deferred payment or toll payment plan is put in place. This creates an environment in which the supplier is a partner in a project, and there is incentive for all parties to achieve overall project success.
Since the downturn in 2014, many service firms have banded together to deliver integrated service packages. For instance, in 2015, OneSubsea aligned with Subsea 7 to combine subsurface expertise, subsea production systems, subsea processing systems, subsea umbilicals, risers and flowlines systems, and life-of-field services. In 2014, Aker Solutions and Baker Hughes (now BHGE), agreed to a subsea production solutions alliance. OneSubsea, Schlumberger, and Helix Energy Solutions also formed the Subsea Services Alliance. Forsys Subsea was a joint venture between FMC Technologies and Technip before the two merged.
E&P firms also are using a consortium approach. One example is the CA-KU-A1 gas compression platform project in Mexico. This is a project where Mexico’s state-owned operator Pemex tendered the “contract” to various proposed consortiums of equity, facilities, EPC, and operations in order to build, own and operate gas compression facilities offshore for a 15-year term before turning the facilities back over to Pemex.
“This purpose is to move forward a very strategic project with limited cash flow. In this case, the consortium puts up the capital and gets paid back on a fee per volume of gas basis. We initially performed a gap and risk analysis on the contract model for our parent companies (io is a consultancy spun out of GE Oil & Gas and McDermott),” Hernandez explains. The project was awarded to Dragados Offshore.
Getting projects off the ground
Most offshore projects that have been sanctioned as of late have been backed by the majors, who have the capital resources and ability to easily raise funds. They are also the most active in taking advantage of cost deflation, says Angus Rodger, Asia-Pacific upstream research director, at Wood Mackenzie.
However, small- and mid-cap companies are struggling to attract the financing needed for offshore projects, partly due to uncertainty over future commodity prices. Many entered the downturn carrying debt, adding to the struggle to get new projects going, Rodger says.
In 2014, deepwater was considered too high cost. But, overcapacity in the service and drilling marketplaces has resulted in costs falling quickly. Over time, the industry also has become leaner, and companies like Shell and BP are lowering costs by learning to drill deepwater wells faster. These structural learnings are making deepwater in the GoM and offshore Brazil much more competitive, Rodger says. As a result, companies are looking at incremental projects, such as subsea tiebacks, that can compete with tight oil investments.
The majors also have maintained a relatively steady level of development drilling in the GoM and offshore Brazil, allowing them to continuously learn how to drill better wells. In the GoM, 30 deepwater development wells were drilled this year, with 30 development wells planned for 2018 and 32 planned for 2019, says Imran Khan, senior research manager, at Wood Mackenzie. Shell leads deepwater GoM development drilling, with Anadarko and Chevron also active as well.
This continued learning is necessary as it takes longer – perhaps two to three years, often more – for real, structural cost savings to emerge in deepwater, Rodger explains. In basins where drilling has been more sporadic or ceased completely since 2014, companies considering project sanctioning “can’t instantly go back and just drill wells 20% better than they did three years ago.” This makes it harder for cost deflation to happen across the board, and means some basins are competing stronger than others for the scarce amount of available capital.
Rodger believes that companies will continue to focus on projects with smaller footprints, as it will be harder to convince both banks and investors that spending vast sums on big greenfield projects, particularly outside of North America, is prudent financial strategy. “Still, the majors can’t just do small-cycle, high return investment projects forever, so over time we will still see the best big projects bubble to the top and move forward,” he says, albeit with capital deployed in a more cautious, phased fashion.
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