The Fuse

Cancellations, Delays of Capital-Intensive Projects Pose Long-Term Risks

by Matt Piotrowski | October 26, 2017

Limited investment in the oil sector over the past few years has coincided with major projects getting canceled or delayed and costly exploration ventures failing to produce any hydrocarbons at all. When capital-intensive projects fail to bear fruit, there tends to be knock-on effects as the entire industry grows more cautious. Companies become more aware of risks of failure since their projects require costly upfront investments, long-term commitments, and the ability to deal with complex conditions. Today’s challenging investment environment heightens the risks of a supply gap or bottlenecks forming in the coming years.

When capital-intensive projects fail to bear fruit, there tends to be knock-on effects as the entire industry grows more cautious.

Even though the growth in U.S. shale has added flexibility to the oil supply system, the world still needs massive investment in conventional fields, midstream projects, and downstream capacity to keep supply shortages from emerging. The investment cycle is important because price reactions tend to follow it with a lag of 5-7 years, meaning today’s limited spending and canceled projects portend tighter conditions early next decade. By 2022, the global oil market will need a large amount of new production to meet demand growth and offset declines of current fields. This reflects the large amount of capital investments that are needed to avoid a structural deficit. A gap of only 1-2 million barrels per day (mbd) would have an outsized impact on prices.

Midstream projects run into trouble

Large projects have had trouble along the supply chain, in the upstream, downstream, and midstream sectors. Earlier this month, TransCanada scrapped its Energy East and Eastern Mainline pipeline projects and wrote off a massive $1 billion. The pipeline was expected to ship crude produced in Western Canada to refineries in the eastern part of the country to cut reliance on imported oil. The company pointed to regulatory hurdles for gutting the $15 billion project, but weaker oil prices and the project’s economics were also likely a factor given the high price tag. No matter what the reason for TransCanada nixing the pipeline, the huge write-off underscores the amount of risk and massive capital necessary for any oil infrastructure project.

TransCanada is also facing another big decision. It will decide in December whether to move forward with the Keystone XL pipeline that would ship crude produced in Alberta to the U.S. Midwest. The estimated cost is approximately $8 billion, rising by 50 percent versus previous estimates. The Trump administration approved the pipeline earlier this year, reversing former President Obama’s 2015 decision to halt the project on environmental grounds. But rising costs and shifting market conditions may prompt TransCanada to not move forward on the project that was first proposed in 2008 and commissioned in 2010.

Some wells come up dry

In the upstream sector, cutbacks on capital expenditures have received the most attention during the price downturn. But companies have also moved forward with capital-intensive projects that came up empty. Shell abandoning the Arctic is the biggest example in this area. The Dutch-Anglo major spent $7 billion on just one well and found only a small amount of hydrocarbons.

Cutbacks on capital expenditures have received the most attention during the price downturn. But companies have also moved forward with capital-intensive projects that came up empty.

Other capital-intensive upstream investments also came up empty. A number of international oil companies drilled “dry holes,” an exploratory well that holds no oil or gas, in different markets: ExxonMobil in Liberia; Statoil and ConocoPhillips in Angola; and Tullow in Norway. Ophir Energy drilled seven dry holes in sub-Saharan African in three years. Even before Shell’s venture in the Arctic, drillers in Alaska hit dry holes a number of times over the decades.

These projects hurt companies individually, and also change industry thinking on a broader level. Executives and investors question the wisdom of looking for resources in areas that are difficult to navigate (i.e., deepwater or the Arctic) and drilling costs are high. Some estimates say that dry holes cost companies $100 million each.

Downstream projects get canceled or ‘delayed indefinitely’

In the downstream sector, projects have also been canceled. A number of companies may not completely shelve a project, but instead say it is “delayed indefinitely” as a result of changing economics. As demand grows by more than 1 million barrels per day every year, limited downstream capacity additions could tighten refined product markets in the future, increasing prices for consumers.

As demand grows by more than 1 million barrels per day every year, limited downstream capacity additions could tighten refined product markets in the future, increasing prices for consumers.

“A lot of refining projects are explored, reach a certain stage, and then the economics change,” John Auers of downstream consultancy Turner, Mason & Co. told The Fuse. “Many are never officially canceled. They just fade away and eventually disappear.”

Some of the most notable cancellations or deferrals have occurred in Latin America, where countries want to reduce their dependence on imported fuel from the U.S. In Brazil, Petrobras halted work on two large refineries totaling 900,000 barrels per day amid rising costs and the inability to find investors. The scandal-plagued company is still moving forward with its Comperj refinery in a partnership with China’s CNPC, but costs have soared. Total costs for the project have reached $13 billion, up from initial estimates of $8.5 billion.

Similarly, Ecuador sought to pour $12 billion into a refining and petrochemical complex, but it’s unclear if the project will ever go forward. The country’s financial problems as a result of low oil prices make the possibility of the new refinery even more questionable. In Mexico, as the country attempts to revamp its energy sector and open it to foreign investors, refining infrastructure needs to be upgraded. The country has significantly increased its dependence on imports of gasoline and diesel from the U.S. One of PEMEX’s biggest projects is developing a new coker at its Tula refinery to increase its production of gasoline. But given the high costs associated with building new coking capacity, PEMEX needs partnerships to help finance the project. This has delayed the necessary work from advancing.

In Asia, Vietnam last year stopped two refinery projects. The Can Tho plant failed to begin construction eight years after it received a license. The other canceled project, a partnership with Thailand’s state company PTT, would have been a $20 billion facility, but it was gutted due to numerous delays. The country is moving forward with one new refinery, a $7.5 billion plant in Nghi Son—but its start-up has been continually delayed and is scheduled to now begin production in 2018.

The U.S., the center of the most sophisticated refining network in the world, is not immune to higher costs and delayed projects. In 2015, the first grassroots refinery was completed in the U.S. since the 1970s, but the owner sold the North Dakota plant last year to Tesoro for a loss. The cost for the facility turned out to be 40 percent higher than original estimates. Meridian Energy Group, meanwhile, has also planned to build a refinery in North Dakota, but the company has yet to receive a Permit to Construct from the state. The project is facing local opposition since it would be located near the historic Theodore Roosevelt National Park, prompting questions about whether it will be built. These two projects reflect the cost and regulatory hurdles needed to overcome in order to build a refinery.

Two new refineries are being planned in West Texas to take advantage of rising shale output in the Permian. The companies, MMEX Resources and Raven Petroleum, estimate the plants to cost $500 million each, but they face financing hurdles. Like other downstream projects, they may never go beyond the strategic planning process. Arizona Clean Fuels, which developed plans to build a new refinery in Yuma in the 1990s, has contended with rising costs, a long permitting time, and stricter environmental regulations—but never officially canceled the project. Even scheduled projects—such as condensate splitters—at existing facilities have either been nixed or run into increasing costs.

The emerging supply gaps

Today’s environment portends shortfalls at some point with increased price volatility.

The world still needs massive investment—all along the supply chain—to keep future price spikes from occurring and for countries to improve their energy security. With companies having to scrap projects due to rising costs and regulatory issues or coming up dry after pouring billions into projects, many in the industry will be more restrained in making investments. This means today’s environment portends shortfalls at some point with increased price volatility.

ADD A COMMENT