The evolution of oil prices over the last 50 years feels like a roller-coaster ride—a sequence of steep hills, unexpected jumps, and sharp drop-offs. For the world economy, this bumpy ride has been anything but fun.

Take 1973, when oil prices skyrocketed unexpectedly. Within two years, US unemployment had doubled, leaving the nation deep in the throes of a recession. (The rest of the world soon followed.) Similar tailspins occurred in 1979 and 1991, both caused by sharp increases in oil prices.

“The few recessions where we can name the culprit are oil-driven recessions,” explains Sergio Rebelo, a finance professor at the Kellogg School.

But what makes oil prices so volatile? Despite the high stakes, economists have not had enough data to answer this question. Do shocks to suppliers yank prices upward, or is shifting demand from developing countries part of the problem? And will this volatility continue?

Rebelo set out to answer these questions with fellow economists Gideon Bornstein, a PhD student at Northwestern, and Per Krusell of Stockholm University. The researchers had one critical advantage: a massive oil industry dataset containing historical information on every oil field in the world.

“Those data allowed us to take a close look at the inner workings of the oil industry for the first time,” Rebelo says.

With the data in hand, they have teased out how supply and demand each contribute to the volatility of oil. Counterintuitively, they also predict that fracking—the controversial technique of fracturing underground rock to tap its oil reserves—will eventually smooth out the market’s jagged roller-coaster ride.

“It’ll take out the peaks and troughs of oil prices,” Rebelo says.

A Data Treasure Trove

Three years ago, Rebelo and his coauthors procured a proprietary dataset covering some 14,000 oil fields operated by 3,200 companies since 1900. (For the purposes of their analysis, the researchers zeroed in on the period from 1970 to 2015.)

The data set, which is meant to be used by energy companies, provides unprecedented amounts of information, including not only the amount of oil produced annually, but which countries are producing it, and—crucially—the dollar amount that companies invest in their oil fields each year.

With these data in hand, the researchers set out to draw some basic facts about the oil industry over the last half century. “For instance,” Rebelo says, “we didn’t know much about the investment behavior of this industry.”

When they charted year-to-year changes, the authors found that the amount of resources energy companies invest in oil exploration and extraction was more volatile than oil prices. And when oil prices increased, investment in the oil industry increased along with them, as energy companies sought to capitalize on the higher profit margins.

Curiously, though, those investments did not seem to immediately affect the amount of oil extracted. “We show it’s very difficult to produce more oil in the short run,” Rebelo explains.

Suppliers can boost oil production in one of two ways: by extracting more quickly from existing oil fields, or by finding and drilling new fields. But there are upper limits to how fast oil can be extracted—and developing new wells takes time. The upshot: companies cannot boost production quickly in response to high oil prices.

“In our data, there’s an average lag of 12 years between investment and production,” says Rebelo.

Ask your average person, and you will likely get an answer that revolves around suppliers, Rebelo says. “When you read the Wall Street Journal, it sounds like OPEC—Saudi Arabia in particular—by producing more oil or less, can really manipulate the market.”

Indeed, a quick look at the data revealed that at certain moments, suppliers had effectively cut production—like in 1973, when the oil-producing Arab member nations of OPEC placed an embargo on oil exports to the US. During this period, “we see oil fields getting shut down,” Rebelo says.

But were these moments telling the full story? To find out, the researchers created a mathematical model to estimate the fraction of all oil-price fluctuations that could be attributed to shifts in supply.

What they found is that abrupt changes in supply explain only about half of the jumps in prices.

Rebelo notes that turning oil production on or off is a serious decision that costs millions of dollars. “It’s not like you have a tap, like you’re in the bathtub and you can put in more warm water or less,” he says.

That difficulty in adjusting supply in the short run explains why a full half of oil-price fluctuations were due to changes in consumer demand, which moved up and down according to the changing needs of the world economy.

Shifts in oil investment, on the other hand, appear to be driven primarily by fluctuations in demand. Rebelo says that this is due to the lag between investment and production, combined with the fact that the kinds of supply-side interruptions that ratchet up oil prices tend to be short-lived.

When the first Gulf War started, for example, oil production stalled in Iraq and Kuwait, leading prices to soar. But Rebelo says it did not make sense for companies to try to capitalize on those high prices by finding new oil sources. “By the time that new oil comes online, the shock will be gone, and the prices will be back to normal.”

Demand, on the other hand, tends to be more stable, and therefore provides a better incentive for investment, says Rebelo. “If China is going to grow more than expected for another decade”—and thus experience a steadily growing thirst for oil—“then it makes a lot of sense to invest.”

“By the time that new oil comes online, the shock will be gone, and the prices will be back to normal.”

Fracking and the Future

Where does fracking fit into this picture?

“Fracking started at a time when there was a lot of volatility in oil prices. So fracking and volatility tend to be linked,” Rebelo says.

But his new findings defy the consensus that fracking exacerbated volatility. Instead, the study suggests that fracking could eventually help stabilize oil markets. Fracking, which is short for hydraulic fracturing, involves the high-pressure injection of water into the ground to extract oil and natural gas. It is an environmentally controversial practice, in part, because of concerns over contamination of nearby groundwater.

Because it takes an average of 12 years to produce oil from an investment, companies have not historically been able to quickly capitalize on high prices. Today, however, that is no longer the case. The researchers found that fracking firms can produce oil much more nimbly than traditional firms.

“It takes on average about one year between investment and production in a fracking field,” says Rebelo.

As such, when oil prices rise, fracking firms will be able to take advantage of many booms before they end. And by producing more oil, they will put downward pressure on oil prices. Conversely, when oil prices are low, they are able to more easily halt production, driving prices upward.

In total, the authors calculate that fracking will reduce oil-price volatility by an astounding 65 percent.

Rebelo warns that we are still in the midst of the fracking transition, so it might be a while before the full effect can be seen. “We don’t have a situation where the fracking industry is yet mature,” he says. (The paper did not look at the potential environmental costs of fracking.)

Rebelo and his coauthors are interested to see if their prediction is borne out. Until then, they are glad to have helped shed light on such an important sector of the economy.

“We had this unusual opportunity to study the mechanics of the oil industry,” he says.

New sources, mobility, and industry fragmentation are set to disrupt the system. Change is afoot in the energy system. Soaring demand in emerging markets, new energy sources, and the likely growth of electric vehicles (EVs) are just some of the elements disrupting the status quo. It is hard to discern how the aftershocks will affect the extraordinarily complex network of sectors and stakeholders. 

An array of energy technologies seems poised for a breakthrough. Within two decades, as many as 20 new energy sources could be powering the global economy, including fuel cells; small, modular nuclear-fission reactors; and even nuclear fusion. Fossil fuels will still be part of the mix, but renewables’ share is likely to grow owing to environmental concerns, further cost reductions that make renewable energy more competitive, and demand for electricity. Electricity demand is expected nearly to double by the middle of the century, propelled primarily by economic development in China and India. By 2050, electric power, which can be generated by low-carbon energy sources such as wind and solar, could account for a quarter of global energy demand.

An economy based on so many technologies is unprecedented. The Industrial Revolution relied on steam engines powered by wood, water, or coal. In the 20th century, oil and gas were added to the mix, then nuclear fission. The abundant choice on the horizon raises new dilemmas. For example, where should governments focus investment and research efforts? Most are minded to keep their options open for the time being in order to satisfy demand, as well as for cost and environmental considerations. Over time, though, they might have to choose. Uncertainty about how funding will be shared between new technologies could slow their development. And if technologies are in contention, governments might struggle to secure reliable energy supplies. Securing those supplies, however, will no longer necessarily depend on access to oil, gas, and coal reserves—access that has long colored geopolitics. In tomorrow’s world, access to the technologies that harness resources such as wind, sun, water, or heat from the earth’s core is likely to matter most.

The way we move around our ever-spreading cities is set to be transformed by technology and the drive to reduce pollution, congestion, and carbon emissions. Center stage is the electric vehicle. EVs still have high upfront costs compared to conventional vehicles, but thanks in part to the falling price of batteries, they may be competitive by the mid-2020s. By the mid-2030s, our research shows they could account for between 27 and 37 percent of new-vehicle sales, depending on the extent to which regulation, technology, ride sharing, and self-driving vehicles further reduce costs and boost EV popularity.

These factors present a range of potential consequences. For example, global demand for liquid fuel used in light vehicles could fall by between two million and six million barrels a day (a drop of between 8 and 25 percent), helping to make the chemical industry, not transportation, the source of demand growth for these fuels. Oil companies might need to rethink their strategies as a result, perhaps acquiring more acreage to support production of naphtha or natural-gas liquids—key feedstocks for chemical plants. If mobility patterns change rapidly, city planners could find themselves in a matter of years with expensive parking lots that stand empty. And if the cost of moving around cities in self-driving, shared vehicles falls to the point where it matches the cost of using public-transport systems, passenger numbers and revenues for these systems could fall, potentially making them harder to maintain.

For the past half century, large players have dominated energy markets. Today, technology is spawning many smaller operators at the same time as new sources of capital emerge. Public markets and governments were once the only investors in the energy sector. But with many governments now cash-strapped, pension funds and private-equity firms are taking up the slack. In the past five years, private-equity firms invested more than $200 billion in the sector, matching new ideas and business models with capital hungry for returns. This fragmentation is diminishing the power of scale to shape markets.

A large number of shale gas and oil producers in North America, for example, make uncoordinated decisions about supply, challenging the ability of the Organization of Petroleum Exporting Countries to influence prices. Large utilities have to factor into their strategies the growing number of cities, businesses, and households that generate their own energy from renewables, often selling surplus back to the grid. And governments could find it harder to implement effective regulation. Rules around drilling, water disposal, and public health and safety are already being tested in North America because of the speed at which the number of oil and gas producers has grown. And distributed power generation has sparked regulatory questions about how to charge grid users equitably. Assuming it is wealthier consumers who can afford to install solar panels, the cost of maintaining the grid falls to a smaller number of less affluent households.

As scale in some areas diminishes in importance, agility takes precedence. With so many players interacting in so many different ways in so many different locations, it is harder than ever to predict the future. Billion-dollar investments in assets that must be productive for three decades or more become far too risky. Instead, companies will need to make smaller initial investments and be able to adjust their strategies rapidly as circumstances change or local conditions dictate. Local differentiation carries increasing competitive weight. In oil and gas, service providers increasingly tailor their offerings not at the country or even regional level, but basin by basin; power companies may need to consider different strategies for different cities depending on the choice of feedstock and the numbers of residents and businesses producing their own energy.

Ironically, fragmentation is likely to encourage more partnerships. While these are already commonplace in oil and gas, where companies split the cost and risk of large capital projects, one might assume that smaller assets with lower costs and risk would have less need of them. Yet with a rising number of participants in an energy system where local differentiation counts, the reverse could be true.

The speed and scale of change in the energy system will depend on the pace of technological advancement—in establishing cheaper, more efficient power storage, for example—and on government policies and regulation. Unless system participants start to plan now, they could find themselves left adrift.


Falling costs and rising acceptance are promising signs, but the industry needs to keep improving. The landscapes of Rembrandt glow with the great painter’s rendering of light. And they are distinctive for another reason: windmills are everywhere. As far back as the 13th century, the Dutch used windmills to drain their land and power their economy. And now, 800 years later, the Netherlands is again in the vanguard of what could be the next big thing, not only in wind power but also in the global energy system as a whole: offshore wind.

In December, the Netherlands approved a bid for its cheapest offshore project yet—€54.50 per megawatt-hour, for a site about 15 miles off the coast. Just five months before, the winning bid for the same site was €72.70. Denmark has gone even further, with an auction in November 2016 seeing a then record-winning bid of €49.90 per megawatt-hour, half the level of 2014.

Europe, which has provided considerable economic and regulatory support, accounts for more than 90 percent of global capacity. As a result, Europe now has a maturing supply chain, a high level of expertise, and strong competition; it is possible that offshore wind could be competitive with other sources within a decade. By 2026, the Dutch government expects that its offshore auctions will feature no subsidies at all. But it might be even sooner: in the April 2017 German auction, the average winning bid for the projects was far below expectations, and even less than the Danish record set only six months before. Some of the bids were won at the wholesale electricity price, meaning no subsidy is required.

The industry still has a way to go compared with current costs: the levelized cost of electricity (or LCOE, a metric that incorporates total lifetime costs and expected production) for an offshore park installed in 2016 is expected to be €120 to €130 per megawatt-hour, about 40 percent more than onshore wind in comparable regions and 20 percent more than solar photovoltaics (PVs). Conventional sources, such as coal and gas, are currently even cheaper in many locations.

The technology thus still comes at a premium. Costs are higher because building at sea requires more materials for foundations and piles, while rough weather conditions make installation and maintenance expensive. Offshore wind parks also require expensive connectors to the inland transmission network.

While prices for all renewables will continue to drop, offshore wind is at an earlier stage of development, so its prices can be expected to fall further, faster, thus improving its competitive position. When different wind farms are made comparable by normalizing for water depth, site preparation, subsidies, and other factors, this is already happening.

One caveat: these are prices, not actual costs. Until the parks are actually built and running, it is impossible to know if they can be profitable at these prices. But companies would not be competing so fiercely—the Dutch auction saw 38 bids—if they didn’t think they could be.

Offshore wind has a number of advantages that can help to compensate for its higher costs. Specifically, it can be sited near densely populated coastal areas, where land can be costly, and its higher wind speeds produce more power per unit of capacity. Offshore also complements solar PV, because it produces well in winter when load is highest, creating a stable production profile, day in and day out, throughout the year. Offshore wind produces at 35 to 55 percent of capacity, versus 10 to 20 percent in the Northern Hemisphere for solar PV. Finally, the not-in-my-backyard (NIMBY) effect is considerably less when the nearest turbine is miles away at sea. However, when offshore parks are not placed far enough offshore, NIMBY can become an issue, with complaints of visual or horizon pollution.

Factors outside the industry’s control, including low interest rates and low steel prices, have played a major role in cutting costs. But so has better technology, especially the trends toward larger turbines and greater durability. Larger turbines harvest more of the wind, which make them more efficient. For many years, 3- to 4-megawatt turbines were standard; now 8- to 10-megawatt models are common, and by 2024, 13- to 15-megawatt models will likely hit the market. This reduces the cost per megawatt. Even as turbines have become larger, they have also become better. In the 1990s, the expected lifetime of offshore wind parks was only 15 years; now it is closer to 25 years, and new sites project an operational lifetime of 30 years.

The offshore wind industry is still in the process of growing up and becoming more professional. There are a limited number of fit-for-purpose suppliers and vessels, for example, and owners, contractors, and subcontractors are still learning how to work together. There aren’t that many industry professionals who are experienced at completing offshore wind projects, and as parks get bigger, the need for such expertise is greater.

Scale itself will help. With more offshore farms being built, the economics of scale are beginning to emerge, in both logistics and along the supply chain, including such things as sharing crew transfer vessels, helicopters, and coordinating jack-up barges across assets and operators for major component replacements.

For offshore wind to fulfill its considerable potential, it needs to raise its game everywhere. The most promising opportunities are in design, procurement, and execution; operations; and innovative financing.

Value-focused design involves working with all stakeholders, internal and external, to systematically identify technical improvements and value-creation opportunities. For example, the developer and supplier can get together to define the minimum technical solutions, ruthlessly eliminating high-cost, low-value specifications. Design optimization is another possibility. The standardization of components and designs across a single offshore wind site, or a fleet of them, reduces the costs of construction, installation, follow-up engineering, and debugging. Manufacturers can then use modular techniques to adapt to specific situations in a cost-efficient way.

Contracting and procurement could add up to 5 to 10 percent in cost savings. Contracting strategy begins with understanding exactly what is expected of the contractor with respect to technical delivery and added value, the complexity of engineering, and fit with the design requirements. Based on a rigorous risk assessment, the developer seeks the best delivery model and pricing structure and optimizes the contract terms to be consistent with this strategy. By brainstorming with the candidate contractors, then assessing their risk profiles, one onshore wind company saved at least 15 percent on the final proposals.

Applying procurement-excellence tools, such as clean-sheet costing, and creating a clear “package procurement” road map, can help to find the right price for the right product. At several companies, this rigorous purchasing approach has translated into 15 to 20 percent price reductions in the procurement of turbines.

By their nature, offshore wind platforms are costly to build, so improving project execution offers another avenue to cut costs, by 3 to 5 percent. Integrated performance management ensures that data is collected and shared throughout the project—from the owner to all the suppliers and all the subcontractors. Lean construction comprises a set of principles, operating practices, and methods that improve execution while minimizing waste. In offshore wind, examples include reducing delays in preparing foundations and increasing standardization in the assembly of components.

Offshore wind developers vary widely in their operations and maintenance performance. The best drive down costs while maintaining high availability and safety standards; the rest tend to focus on availability and do not pay enough attention to costs. We estimate that for many projects, improved operations could translate into savings of as much as €10 per megawatt-hour in LCOE. Improved operations start with the relentless application of advanced analytics to improve predictive maintenance, condition monitoring, and component replacement.

Second, operators should establish flexible work contracts for offshore sites that are difficult to access, share technicians across sites, and find the right balance between internal and external technicians to contain labor costs while maintaining quality. Size and proximity to other parks does matter. Building new vessel-logistics concepts such as service-operation vessels, and sharing technicians and fleet with other sites (as done in the offshore oil and gas sector) adds a third opportunity to reduce costs.

A one-percentage-point decrease in the cost of capital brings a 5 to 10 percent improvement in LCOE for renewables. To realize this advantage requires investors having a thorough understanding of the real risk profile that offshore wind assets have compared with other renewable or infrastructure assets.

Another way to reduce financing costs is to make the sector more attractive to a broader group of investors. Offshore wind investments are relatively “chunky,” requiring hundreds of millions of euros per park, and “illiquid,” meaning they are difficult to sell without incurring high transaction costs. To overcome these challenges, other asset classes have devised alternative structures, such as publicly traded or private YieldCos; these have had their challenges but can still be attractive. The industry could also consider new structures, combining features such as publicly listed versus private structures, single asset versus broader portfolios, and single-technology focus versus cross technology.

The world’s first wind farm began operating in 1991: the Vindeby project featured 0.45-megawatt turbines. As of 2017, there is more than 14 gigawatts of cumulative installed capacity worldwide.

Other markets have taken note of Europe’s progress and are putting into place supportive regulation. China has made offshore wind part of its five-year energy plan. Korea, Poland, Taiwan, and a number of other countries are also considering offshore wind as part of their future energy mix. For example, a major project off the northeast coast of the United States is in the works.

Although in some areas of the world the LCOE of offshore wind may never become at par with, say, solar PV, the value it can bring—as less-intermittent baseload power generation near urban demand centers, offsetting supply deficits from solar PV in winter—can make it a valuable addition to the energy mix.

These brighter prospects have also led to increased interest from oil and gas companies, which are increasing their exposure to the sector. Offshore is a natural fit with their expertise in engineering and in executing complex energy projects in offshore locations.

Offshore’s considerable potential would be further enhanced if floating wind platforms could become cost competitive. Fixed-foundation wind parks have to be sited in relatively shallow waters; floating ones could be placed in deeper areas, farther from land, and could open additional markets. There is considerable research going on, with the first floating wind farm being built off the coast of Scotland.

Fast growth, increased investment, bigger parks, falling costs, and new technologies and markets: these are the trends that are defining the offshore sector. Put it all together, and it is fair to conclude that the wind is at the industry’s back.


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