Although the decision by the EU’s largest natural gas-producing country was not a huge surprise—I described about a year ago that it might be forthcoming—reduced Dutch production further reinforces the importance of completing the European internal market. That is essential in order to ensure that imported commodities can be shipped, and used, in all EU member states.

Author

Tim Boersma

Fellow - Foreign Policy, Energy Security and Climate Initiative

The decision

Minister Kamp has decided to cap Dutch annual natural gas production at 24 billion cubic meters (bcm), based on recommendations from the State Supervision of Mines (SSM) and the Dutch transmission system operator (TSO) Gasunie, among others. That is 3 bcm lower than the cap that is in place for this calendar year, which was announced in December 2015. The Dutch company Nederlandse Aardolie Maatschappij (NAM), which is jointly owned by Royal Dutch Shell and Exxon Mobil, would have preferred a different new cap. NAM had planned for 27 bcm of annual production for this year (in line with the ministerial decision), but had hoped that future production could rise again, up to 33 bcm per year.

This will not happen. The minister has in essence followed the recommendation for the lowest production level, and made a (for him) logical and safe decision. Further reducing natural gas production has full parliamentary support and most importantly satisfies popular demands and hopefully safeguards public safety. SSM had argued that based on recent experiences, fluctuations in gas extraction are believed to increase the chances of earthquakes, as a result of changes in pressure in the large Groningen field. More research is needed to better quantify those chances, but it is believed that production cannot exceed 27 bcm per year. To be on the safe side, SSM recommended a safety margin, leading to its advice of 24 bcm per year. The minister has adopted this production level for the next five years. Because of reduced production and expected low fluctuations (including seasonal swing), it is anticipated that seismic activity too will be reduced.

What’s next?

First, these plans have to be formalized by the minister, which will likely happen in the next couple of weeks.

Practically speaking, the operators (NAM) and regulators now have a clear operational framework. What remains is producing 24 bcm per year, monitoring effects of extraction, and further studying remaining uncertainties. Because the minister outlined the rules for the next five years, the topic can, notwithstanding new concerns, probably disappear from public and parliamentarian discussions. Fortification of houses in the area that has been most affected will continue.

For production in the Groningen field, the only thing that has really changed is the timeline. Natural gas production in the Netherlands has been in decline for a while, particularly when seismic activity increased, starting in 2013. However, many in government and industry initially underestimated the gravity of public concern, and bad public relations (in particular by NAM) turned the issue into a political hot potato, and subsequently moved the timeline substantially forward. Dutch production is now where conventional wisdom dictated it would only be a decade from now.

The Dutch do not consume all their natural gas at home, and a number of long-term export contracts with neighboring countries remain in place. The minister has confirmed that the Netherlands will adhere to these contracts, including when Dutch production will be further reduced in the future. This is because in the three countries that physically import Dutch gas—Germany, Belgium, and France—measures are being taken to prepare consumers for a switch to high caloric gas, rather than the (fairly unique) low caloric gas that comes out of the Groningen field. The Dutch TSO Gasunie has also indicated that increased efficiency and other measures will further reduce natural gas demand in Northwestern Europe going forward, making a transition away from Groningen gas easier to absorb.

Last year, the minister wrote that it would probably be necessary to build an additional nitrogen mixing station (that is required to converge gas qualities to avoid damage to equipment and machineries)—but at the moment, it is uncertain whether that will be built. Alternatively, the major gas storage facility in Bergermeer, owned by Abu Dhabi-based TAQA, could also replace the Groningen field to balance seasonal fluctuations (a role that Groningen historically played, but won’t in the future, as described before). It is not yet clear what approach will be preferred going forward, and how the costs will be divided. These and potential other loose ends are to be negotiated between the various stakeholders in the coming months.

Natural gas production from the Groningen field has now roughly halved over the last three years, and will not return to previous levels. This latest decision, therefore, truly marks the end of an era for the Dutch and for Europe more broadly.

      

 

 

The answer depends on who you ask. Presidential candidates, Washington think tank analysts, and ordinary citizens all give widely different answers to that question. In the United States, natural gas is sure to play an important role in the energy mix for the foreseeable future and has yielded several major economic, environmental, and health benefits in the short- and medium-term. Despite this, the image of natural gas has deteriorated in recent years, particularly within the environmental community. 

In a new policy brief, “Natural gas in the United States in 2016: Problem child and poster child,” Tim Boersma discusses the various sentiments surrounding the debate over natural gas, analyzing the data supporting or refuting these varied points of view. Additionally, Boersma discusses the role that natural gas can play as a bridge fuel to a low-carbon economy, outlining a policy and research agenda for the utilization of natural gas going forward.

      

 

 

In a recent Brookings paper, “Rooftop solar: Net metering is a net benefit,” Mark Muro and Devashree Saha contend that net metering is a net benefit for non-NEM customers.[2] I fundamentally disagree with their findings, and argue that NEM is not a net benefit; it is, in fact, a tariff that much of the time results in a subsidy to NEM customers and a cost shift onto non-NEM customers. As Executive Director of the Institute for Electric Innovation, a non-lobbying organization focused on trends in the electric power industry, I have followed this debate and written about it for several years.

Much of the talk about NEM focuses too often on the “value” of the energy that is sold back to the grid by a NEM customer. In reality, the amount of energy sold back to the grid is relatively small. The real issue is the failure of NEM customers to pay fully for the grid services that they use while connected to the grid 24/7, as shown in Figure 1.[3] Customers need to constantly use the grid to balance supply and demand throughout the day, and the cost of these grid services can be sizeable. In fact, for a typical residential customer in the United States with an average electricity bill of $110 per month, the actual cost of grid services can range from $45 to $70 per month–however, the customer doesn’t see that charge.[4] That means, in the extreme, if a customer’s energy use “nets” to zero in a given month because the customer’s private solar system produced exactly what the customer consumed, that customer would pay $0 even though that customer is connected to the local electric company’s distribution grid and is utilizing grid services on a continuous around-the-clock basis.[5]

Although exactly netting to zero energy in a month is highly unlikely, this example demonstrates the point that the customer would pay nothing, despite using grid services at a cost ranging from $45 to $70 per month. Over the course of one year, this customer could receive a subsidy resulting from NEM of between $540 and $840. Over the life of a private rooftop solar system, which ranges from 20 to 25 years, this is a significant subsidy resulting from NEM.

Granted, this is an extreme example, and most NEM customers will pay for some portion of grid services. However, the fundamental source of the NEM subsidy is the failure of NEM customers to pay fully for the grid services that they use 24/7, and the cost of these services can be quite substantial. When a NEM customer doesn’t pay for the grid, the cost is shifted onto non-NEM customers.[6] It is a zero-sum game; plain and simple. This is the elephant in the room.

This issue was directly addressed by Austin Energy when the company implemented a “buy-sell” arrangement for the private rooftop solar customers in its service territory. The rationale for the buy-sell approach is that the customer buys all of the energy that is consumed on-site through the electric company’s retail tariff and sells all of the energy produced by their private rooftop solar system at the electric company’s avoided cost. This addresses the “elephant in the room” because, by buying all energy consumed at the retail tariff, the customer does pay for grid services that are largely captured through the retail tariff. It is an unfortunate fact that under ratemaking practices today in the United States, the majority of fixed costs (i.e., grid and other costs) are captured through a volumetric charge.

Hence, I fundamentally disagree with the Muro/Saha paper–NEM does need to be reformed. NEM is not a net benefit; it is a tariff that the much of the time results in a cost shift onto non-NEM customers. One of the first studies to quantify the magnitude of the NEM subsidy was conducted by Energy+Environmental Economics (E3) for the California Public Utilities Commission (CPUC) in 2013. There was no mention of this analysis for the CPUC in the Muro/Saha paper. The E3 study estimated that NEM would result in a cost shift of $1.1 billion annually by 2020 from NEM to non-NEM customers if current NEM policies were not reformed in California.[7] A cost shift of this magnitude–paid for by non-NEM customers–was unacceptable to California regulators. As a result, California regulators set to work to reform rates in their state; many other states followed suit and conducted similar investigations of the magnitude of the NEM subsidy.

In reviewing NEM studies, Muro and Saha chose to focus on a handful of studies that show that net metering results in a benefit to all customers. In this small group of NEM studies, they included a study that E3 conducted for the Nevada Public Utilities Commission (PUC) in 2014–perhaps the most well-known and cited of the five studies included in the Muro/Saha paper. Very soon after the E3 Nevada study was published, the cost assumptions for the base-case scenario which showed a net benefit of $36 million to non-NEM customers (assuming $100 per MWh for utility-scale solar) were found to be incorrect, completely reversing the conclusion. The $36 million benefit associated with NEM for private rooftop solar turned into a $222 million cost to non-NEM customers when utility-scale solar was priced at $80 per MWh.[8] Today, based on the two most recent utility-scale contracts approved by the Nevada PUC, utility-scale solar has an average lifetime (i.e., levelized) cost of $50 per MWh, meaning that the NEM cost shift would be far greater today. In February 2016, the Nevada PUC stated that “the E3 study is already outdated and irrelevant to the discussion of costs and benefits of NEM in Nevada…”[9] Hence, because the E3 study for the Nevada PUC that the Muro/Saha paper included has been declared outdated and irrelevant to the discussion and because costs for utility-scale solar have declined significantly, that study does not show that NEM provides a net benefit.

No doubt there is an intense debate underway about NEM for private rooftop solar, and much has changed in the past two years in terms of both NEM policies and the growth of private solar projects:

• First, several state regulatory commissions now recognize that the NEM cost shift is both real and sizeable and that all customers who use the grid, including NEM customers, need to pay for the cost of the grid. As a result, many electric companies have proposed and state regulatory commissions have approved increases in monthly fixed charges over the past few years; this partially addresses the issue of NEM customers paying for the cost of the grid services that they use.
• Second and related, getting the pricing right for distributed energy resources of all types is important because we expect those resources to grow significantly in the future. Work is underway in this area and it is one focus of the New York Reforming the Energy Vision proceeding; but there is still much to be done.

By focusing on a select group of studies that show that NEM benefits all customers (as stated by the authors); by excluding the E3 study for the CPUC which was fundamental to the NEM cost shift debate; and by not providing an update on the NEM debate today, I believe that the Muro/Saha paper is misleading.

In the second part of their paper, Muro and Saha suggest some helpful regulatory reforms such as moving toward rate designs that “can meet the needs of a distributed resource future” and moving “toward performance-based rate-making (PBR).” Some electric companies have already implemented PBR or some type of formula rate and PBR is under discussion in several states.[10] Lawrence Berkeley National Labs is looking closely at this and related issues in its Future Electric Utility Regulation series of reports currently underway.[11]

Mura and Saha also suggest decoupling as a way forward–I disagree. In my view, decoupling is a not solution for private rooftop solar. Revenue decoupling is currently used to true-up revenues that would otherwise be lost due to declining electricity sales resulting from electric company investments in energy efficiency (EE). Decoupling explicitly shifts costs from participating EE customers to non-participating EE customers causing the same cost-shifting problem that is created by NEM. However, a fundamental difference is that the magnitude of the cost shifting onto non-NEM customers is on a much larger scale than the cost shifting due to EE. A recent study revealed that decoupling rate adjustments for EE are quite small–about two to three percent of the retail rate.^[12] In contrast, as described earlier in this paper, a NEM customer could shift a significant cost onto non-NEM customers (and the NEM cost shifting is essentially invisible to customers, which is one reason that NEM customers do not believe they are subsidized).[13]

Finally, Muro and Saha suggest that electric companies should invest in a more digital and distributed power grid. In fact, electric companies across the United States are doing just that. In 2015, electric companies invested $20 billion in the distribution system alone and this is expected to continue. Over the past five to six years, electric companies invested in the deployment of nearly 65 million digital smart meters to about 50 percent of U.S. households. In addition, electric companies are investing in thousands of devices to make the power grid smarter and more state-aware. Today, in states such as California, Hawaii, and Arizona, electric companies are investing to enable and integrate the distributed energy resources that are growing exponentially. And, in some states–where regulation allows–electric companies are offering rooftop solar or solar subscriptions to their customers.

No doubt, the electric power industry is undergoing a period of profound transformation–our power generation resource mix is getting cleaner and more distributed; the energy grid is becoming more digital; and customers have different expectations.[14]

Collaboration, good public policy, and appropriate regulatory policies are critical to a successful transformation of the power sector. In the context of this paper, this means reforming NEM so that private rooftop solar customers who use the energy grid pay for the grid. One straightforward approach is to require NEM customers to pay a higher monthly fixed charge thereby reducing the cost shift.[15] Ultimately the challenge is to make the transition of the electric power industry–including the significant growth in private rooftop solar and other distributed energy resources–affordable to all customers.

Lisa Wood is a nonresident senior fellow in the Energy Security and Climate Initiative at Brookings. She is also the executive director of the Institute for Electric Innovation and vice president of The Edison Foundation whose members include electric companies and technology companies.

      

 

 

Now that there are presumptive nominees for both major political parties, it’s an important moment to outline, in broad strokes, the positions of Secretary Hillary Clinton and businessman Donald Trump. We realize that Democratic Presidential candidate Bernie Sanders has not dropped out of the race, but note that it is fairly unlikely at this point that he would clinch the nomination.

Clinton: Building on the Obama legacy 

Secretary Clinton has laid out the most comprehensive and detailed energy and climate policy proposals of the candidates to date. They are in essence a continuation, and in some cases a further expansion, of existing White House policies under President Obama. The Secretary has stated that she wants the United States to be the “clean energy superpower of the 21st century.”

This starts with the notion that climate change is an existential threat, which the global community has to address as soon as possible. In order to do that, in her view, the United States needs to continue to show leadership on the international stage, as the Obama administration sought to do surrounding the Paris agreement in December 2015. This will require substantial reforms to expand low-carbon options, including nuclear energy to some degree, while tightly regulating fossil fuels (and gradually phasing them out). 

[S]he wants the United States to be the “clean energy superpower of the 21st century.”

The first casualty of this transformation is the coal industry, which Clinton has explicitly acknowledged. She presented a $30 billion plan to revitalize communities where coal production is currently an important industry and job creator, for example, and has campaigned with this message in various state primaries. Implicitly, Secretary Clinton does not seem to believe in the economic viability of carbon capture and sequestration in the United States—this is despite the fact that most analyses, including those of the Intergovernmental Panel on Climate Change (IPCC), suggest that this technology could be a cost-efficient tool in a wider carbon emission mitigation portfolio. 

Clinton sees natural gas as a bridge fuel, though at this point it’s not clear how long that bridge is. Questions remain about the role that natural gas can play in scenarios of deep decarbonization in 2030 and beyond. At the moment, the gas industry is rather nervous of the Secretary’s statement that she’d increase regulations on, in particular, the fracking industry—if her conditions came to fruition, there would very few places where fracking would continue. 

Secretary Clinton believes that oil consumption has to be cut substantially in the coming years, and she has suggested that new drilling in places like the Arctic, off the Atlantic Coast, and on federal lands would be discouraged or banned. She has previously opposed crude oil exports, though we would not anticipate a roll-back of existing policies (in December 2015, the Obama administration lifted the decades-old ban). 

Clinton foresees a new energy economy built on rapidly increasing shares of renewable energy, which should comprise 25 percent of the U.S. fuel mix by 2025 according to her plan (solar energy would be a key focus, with half a billion panels to be installed by the end of her first term). To facilitate this transition, she presented an elaborate energy infrastructure plan to modernize the U.S. grid and improve efficiency in reviewing and approving projects. 

Tax credits to support renewables would be continued under a Clinton White House, whereas fossil fuel subsidies would be phased out. Increased energy efficiency, including harmonization of vehicle efficiency and fuel standards, are high on her agenda as well. The Secretary also supports the Clean Power Plan that the Environmental Protection Agency under the Obama administration has launched, and which is currently on hold in the Supreme Court. 

On the international stage, Clinton supports the Paris agreement on climate change. Should she win the presidency in November, she would make an effort to take this Treaty to the next step, thus continuing U.S. leadership. That would mean reinforcing U.S. leadership along the lines described above, while helping address current uncertainties about finance, transparency, and accountability, to name only a few challenges that remain.

Trump: Drill, baby, drill

Although Donald Trump’s candidacy remains highly controversial, he is now the presumptive Republican nominee for president. To the extent that we know any detailed plans, quod non, it is safe to say that his views on energy and climate change are diametrically opposed to most of Clinton’s. Broadly speaking, Mr. Trump has come out as a fervent supporter of the fossil fuel industry, and has expressed skepticism about the economic viability of renewable energy.

Mr. Trump’s views start with the belief that climate change is not man-made. In the past, the controversial businessman has suggested that climate change might be a hoax invention from China, in order to undermine U.S. industrial interests and job creation. This starting point allows Mr. Trump to be extremely supportive of existing industrial interests (if carbon and other greenhouse gas emissions are not a problem, the thinking goes, then business as usual is the way to go). 

In a speech in North Dakota in late May, Mr. Trump laid out some broad initial ideas for his energy policy. He declared that under his presidency the United States would “accomplish complete American energy independence,” leaving unaddressed arguments about what that would mean for existing international energy trade. 

It is probably safe to say that Mr. Trump would like to further expand oil, gas, and coal production in the country. The latter, in particular, is remarkable: even coal executives have declared that market forces (particularly very competitive natural gas) have been the primary threat to the coal industry. Since Mr. Trump is also a strong supporter of the natural gas industry—and considering the challenges of building new bulk terminals for exports—it is unclear how a revitalization of the coal industry would occur. 

If climate change is a hoax, it will come as no surprise that Mr. Trump will not support efforts to mitigate carbon and other greenhouse gas emissions.

Contrary to his opponent, Mr. Trump would also like to revoke restrictions on drilling for oil and gas, and would permit production on federal lands. He also supports further expansion of energy infrastructure, and would, if elected, ask Trans Canada to resubmit a permit application for the Keystone pipeline, which he’d approve. He has caveated his support for projects like these by demanding that a portion of the revenues from oil and gas flows be redistributed to local communities, to compensate them for intrusion on their private property. Mr. Trump has also indicated that he wants to use revenues from oil and gas production to rebuild U.S. infrastructure more broadly.

If climate change is a hoax, it will come as no surprise that Mr. Trump will not support efforts to mitigate carbon and other greenhouse gas emissions. The candidate has called the Obama administration’s Clean Power Plan “stupid,” and when asked what he would do about the Paris agreement on climate change, he said he’d cancel it. 

Though Trump says the United States must pursue all forms of energy—including renewables—he has expressed skepticism about their economic viability, calling solar energy “very expensive.” Wind energy received similar pejorative feedback, since Trump says it kills eagles and is noisy. During one of the few debates about renewable energy during the Iowa primary, he voiced his support for blending biofuels in vehicles. 

To the polls

The 2016 U.S. presidential election will have a profound impact on global affairs. Not only will it affect a range of security and economic issues in important ways, it also means a lot for global energy and climate policy. Will the United States continue on the trajectory that President Obama has started and continue a major energy transition strategy? Or will it shift course, potentially undermining existing domestic policies and investments, as well as international obligations? In November 2016, the American people will decide.

      

 

 

Coal-fired electricity is responsible for producing 40 percent of the world’s power and about 70 percent of its steel. The coal industry employs millions worldwide and provides billions of people with electricity. Analysts estimate that the world has hundreds of years of coal reserves in the ground, at current consumption levels. Its abundance, low price, and global availability make it a difficult fuel source to give up. But despite coal’s advantages, it poses significant environmental and health risks. Ten percent of coal consists of ash, which contains radioactive and toxic elements. It is responsible for over $50 billion in medical costs annually in the European Union alone. The environmental consequences of coal use, such as water contamination and habitat destruction, are common. Burning coal adds millions of tons of dangerous particulates and greenhouse gases, including carbon, to the atmosphere.

States and societies around the world rely on coal, even though many of its dangers have been known for decades. If the Paris Agreement is to succeed, global leaders must address the reasons why many countries—particularly in the developing world—still rely on coal. Better yet, they must find new ways to provide coal-reliant countries with affordable, alternative energy, and invest in new technologies that could help mitigate coal’s negative consequences.

COAL ACROSS THE WORLD

Globally, coal production and consumption has risen almost continuously for more than 200 years. The International Energy Agency has estimated that the world burned approximately 7,876 million tons of coal in 2013, adding over 14.8 gigatons of carbon to the atmosphere. But global coal statistics do not tell us much about markets and trends. In fact, coal usage varies enormously around the world, with some regions transitioning away from the resource as others have increasingly embraced it.

For example, stringent environmental, health, and safety policies in the United States have put increasing pressure on the coal industry. Well-funded environmental groups have succeeded in closing coal-fired power plants, and many states on the country’s west coast and in its northeast have aimed to create a coal-free power grid. Yet market forces have turned out to be the nail in U.S. coal’s coffin. The rise of natural gas in the United States has gave the country’s electricity producers an incentive to shift away from coal. In fact, U.S. coal consumption declined from a billion tons in 2008, to roughly 850 million tons by 2013. This year, analysts suggest that coal will fuel only 32 percent of all U.S. electricity, and natural gas will become the country’s leading electricity source for the first time. As a result of low prices, low returns, and political controversy, investors have shied away from coal, which has caused major coal companies to struggle to stay afloat. Of all announced new electricity generation capacity in the United States, not a single megawatt is coal-fired. Although change is happening, it will likely be decades before coal is no longer an important fuel source in the U.S. economy. Canada’s coal sector faces similar pressures: weak demand from Asia, public opposition to the construction of new export facilities, domestic environmental legislation, and the shale boom have all taken their toll.

In Europe, stringent air quality controls and climate change regulations have cut the use of coal dramatically in Denmark, Sweden, and the United Kingdom. But the EU emissions trading scheme, which relies on carbon offsets and carbon dioxide caps, has proven disappointing. In fact, most European countries still lack an economically competitive and readily available alternative to coal. Plus, the coal industry still has political power in capitals like Berlin and Warsaw, which lowers the European common denominator for energy policy, as well as its policies that fight climate change.

Photo courtesy of REUTERS/James Regan/File Photo. Coal is stockpiled at the Blair Athol mine in the Bowen Basin coalfield near the town of Moranbah, Australia, June 1, 2012.

In Asia, both Japan and South Korea are set to expand their use of coal despite signing the Paris Agreement. After the Fukushima disaster, Japan has implemented ambitious renewables and energy efficiency policies, but those cannot take the place of its nuclear energy production on their own. These countries are entirely import dependent, which makes natural gas prices high. This, in turn, makes natural gas a less likely fuel source as the countries transition to greener electricity. In this context, high-efficiency coal plants appear to be a viable alternative, especially as nuclear power remains highly controversial.

And outside of advanced economies, coal often plays the role it once played in Europe and North America. For over a decade, China was the main engine of global coal consumption, driving booms in coal mining and shipping. China’s domestic coal production skyrocketed, and other countries, such as Australia, experienced coal booms to keep pace with Chinese demand. Although China produced and consumed almost as much coal as the rest of the world combined in 2014, it seems that the country’s consumption has peaked. But China will still rely heavily on coal-fired electricity for decades. The country remains a key player in steel production, and millions of its citizens continue to work in the mining industry, despite recent layoffs.

South Asian countries continue to invest heavily in new coal-fired electricity plants and industrial projects. India may appreciate the risks of climate change, but its chief concern is delivering low-cost power to 350 million of its citizens who lack electricity. Coal is set to play a prominent role in meeting such goals. Countries like Indonesia, Thailand, and Vietnam have followed suit as they search for low-cost electricity to power their countries.

In short, coal remains a big player in the global fuel mix, even as it faces tough challenges from stringent environmental regulations, competition from other fuel sources, and a lack of new investments.

Photo courtesy of REUTERS/Sheng Li/Files. A labourer carries honeycomb briquettes at a coal processing factory in Shenyang, Liaoning province in this December 2, 2009 file photo.

WHITHER COAL?

Different strategies apply in different parts of the world when it comes to eradicating coal, despite the global agreement in Paris. Just as there is not a global energy grid, there is also no single, global transition to lower-carbon energy. Although some countries are transitioning away from coal, others continue to transition toward it.

Second, pragmatism and persistence—rather than ideological purity—remain key values as countries transition towards low-carbon economies. Natural gas provides North America with a backup fuel as it transitions to green energy. Without major bulk terminals on the west coast, western U.S. coal producers will not find new markets for their products overseas. And in Europe, policymakers will have to make good on long-promised and long-delayed changes to energy policy and infrastructure. If Germany and other EU states are to achieve promised clean energy transitions, coal production must be scaled back substantially across the continent. European leaders must also build an “Energy Union” that will accelerate the flow of cross-border electricity, if they are to achieve the Paris Accord’s climate change goals. Europe must also reform its existing carbon pricing mechanisms. And across China, Europe, and North America, workers will have to be re-educated for new job opportunities as the coal market dries up.

But for now, coal still keeps the light on around the world. It powers new, high-tech economies, as well as a huge share of traditional manufacturing. If hundreds of millions of Africans and Asians are to gain access to electricity, new coal-fired power plants will have to come online in the years ahead. As coal continues to play a prominent role in industrial processes like steel and cement making, technological investments are required to limit its consequences.

To tackle these challenges, coal advocates, as well as some climate experts, suggest that more countries must invest in carbon capture and sequestration (CCS) research. But such investments are lagging, and the world would require several dozen CCS projects in order to make the technology commercially viable in the long term.

If the Paris Accord is to succeed, the earth’s atmosphere cannot remain a free dump for billions of tons of pollution every year. In fact, virtually all greenhouse gas emissions must be reduced. Countries can impose taxes, cap-and-trade schemes, and regulation to make this happen. Governments will have to design unique strategies that are custom fit to their countries, and, in some cases, find opportunities with their neighbors as well. For example, some private and public institutions have chosen to stop financing coal-fired projects, and the Obama administration has indicated it will not give out new leases for coal mining on federal land. Others will choose to build more coal-fired plants until the alternatives are cheaper, or until someone pays them not to.

Globally, coal may indeed be at the beginning of the end. But the energy transition is not strictly global. It is also national, regional, and local. Coal remains economically competitive—attractive even—in many parts of the world. Some countries will wage wars on coal, which will be as much economic and financial as they are political. But some countries, like India, will host coal booms regardless of the consequences. After Paris, there is no point in ignoring coal. It will be powering the world—and the world’s debates—for decades to come.

This piece was originally published by Foreign Affairs.

      

 

 

Addressing global poverty requires taking steps to address energy poverty, but the best model for doing so is widely debated. Is centralized distribution the best way forward, or should energy projects focus on distributed generation? Can large-scale deployment of wind turbines and solar panels meet the needs of rural communities in the developing world? What role should nuclear power and fossil fuels play in expanding grid access?

On May 24, the Energy Security and Climate Initiative (ESCI) at Brookings hosted a debate on solutions to increase energy access between Daniel Kammen, Class of 1935 distinguished professor of energy at the University of California, Berkeley, and Ted Nordhaus, co-founder and research director of the Breakthrough Institute. ClimateWire Editor Lisa Friedman moderated the discussion and audience Q&A.

      

 

 

To be sure, these are not the best of times. Europe is perceived by some, including Republican presidential candidate Donald Trump, as failing to invest enough in its own security, since NATO allies spend less than 1.4 percent of GDP on their armed forces while the United States spends twice that. However, we must not lose sight of the key structural advantages—and the important policy successes—that have brought Europe where it is today. For example, Europe’s recent progress in energy policy has been significant—good not only for economic and energy resilience, but also for NATO’s collective handling of the revanchist Russia threat. 

[W]e must not lose sight of the key structural advantages—and the important policy successes—that have brought Europe where it is today.

For many years, analysts and policymakers have debated the question of Europe’s dependence on natural gas from Russia. Today, this problem is largely solved. Russia provides only one-third of Europe’s gas. Importantly, Europe’s internal infrastructure for transporting natural gas in all desired directions has improved greatly. So have its available storage options, as well as its possibilities to import alternatives either by pipeline or in the form of liquefied natural gas. As a result, almost all member states are currently well-positioned to withstand even a worst-case scenario. 

Indeed, European Commission analyses show that even a multi-month long supply disruption could be addressed, albeit at real economic cost, by diversification and fuel switching. Progress in energy efficiency and renewable energy investments also help. There is more to do to enhance European energy security, but much has been done already. The Europeans have shown that, with ups and downs, they can address energy security themselves.

Already this energy success has contributed to a strategic success. Europe has been heavily criticized for not standing up more firmly to Russia in response to the annexation of Crimea and the conflict in eastern Ukraine. In fact, all EU member states have agreed to keep economic sanctions in place against Moscow. In addition, lifting the sanctions has been firmly attached to the implementation of the Minsk II agreement—and despite recent cracks in European solidarity, we hope that this stance will hold going forward. 

The notion that Europe is weak and dependent on Russian natural gas is a relic from the past.

The notion that Europe is weak and dependent on Russian natural gas is a relic from the past. Europe has a strong regulatory framework with which commercial entities, including Gazprom, have to abide. For those who doubt the impact of these regulations, just ask Google or Microsoft. With the end of so-called destination clauses, natural gas can be re-sold whenever required, as long as sufficient infrastructure is in place. Just last year, Germany re-exported over 30 billion cubic meters of gas, mostly Russian, in particular to Central and Eastern Europe (including Ukraine). That volume exceeds the annual consumption of every European state with the exceptions of Germany, Italy, France, and Britain.

In theory, Europe could even substantially wean itself off Russian gas if need be. To be sure, that would come at a major expense: over 200 billion euros of additional investments over a period of two years or more, and then an annual 35 billion euros, according to some calculations. That will almost surely not happen. But as a way of bounding the worst-case scenario, it is still informative. One might say that Europe has escalation dominance over Russia; the latter needs to export to Europe more than Europe need Russian hydrocarbons.

The internal energy market is not finished, but Europe’s energy security has significantly improved in recent years. Even though world markets are currently awash in resources, there is no time for complacence, and European leaders should finish the job, foremost by safeguarding the swift construction of the so-called Projects of Common Interest (key energy infrastructure projects that address the remaining bottlenecks in the EU market), so that the U.S. State Department can take new infrastructure projects like Nord Stream 2 off its priority list, and make energy policy another true European success story. It is already much of the way there, and Western security is the better for it.

      

 

 

The current Iranian-Saudi conflagration is already more dangerous than the original, as the fallout from the conflict has been felt across the region in the devastating wars in Syria and Yemen. And in contrast to the 1980s, when it was the nascent Islamic Republic whose ideological imperatives frustrated efforts at de-escalation, this time around the wild card lies in Riyadh, not in Tehran.

[T]his time around the wild card lies in Riyadh, not in Tehran.

Even by the standards of their well-established enmity, the past week has been an especially sour one between Tehran and Riyadh. The Istanbul summit of the Organization of Islamic Cooperation (OIC) ended in recriminations and resentment after the Saudis engineered a final statement that criticized Tehran. A Doha meeting of major oil producers failed to produce agreement on a Saudi proposed output freeze because of Tehran’s refusal to cooperate. And quiet talks over the annual pilgrimage to Mecca—a traditional source of strife between the two theocratic states that was further complicated by their January rupture in diplomatic relations—have just collapsed. 

The handling of these three encounters among wary adversaries underscores trends already evident in Saudi foreign policy: the increasing centrality of Mohammed bin Salman, the kingdom’s deputy crown prince and defense minister, in shaping Saudi strategy, and the audacity—even incaution—with which he approaches the strategic schism between the kingdom and Iran. 

Energy diplomacy gone awry

Of the three incidents, perhaps the most consequential (and illuminating) was the botched Saudi bid to stem the precipitous decline in oil prices—a drop of as much as 70 percent in the past two years, which has cost the Saudis and their Gulf neighbors at least $300 billion in revenues. The collapse reflects a variety of economic and geopolitical factors, but at its heart is a mismatch between robust oil production levels—including the kingdom’s own epic output—and flagging global demand. For months, Riyadh has been courting support from other major exporters, most notably Russia, to cap production at January 2016 levels. The proposal was predicated on adherence by all the major producing states, and reports around an initial agreement did indeed bolster prices modestly.

Not surprisingly, Tehran was never willing to join such a scheme. Having only just unfettered its economy from the international sanctions that had slashed its exports by more than 1 million barrels per day (mbpd) for several years, not even the most accommodating Iranian leadership would contemplate voluntarily forgoing the opportunity to reclaim market share and generate much-needed revenues. Public exhortations by the Saudis to join in a freeze were met with unequivocal opposition and even derision from Iranian officials. 

In the face of the Iranian stance, the decision to proceed with Sunday’s meeting among major oil producers seemed to suggest Saudi flexibility on the question of Tehran’s inclusion, as did signals from the kingdom’s venerable oil minister, Ali Al-Naimi, in the days before the meeting. Expectations were relatively low, but market analysts and diplomats from other states invited to the meeting anticipated some modest yield—perhaps “bullish statements about the market adjusting and their output not increasing.” After all, commented one analyst, “if the Saudis were having cold feet, this meeting would already be canceled.” 

Here is where things get interesting. In the days before the Doha meeting, Deputy Crown Prince Mohammed bin Salman, or MbS as he is frequently dubbed, doubled down on the issue of Iran. He insisted that without Tehran’s cooperation, the production freeze proposal was off the table and “we will sell at any opportunity we get.” He dismissed any concerns about the kingdom’s energy development or its fiscal viability, commenting that “this battle is not my battle. It’s the battle of others who are suffering from low oil prices.” As for Riyadh, MbS sniffed, “we have our own programs that don’t need high oil prices.”

[T]he usually well-scripted Saudi energy diplomacy took a curiously chaotic turn.

From there, the usually well-scripted Saudi energy diplomacy took a curiously chaotic turn. Having confirmed they would send a delegation to the talks, the Iranians opted to boycott entirely—no doubt with a nod to their own domestic context, where a movement was already afoot within the Iranian parliament to impeach the oil minister had he attended the meeting. The Doha meeting dragged on for hours beyond schedule as representatives sought in vain to devise some semblance of an agreement that would avoid a negative reaction from oil markets.

Blowback

The disaster in Doha came on the heels of the OIC summit in Istanbul, where a heavy-handed official communique lambasting Iranian policies only deepened the animus. It was an especially indecorous jab considering the presence of Iranian president, Hassan Rouhani, and the Turkish efforts to use the meeting as an opportunity to mediate the conflict and engineer some dialogue between Rouhani and the Saudi king, Salman, who also attended the summit. 

The series of diplomatic skirmishes with Tehran only highlights the primacy of Mohammed bin Salman, who in addition to directing the kingdom’s military campaign against Iranian-backed separatists in Yemen made waves earlier this year when he discussed selling off components of the storied Saudi state oil company Aramco. One oil analyst has dubbed him “the ultimate disrupter” for having publicly outflanked Naimi, who for three decades has been the authoritative voice of Saudi oil policy.

For MbS, the oil output talks offered a convenient opportunity to deliver another blow to Tehran. And he had little to lose by using Iran as a wedge to scuttle the proposed freeze. The plan was always understood as a modest gesture; since it would have left both Riyadh and Moscow producing near peak capacity, at best a freeze might have had a slight modulating effect on the psychology of the market. Instead, Saudi Arabia and other oil producers will have to watch as the slow, erratic process of market rebalancing unfolds and global demand for oil eventually rebounds to meet supply.

However, it’s unclear if these tactics can generate newfound diplomatic leverage for the kingdom. In the aftermath of the Doha meeting, the Russian energy minister pointedly exonerated Tehran while describing the Saudi stance as “unreasonable.” Reports from the sidelines suggest that even Riyadh’s Gulf allies were “annoyed” by the sudden shift in what had been pitched to participating governments and by the fact that oil prices fell again in the days that followed.

History lesson

Still, the 31-year-old deputy crown prince might do well to study the last major oil conflict between Tehran and Riyadh, which coincidentally unfolded just around the time of his birth. Then, as now, the Saudis struggled to deal with the ripple effects of a production surge that they helped initiate; then, as now, their decision to flood the market shattered their adversaries’ balance sheets, but it also generated long-term blowback for the kingdom’s internal stability and external influence.

Much like the recent developments, the oil crisis in the mid-1980s had its roots in Saudi strategic interests toward the region as well as toward oil markets. As OPEC’s swing producer, Riyadh had absorbed massive production cuts in the early 1980s in order to maintain prices in a period of falling demand and expanding non-OPEC supply. Saudi exports sank to 2.15mbpd in 1985, approximately half of its formal OPEC quota and a mere 25 percent of its 1980 exports, even as its OPEC partners routinely disregarded their quotas. After a futile effort to persuade non-OPEC producers to cut back, the Saudis began ramping up production, and over a nine-month period beginning in August 1985, OPEC production ballooned by 4mpbd, with the kingdom responsible for approximately half that increase.

Then, as now, the Saudis struggled to deal with the ripple effects of a production surge that they helped initiate.

The decision coincided with the spillover of the Iran-Iraq war into the Gulf, via Iraqi attacks on Iran’s oil infrastructure and Iranian counter-attacks on Gulf oil exports and other shipments transiting the strategic waterway. 

The combination was catastrophic for Iran, whose oil revenues plummeted from $21.2 billion in 1983 to $13.7 billion in 1984 and $6.3 billion in 1986. Meanwhile, Iran’s economy began to grind to a halt—the GDP crashed, and key sectors such as manufacturing and construction were disproportionately hit. Iranian officials saw Saudi production increases as a deliberate effort, with Washington’s active collusion, to cripple Iran’s economy and its military capability. Then-President Ali Khamenei, who is now Iran’s supreme leader, warned Riyadh that “the price war is no less important to us than the military war at the front.” Tehran tried to push back within OPEC but made little headway. 

As is the case today, the Saudi strategy in the mid-1980s was neither irrational nor purely punitive toward Tehran. In fact, Riyadh’s 1985 production increases reflected an attempt to address two profound concerns: the kingdom’s massive fiscal requirements for domestic development and its international initiatives. In addition, the Saudis feared a long-term erosion in market share, weakened geostrategic preeminence, and mounting Iranian regional ambitions. They even sent quiet overtures to Tehran about the possibility of a ceasefire and sought to break the Iranian alliance with Syria.

In the 1980s, the oil strategy proved a partial success, and an incredibly costly one, for Riyadh. While the kingdom managed to claw back market share, the crisis did not generate sustained OPEC unity, nor did it produce near-term progress on subduing Tehran. The price crash hurt Riyadh’s diplomatic sway regionally and internationally, generated terrible blowback for the Saudi leadership, and caused its oil income to plummet to a mere $18 billion in 1986—a $100 billion drop from five years earlier. As one Saudi government oil economist remarked: “Everyone suffered, Saudi Arabia most of all. It was a very bad time.” 

Eventually, the 1985-86 oil war subsided, as both Tehran and Riyadh came to appreciate that their interests were better served by mutual compromise. The Saudis sought an exit strategy to stem the price erosion as well as the ongoing damage to their relations with smaller producers, including the United States. Facing an inflection point in its war with Iraq, Tehran also yielded, even conceding a temporary boost for Baghdad’s production. Hubris on both sides was eventually run aground by economic realities. Mohammed bin Salman may soon learn a similar lesson.