Saudi Arabians woke up over the weekend to a once-in-a-decade cabinet reshuffle. Octogenarian oil minister Ali al-Naimi, who has been in charge of the Kingdom’s energy policy since 1995, was replaced by Khaled al-Falih, who is to head the newly created Energy, Industry, and Natural Resources Ministry. Majed al-Qusaibi was named head of the newly created Commerce and Investment Ministry. Finally, Ahmed al-Kholifey was made governor of the Saudi Arabia’s Central Bank (SAMA). It may come as a surprise to many Saudis that the origin of this reshuffle—and indeed the Kingdom’s new economic direction—finds its impetus in a report by the global management consulting firm McKinsey & Company.

A man with a plan

Saudi Arabia has been struggling to deal with the impact of lower oil prices. After years of recording budget surpluses, the government has seen its budgetary deficit grow to 15 percent of GDP. Lower oil prices—coupled with tensions with regional rival Iran over Yemen, Syria, and Lebanon—have put the Kingdom’s finances under pressure. Since oil prices began to plummet, Saudi Arabia’s ever-ambitious Deputy Crown Prince Mohammed bin Salman has been spearheading an ambitious reform initiative that seeks to diversify the Kingdom’s economy away from oil. 

Dubbed “Saudi Arabia’s Vision 2030,” the prince says that the new economic blueprint will increase the role of the private sector from 40 percent to 60 percent, reduce unemployment from 11 percent to 7.6 percent, and grow non-oil income exponentially. This is to be financed by the partial privatization of the Kingdom’s oil behemoth, Aramco. 

The 2030 document outlines a number of significant reforms that seek to change not only the Saudi economy, but state-society relations more broadly, in a way that has been done since the Kingdom’s founding.

The 2030 document outlines a number of significant reforms that seek to change not only the Saudi economy, but state-society relations more broadly, in a way that hasn't been done since the Kingdom’s founding. The prince’s vision seems to have been inspired by a report issued by the McKinsey Global Institute in December 2015 titled “Moving Saudi Arabia’s Economy Beyond Oil.” The vision and the report have similar policy prescriptions for diversifying the Kingdom’s economy away from oil. 

Such similarities highlight the influence of consultancies on policymaking in the Kingdom. Indeed, Bloomberg news reported that consultancies are set to earn 12 percent more in commissions in Saudi Arabia this year, the fastest growth amongst the world’s advisory markets. In a wide-ranging interview with The Economist in January, Prince Mohammed himself said that “McKinsey participates with us in many studies.” According to the Financial Times, Saudi businessmen have sarcastically dubbed the Ministry of Planning as the “McKinsey Ministry.”

McKinsey’s key report, full with glossy illustrations, contains consultant buzzwords (“transformation,” “efficiency,” and “synergies”) that would make Marty Kaan in Showtimes’s House of Lies proud. It’s by no means novel for consultants to advise governments in the region and across the world, and indeed the report does outline an ambitious blueprint for the Kingdom’s economic transformation and diversification away from oil. 

Will the public buy it?

But in a glaring omission, the report does not adequately explain how the Saudi government will be able to change the mindset of everyday Saudi Arabia citizens, who have long been accustomed to state largesse that included fuel subsidies, loans, free land, and public sector jobs. 

This is the key issue. The reform plans sound promising, and will indeed make headway in weaning the Kingdom off its oil “addiction” (as the prince himself put it). But how will everyday citizens react to the reforms? The Saudi government will be asking more of its citizens—will the citizens in turn ask for more accountability and representation? Since January, the prices of gasoline, electricity, and water have gone up. There was a public outcry against higher utility prices, which lead King Salman to fire the water minister to absorb the public’s anger. 

Such discontent is the harbinger of things to come. The coming months and years will show how Saudi leadership implements much needed economic reforms without alienating its population. While the outcome is uncertain, one thing is: consultants will continue to flock to Saudi Arabia to work on the “mother of all transformation projects.”

Editors' Note: This post was corrected on May 12, 2016 to clarify that the report “Moving Saudi Arabia’s Economy Beyond Oil” was issued by the McKinsey Global Institute, the research arm of McKinsey & Company. MGI’s work is independent and wholly funded by McKinsey Partners. The MGI report was not commissioned by the government of Saudi Arabia and has no formal role in government decision-making.

Rooftop solar is booming in U.S. cities.

One of the most exciting infrastructure developments within metropolitan America, the installation of over a million solar photovoltaic (PV) systems in recent years, represents nothing less than a breakthrough for urban sustainability — and the climate.

Prices for solar panels have fallen dramatically. Residential solar installations surged by 66 percent between 2014 and 2015 helping to ensure that solar accounted for 30 percent of all new U.S. electric generating capacity. And for that matter, recent analyses conclude that the cost of residential solar is often comparable to the average price of power on the utility grid, a threshold known as grid parity.

So, what’s not to like? Rooftop solar is a total winner, right?

Well, not quite: The spread of rooftop solar has raised tricky issues for utilities and the public utilities commissions (PUCs) that regulate them. 

Specifically, the proliferation of rooftop solar installations is challenging the traditional utility business model by altering the relationship of household and utility—and not just by reducing electricity sales. In this respect, the solar boom has prompted significant debates in states like New York and California about the best rates and policies to ensure that state utility rules and rates provide a way for distributed solar to flourish even as utilities are rewarded for meeting customer demands. Increasingly, this ferment is leading to thoughtful dialogues aimed at devising new forms of policy and rate design that can—as in New York—encourage distributed energy resources (DERs) while allowing for distribution utilities to adapt to the new era.

However, in some states, the ferment has prompted a cruder set of backlashes. Most pointedly, some utilities contend that the “net-metering” fees paid to homeowners with rooftop installations for excess solar power they send back to the grid unfairly transfer costs to the utilities and their non-solar customers.

And so in a number of states, utility interests have sought to persuade state regulators to roll back net-metering provisions, arguing they are a net cost to the overall electricity system.  Most glaringly, the local utility in Nevada successfully wielded the cost-shift theory last winter to get the Nevada Public Utilities Commission to drastically curtail the state’s net-metering payments, prompting Solar City, Sunrun, and Vivint Solar—the state’s three largest providers of rooftop panels—to leave the Nevada market entirely. The result: New residential solar installation permits plunged 92 percent in Nevada in the first quarter of 2016.

All of which highlights a burning question for the present and future of rooftop solar: Does net metering really represent a net cost shift from solar-owning households to others? Or does it in fact contribute net benefits to the grid, utilities, and other ratepayer groups when all costs and benefits are factored in? As to the answer, it’s getting clearer (even if it’s not unanimous). Net metering — contra the Nevada decision — frequently benefits all ratepayers when all costs and benefits are accounted for, which is a finding state public utility commissions, or PUCs, need to take seriously as the fight over net metering rages in states like Arizona, California, and Nevada.  Regulators everywhere need to put in place processes that fairly consider the full range of benefits (as well as costs) of net metering as well as other policies as they set and update the policies, regulations, and tariffs that will play a critical role in determining the extent to which the distributed solar industry continues to grow.

Fortunately, such cost-benefit analyses have become an important feature of state rate-setting processes and offer important guidance to states like Nevada.  So what does the accumulating national literature on costs and benefits of net metering say?  Increasingly it concludes— whether conducted by PUCs, national labs, or academics — that the economic benefits of net metering actually outweigh the costs and impose no significant cost increase for non-solar customers.  Far from a net cost, net metering is in most cases a net benefit—for the utility and for non-solar rate-payers.

Of course, there are legitimate cost-recovery issues associated with net metering, and they vary from market to market. Moreover, getting to a good rate design, which is essential for both utility revenues and the growth of distributed generation, is undeniably complicated.  If rates go too far in the direction of “volumetric energy charges”—charging customers based on energy use—utilities could have trouble recovering costs when distributed energy sources reach higher levels of penetration. On the other hand, if rates lean more towards fixed charges—not dependent on usage—it may reduce incentives for customers to consider solar and other distributed generation technologies.  

Moreover, cost-benefit assessments can vary due to differences in valuation approach and methodology, leading to inconsistent outcomes. For instance, a Louisiana Public Utility Commission study last year found that that state’s net-metering customers do not pay the full cost of service and are subsidized by other ratepayers. How that squares with other states’ analyses is hard to parse.

Nevertheless, by the end of 2015, regulators in at least 10 states had conducted studies to develop methodologies to value distributed generation and net metering, while other states conducted less formal inquiries, ranging from direct rate design or net-metering policy changes to general education of decisionmakers and the public. And there is a degree of consensus.  What do the commission-sponsored analyses show? A growing number show that net metering benefits all utility customers:

• In 2013 Vermont’s Public Service Department conducted a study that concluded that “net-metered systems do not impose a significant net cost to ratepayers who are not net-metering participants.” The legislatively mandated analysis deemed the policy a successful component of the state’s overall energy strategy that is cost effectively advancing Vermont’s renewable energy goals.

• In 2014 a study commissioned by the Nevada Public Utility Commission itself concluded that net metering provided $36 million in benefits to all NV Energy customers, confirming that solar energy can provide cost savings for both solar and non-solar customers alike. What’s more, solar installations will make fewer costly grid upgrades necessary, leading to additional savings. The study estimated a net benefit of $166 million over the lifetime of solar systems installed through 2016. Furthermore, due to changes to utility incentives and net-metering policies in Nevada starting in 2014, solar customers would not be significantly shifting costs to other ratepayers.

• A 2014 study commissioned by the Mississippi Public Services Commission concluded that the benefits of implementing net metering for solar PV in Mississippi outweigh the costs in all but one scenario. The study found that distributed solar can help avoid significant infrastructure investments, take pressure off the state's oil and gas generation at peak demand times, and lower rates. (However, the study also warned that increased penetrations of distributed solar could lead to lower revenues for utilities and suggested that the state investigate Value of Solar Tariffs, or VOST, and other alternative valuations to calculate the true cost of solar.)

• In 2014 Minnesota’s Public Utility Commission approved a first-ever statewide “value of solar” methodology which affirmed that distributed solar generation is worth more than its retail price and concluded that net metering undervalues rooftop solar. The “value of solar” methodology is designed to capture the societal value of PV-generated electricity. The PUC found that the value of solar was at 14.5 cents per kilowatt hour (kWh)—which was 3 to 3.5 cents more per kilowatt than Xcel's retail rates—when other metrics such as the social cost of carbon, the avoided construction of new power stations, and the displacement of more expensive power sources were factored in.

• Another study commissioned by the Maine Public Utility Commission in 2015 put a value of $0.33 per kWh on energy generated by distributed solar, compared to the average retail price of $0.13 per kWh — the rate at which electricity is sold to residential customers as well as the rate at which distributed solar is compensated. The study concludes that solar power provides a substantial public benefit because it reduces electricity prices due to the displacement of more expensive power sources, reduces air and climate pollution, reduces costs for the electric grid system, reduces the need to build more power plants to meet peak demand, stabilizes prices, and promotes energy security. These avoided costs represent a net benefit for non-solar ratepayers.

These generally positive PUC conclusions about the benefits of net metering have been supported by research done by a national lab and several think tanks. Important lab research has examined how substantially higher adoption of distributed resources might look.

In a forward-looking analysis of the financial impacts of net-metered energy on utilities and ratepayers, Lawrence Berkeley National Lab found that while high use of net-metered solar generation may decrease utility shareholders' earnings, it will have a "relatively modest" impact on ratepayers. The report examined solar penetration levels that are "substantially higher than [those that] exist today" — 10 percent compared to today's 0.2 percent — and concluded that “even at penetration levels significantly higher than today, the impacts of customer-sited PV on average retail rates may be relatively modest." The report further said that utilities and regulators "may have sufficient time to address concerns about the rate impacts of PV in a measured and deliberate manner"

Similarly, a growing number of academic and think tank studies have found that solar energy is being undervalued and that it delivers benefits far beyond what solar customers are receiving in net-metering credits:

• For instance, a review of 11 net metering studies by Environment America Research and Policy Center has found that distributed solar offers net benefits to the entire electric grid through reduced capital investment costs, avoided energy costs, and reduced environmental compliance costs. Eight of the 11 studies found the value of solar energy to be higher than the average local residential retail electricity rate: The median value of solar power across all 11 studies was nearly 17 cents per unit, compared to the nation’s average retail electricity rate of about 12 cents per unit.

• A 2015 cost-benefit study of net metering in Missouri by the Missouri Energy Initiative found that even accounting for increased utility administrative costs and the shifting of some fixed expenses, net metering is a net benefit for all customers regardless of whether they have rooftop solar. The study used values for two kinds of costs and two benefits and concluded that net metering’s “net effect” is positive. The typical solar owner pays only 20 percent less in fixed grid costs and costs the utility an estimated $187 per interconnection. Meanwhile, solar owners benefit the system through reduced emissions and energy costs.

• Likewise, a study by Acadia Center found the value of solar to exceed 22 cents per kWh of value for Massachusetts ratepayers through reduced energy and infrastructure costs, lower fuel prices, and lowering the cost of compliance with the Commonwealth's greenhouse gas requirements. This value was estimated to exceed the retail rate provided through net metering.

• In yet another study, researchers at the University at Albany, George Washington University, and Clean Power Research have found that solar installations in New York deliver between 15 and 40 cents per kWh to ratepayers. The study noted that these numbers provide economic justification for the existence of incentives that transfer value from those who benefit from solar electric generation to those who invest in solar electric generation.

In short, while the conclusions vary, a significant body of cost-benefit research conducted by PUCs, consultants, and research organizations provides substantial evidence that net metering is more often than not a net benefit to the grid and all ratepayers.

As to the takeaways, they are quite clear: Regulators and utilities need to engage in a broader and more honest conversation about how to integrate distributed-generation technologies into the grid nationwide, with an eye toward instituting a fair utility-cost recovery strategy that does not pose significant challenges to solar adoption.

From the state PUCs’ perspective, until broad changes are made to the increasingly outdated and ineffective standard utility business model, which is built largely around selling increasing amounts of electricity, net-metering policies should be viewed as an important tool for encouraging the integration of renewable energy into states’ energy portfolios as part of the transition beyond fossil fuels. To that end, progressive regulators should explore and implement reforms that arrive at more beneficial and equitable rate designs that do not prevent solar expansion in their states. The following reforms range from the simplest to the hardest:

• Adopt a rigorous and transparent methodology for identifying, assessing, and quantifying the full range of benefits and costs of distributed generation technologies. While it is not always possible to quantify or assess sources of benefits and costs comprehensively, PUCs must ensure that all cost-benefit studies explicitly decide how to account for each source of value and state which ones are included and which are not. Currently methodological differences in evaluating the full value of distributed generation technologies make comparisons challenging. States start from different sets of questions and assumptions and use different data. For instance, while there is consensus on the basic approach to energy value estimation (avoided energy and energy losses via the transmission and distribution system), differences arise in calculating other costs and benefits, especially unmonetized values such as financial risks, environmental benefits, and social values. In this regard, the Interstate Renewable Energy Council’s “A Regulator’s Guidebook: Calculating the Benefits and Costs of Distributed Solar Generation” and the National Renewable Energy Laboratory’s “Methods for Analyzing the Benefits and Costs of Distributed Photovoltaic Generation to the U.S. Electric Utility System” represent helpful resources for identifying norms in the selection of categories, definitions, and  methodologies to measure various benefits and costs.

• Undertake and implement a rigorous, transparent, and precise “value of solar” analytic and rate-setting approach that would compensate rooftop solar customers based on the benefit that they provide to the grid. Seen as an alternative to ‘traditional’ net-metering rate design, a “value of solar” approach would credit solar owners for (1) avoiding the purchase of energy from other, polluting sources; (2) avoiding the need to build additional power plant capacity to meet peak energy needs; (3) providing energy for decades at a fixed prices; and (4) reducing wear and tear on the electric grid. While calculating the “value of solar” is very complex and highly location-dependent, ultimately PUCs may want to head toward an approach that accurately reflects all benefits and costs from all energy sources. Value of solar tariffs are being used in Austin, Texas (active use) and Minnesota (under development).

• Implement a well-designed decoupling mechanism that will encourage utilities to promote energy efficiency and distributed generation technologies like solar PV, without seeing them as an automatic threat to their revenues. As of January 2016, 15 states have implemented electric decoupling and eight more are considering it. Not surprisingly, it is states that have not decoupled electricity (such as Nevada) that are fighting net metering the hardest. Typically, decoupling has been used as a mechanism to encourage regulated utilities to promote energy efficiency for their customers. However, it can also be used as a tool to incentivize net metering by breaking the link between utility profits and utility sales and encouraging maximum solar penetration. Advocates of decoupling note that it is even more effective when paired with time-of-use pricing and minimum monthly billing.

• Move towards a rate design structure that can meet the needs of a distributed resource future. A sizable disconnect is opening between the rapidly evolving new world of distributed energy technologies and an old world of electricity pricing. In this new world, bundled, block, “volumetric” pricing—the most common rate structure for both residential and small commercial customers—can no longer meet the needs of all stakeholders. The changing grid calls, instead, for new rate structures that respond better to the deployment of new grid technologies and the proliferation of myriad distributed energy resources, whether solar, geothermal, or other.  A more sophisticated rate design structure, in this regard, would take into consideration three things: (1) the unbundling of rates to specifically price energy, capacity, ancillary services,  and so on; (2) moving from volumetric bloc rates to pricing structures that recognize the  variable time-based value of electricity generation and consumption (moving beyond just peak versus off-peak pricing to  fully real-time pricing); and (3) moving from pricing that treats all customers equally to a pricing structure that more accurately compensates for unique, location-specific and technology specific values.

• Move towards a performance-based utility rate-making model for the modern era. Performance based regulation (PBR) is a different way of structuring utility regulation designed to align a utility’s financial success with its ability to deliver what customers and society want. Moving to a model that pays the utility based on whether it achieves quantitatively defined outcomes (like system resilience, affordability, or distributed generation integration) can make it profitable for them to pursue optimal grid solutions to meet those outcomes. The new business model would require the PUC and utilities to make a number of changes, including overhauling the regulatory framework, removing utility incentives for increasing capital assets and kilowatt hours sold, and replacing those incentives with a new set of performance standard metrics such as reliability, safety, and demand-side management. New York’s Reforming the Energy Vision  proceeding is the most high-profile attempt in the country to implement a PBR model.

Options also exist for utilities to address the challenges posed by net metering:

• Utilities, most notably, have the opportunity to adjust their existing business models by themselves owning and operating distributed PV assets (though not to the exclusion of other providers).  On this front, utilities could move to assemble distributed generation systems, such as for rooftop solar, and sell or lease them to homeowners. In this regard, utilities have an advantage over third-party installers currently dominating the residential rooftop solar industry due to their proprietary system knowledge, brand recognition, and an existing relationship with their customers. Utilities in several states such as Arizona, California, and New York are investigating or have already invested in the opportunity.

• Furthermore, utilities can also push the envelope on grid modernization by investing in a more digital and distributed power grid that enables interaction with thousands of distributed energy resources and devices.

Ultimately, distributed solar is here to stay at increasing scale, and so state policies to support it have entered an important new transitional phase. More and more states will now likely move to update their net-metering policies as the cost of solar continues to drop and more homeowners opt to install solar panels on their homes.

As they do that, states need to rigorously and fairly evaluate the costs and benefits posed by net metering, grid fees, and other policies to shape a smart, progressive regulatory system that works for all of the stakeholders touched by distributed solar.

Utilities should have a shot at fair revenues and adequate ratepayers. Solar customers and providers have a right to cost-effective, reliable access to the grid. And the broader public should be able to expect a continued solar power boom in U.S. regions as well as accelerated decarbonization of state economies. All of which matters intensely. As observes the North Carolina Clean Energy Technology Center and Meister Consultants Group: “How key state policies and rates are adapted will play a significant role in determining the extent to which the [solar PV] industry will continue to grow and in what markets.”

On December 12, 2015, 195 countries adopted the Paris Agreement, the most ambitious climate change pact to date. The document lays out a plan to curb greenhouse gas emissions, among other climate-related initiatives. Participating countries must now find ways to translate those ambitions into policy, and answer important questions about financing, transparency and accountability, national implementation, and accelerated emissions reduction goals, to name but a few. But one issue looms large: coal.

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.

Renewable energy is an important source to tackle against climate change, as the latest IPCC report has pointed out. However, due to the existence of multiple market failures such as negative externalities of fossil fuels and knowledge spillovers of new technology, government subsidies are still needed to develop renewable energy, such as solar photovoltaic (PV) cells. In the United States, there have been various forms of subsidies for PV, varying from the federal level to the state level, and from the city level to the utility level. California, as the pioneer of solar PV development, has put forward the biggest state-level subsidy program for PV, the California Solar Initiative (CSI). The CSI has planned to spend around $2.2 Billion in 2007–2016 to install roughly 2 GW PV capacity, with the average subsidy level as high as $1.1/W. How to evaluate the cost-effectiveness and incentive pass-through of this program are the two major research questions we are pursing.

Our cost-effectiveness analysis is based on a constrained optimization model that we developed, where the objective is to install as much PV capacity as possible under a fixed budget constraint. Both the analytical and computational results suggest that due to a strong peer effect and the learning-by-doing effect, one can shift subsides from later periods to early periods so that the final PV installed capacity can be increased by 8.1% (or 32 MW). However, if the decision-maker has other policy objectives or constraints in mind, such as maintaining the policy certainty, then, the optimally calculated subsidy policy would look like the CSI.

As to the incentive pass-through question, we took a structural approach and in addition used the method of regression discontinuity (RD). While in general, the incentive pass-through rate depends on the curvature of the demand and supply curve and the level of market competition, our two estimations indicate that the incentive pass-through for the CSI program is almost complete. In other words, almost all of the incentive has been enjoyed by the customer, and the PV installers did not retain much. Based on the RD design, we observe that PV installers tend to consider the CSI incentive as exogenous to their pricing decision.

The relative good performance of the CSI in terms of both the cost-effectiveness and the incentive pass-through aspect are tightly related to its policy design and program management. International speaking, the biggest challenge for the design of any PV subsidy program is the quick running out of the budget, and in the end, it looks like customers are rushing for the subsidy. Such rushing behavior is a clear indication of higher-than-needed incentive levels. Due to the policy rigidity and rapid PV technological change, the PV subsidy policy may lag behind the PV cost decline; and as a result, rational customers could rush for any unnecessarily high subsidy.

Due to the high uncertainty and unpredictability of future PV costs, the CSI put forward a new design that links the incentive level change and the installed capacity goal fulfillment. Specifically, the CSI has designed nine steps to achieve its policy goal; at each step, there is a PV capacity goal that corresponds to an incentive level. Once the capacity goal is finished, the incentive level will decrease to the next lower level. Furthermore, to maintain the policy certainty, the CSI regulated that every step-wise change in the incentive level should not be higher than $0.45/W, nor smaller than $0.05/W, together with other three constraints.

A good subsidy policy not only requires flexible policy design to respond to fast-changing environment, but also demands an efficient program management system, digitalized if possible. For the CSI, the authority has contracted out a third-party to maintain a good database system for the program. Specifically, the database has documented in detail every PV system that customers requested. Key data fields include 22 important dates during the PV installation process, customers’ zip code, city, utility and county information, and various characteristics of the PV system such as price, system size, incentive, PV module and installer. All information is publicly available, which to some extent fills in the information gap held by customers and fosters the market competition among PV installers. For customers to receive the incentive, their PV systems have to pass the inspection of the local government, and also to be interconnected to the grid. On the supply side, the CSI has also certified and created a list of PV installers that every customer can choose from.

Although the CSI has ended in 2014 due to fast PV cost reduction starting from 2009, its experience has been transferred to other areas in the United States and in Europe. It is highly possible that other similar new technologies and products (e.g. the electric car and the battery) can adopt the CSI policy design, too. In summary, a good and successful policy may need to be simply, clear, credible, foreseeable, flexible, end-able, and incentive-compatible. The PV subsidy policy in China still has a long way to go when compared to the CSI.