In a recent private roundtable on global electricity and technology held by the Energy Security and Climate Initiative, participants discussed the benefits and challenges of implementing performance-based utility regulation. This summary reflects some of the key points in the discussion. 

As discussed in a previous Brookings report, the U.S. electric utility industry is undergoing a dramatic transformation. Three major inter-related factors are converging to drive this change: policy, technology, and customer engagement. 

• Federal, state, and local policies are supporting the increased deployment of renewable energy and distributed energy resources (DER) such as rooftop solar PV, storage, electric vehicles, demand management tools, and micro-grids;
• Costs for many of these technologies continue to decline; and
• Customers are demanding more control and information regarding their energy use.  

Power lines in Hinsdale, New Hampshire, lead away from the Vermont Yankee nuclear power plant (C rear) in Vernon, Vermont August 27, 2013. (REUTERS/Brian Snyder)

Initially, most of the debate on the impact of these trends has focused on the “death spiral” for utilities and how the existing business model of traditional, large central-station, one-way power and information flows from utility to customer will increasingly become obsolete. Recently, however, the tone of this discussion has changed: More and more utility executives view DER and the customer relationship as the biggest growth opportunities in the coming years. Consequently, the focus is moving from hand-wringing to proactively figuring out the model for utilities to sell kWhs and services, including whether there is a role for utilities in the DER market.

Lisa Wood and I have previously discussed how utilities are answering this challenge by playing a key role in the evolving distribution grid, but important questions remain: Who owns and operates the grid, enabling these new resources to connect? How do we monetize and value the array of services and resources at the grid edge? 

This raises the critical issue of the regulatory framework. The current cost of service regulatory model emphasizes building infrastructure in order to keep the lights on (reliability) at an affordable cost. This regulatory approach has served society well over the last 100 years, but it does not accommodate the recovery of investment in services and meeting broader societal goals. As noted by a participant in our roundtable: “In the current regulatory system, all equity investment earns the same return despite disparity in value and risk.”   

The U.S. electric utility industry is undergoing a dramatic transformation. Three major inter-related factors are converging to drive this change: policy, technology, and consumer engagement.

Performance-based regulation (PBR) promotes a shift from cost of service to value of service and provides a way for utilities, customers, and broader society to meet their respective goals. Setting performance metrics beyond investment in assets connects shareholder value to the customer and rewards utilities for reaching agreed upon policy goals.

Performance-based regulation in action

New York, through its Reforming the Energy Vision regulatory procedure, is considering changing the existing regulatory framework and implementing a PBR model with two proposed mechanisms. The first, earnings impact mechanisms (EIMs), allow a utility to earn higher returns if it meets certain performance metrics, including peak load reductions, energy efficiency deployment, interconnection of DERs, customer engagement and information access, and affordability. In the second–market based earnings (MBEs)–a utility serves as a distribution systems platform (DSP) and can charge fees for services offered on this grid platform, such as providing dispatch and balancing services for DER on the grid or referring customers to service providers. As one participant stated, the MBE model envisions how “a utility could serve as a storefront for the customer.” 

A key aspect of PBR models is that they are forward looking: The emphasis is on “how to pay for what society wants over a sufficiently long time horizon, rather than focusing on whether society paid the correct amount for what it got in the past.” Performance-based regulatory models with multi-year plans incentivize utilities to modernize their operations and align customer needs with company goals and policy goals. Multi-year plans look forward and can create opportunities for a system ready to make a transition to a more efficient, cleaner, and more distributed electricity system. For example, Minnesota uses a multi-year plan that according to the State Legislature can replace annual rates as long as it bases a portion of utility revenue on encouraging efficiency and rates are reasonably in line with the costs of service during the time period. This allows Minnesota utilities to accommodate a variety of changes while providing opportunities for more efficient and affordable service to customers.

Implementing a PBR framework faces several challenges. First, several contributors at the discussion noted that incentive regulation–rewarding performance, efficiency, and lowering costs–has been around for a long time, including in the United States, and the revenue cap (RPI-X) approach was implemented in the United Kingdom several decades ago but does not seem to have gained traction in this country. While there is no simple answer to explain this, it may be owing to the “complexity of diversity and over-judicialization” of the electricity sector in the United States.

Four reliability coordinators monitor the state power grid during a tour of the Electric Reliability Council of Texas (ERCOT) command center in Taylor, Texas August 14, 2012. (REUTERS/Julia Robinson)

From the utility perspective, it is important to note that while the industry may be changing in very dynamic ways, it also important to consider the ways in which it remains the same:

• Customers continue to demand reliable electricity service at a reasonable price;
• The grid itself is still critically important, especially to support the transformation taking place (as one participant noted, “the grid is still in the money”); and,
• There still needs to be a balance between centralized generation and distributed generation.

Any changes in the regulatory approach must not only account for these realities, but stakeholders must also recognize the impacts of moving toward a PBR framework on the financial health of utilities. As one expert noted: “If all profits come from PBR, risk increases and you get a different class of investors.” These factors argue for gradual implementation of any changes to the regulatory compact. 

Participants raised other concerns with PBR. As electricity markets continue to evolve, stranded assets may grow and it is important to start thinking now about how to deal with or avoid this issue. With more and more renewables being added to the system and prices declining rapidly, policies will continue to evolve, potentially complicating a broader re-working of the regulatory approach. The debate over net metering is an example, where the discussion has moved from what to do with the policy itself to an appropriate rate design to recover the cost of using the grid (for example, use of fixed charges, demand charges, value of solar tariffs). There is also the two-part challenge of determining broader societal goals and the specific performance metrics to measure how they are being achieved. Different states will certainly have different goals and metrics, and there does not yet seem to be any emerging consensus.

From the utility perspective, it is important to note that while the industry may be changing in very dynamic ways, it is also important to consider the ways in which it remains the same.

This brings us to two final key observations from the roundtable. First, stakeholders and proponents of DER as well as the utilities agree that the regulatory model has to change. Second, communication and collaboration among governors, state legislatures, regulators, and utilities is key to bring performance-based regulation into common practice. In particular, policymakers in state governments need to lead in setting priorities and working with utilities and regulators in designing performance-based regulation that provides a way for utilities to be rewarded for meeting customer demands while still providing safe, reliable, and affordable service.

      

 

 

In September, the Energy Security and Climate Initiative (ESCI) at Brookings held the third meeting of its Coal Task Force (CTF), during which participants discussed the dynamics of three carbon policy instruments: performance standards, cap and trade, and a carbon tax. The dialogue revolved around lessons learned from implementing these policy mechanisms, especially as they relate to coal. This summary reflects the views of various participants in the discussion, who all spoke under Chatham House rule.

Performance standards

A performance standard is commonly viewed as a regulatory tool in which the government sets pollution limits at the plant or unit level (although conceptually it could also apply to larger aggregations of plants, including utility portfolio standards). In the United States, federal performance standards for new power plants began in 1971 as part of the Clean Air Act (CAA), initially applied via heat input standards (reductions targeted around pounds per million BTUs) and later at the unit level in pounds of pollutant per MWh of net electricity output. Over time, companies sought guidance on which technologies to use for compliance, leading to the adoption of technology-specific standards, specifying particular technologies to control specific pollutants. It soon became clear that companies needed more flexibility leading to the enactment of the successful acid rain trading program.

Performance standards can be very effective: The experience with SO₂ scrubbers and NOx systems suggests that CAA standards played a significant role in improving the performance of these technologies and reducing costs. The impact of the CAA is also illustrated by the rising number of SO₂ technology patents in the aftermath of the law’s implementation and subsequent amendments. Moreover, as a result of the program, since the 1990s emissions of pollutants have declined 50 percent even as coal use and electricity output have increased, compliance has surged, health benefits have skyrocketed and costs of compliance have been one-eighth of EPA’s original cost estimates. Nevertheless, there are also drawbacks to using performance standards, chiefly that they can spur higher costs than a more market-based solution, given limits on compliance flexibility. In addition, performance standards provide no incentive to improve emissions reductions beyond set targets.

Importantly, this policy tool has not forced coal plants to retire. In fact, only about 2 percent of the reduction in coal use has been owing to retiring existing facilities. Rather, emissions reductions have resulted from using higher quality coal, fuel switching from coal to gas, and the wide-scale deployment of flue gas desulfurization technology (scrubbers). Combined, these responses have reduced SO₂ emissions, but only coal to gas fuel switching has reduced the actual volume of coal consumed. Since 2008, declines in coal-fired electricity generation are due to federal (MATS) and state greenhouse gas (GHG) standards, as well as the abundant supply of cheap natural gas, renewable portfolio standards, and a recession. Consequently, it is difficult to attribute reduced coal consumption and emissions solely to federal standards.

The question is whether similar clean air standards such as finalized under the EPA’s Clean Power Plan (CPP) will work in the same way as standards governing SO₂ emissions have. There is no straightforward answer. On the one hand, the CPP contains a state-wide rate based option allowing states to use other resources of their choice, including coal. Cap and trade is also an option under the CPP, effectively allowing higher cost (emitting) plants to operate where they choose. On the other hand, the U.S. Energy Information Administration (EIA) projects that under all of its scenarios, coal use in the United States will decline as a result of these new rules.

Emissions trading

An emissions trading mechanism–cap and trade–establishes an emissions cap or limit and allows the trading of rights to emit. A carbon price emerges through the trading system. Our discussion on the emissions trading approach highlighted several examples of carbon emissions trading frameworks, summarizing views on how this policy mechanism has worked to date.

First, the European Emissions Trading Scheme (ETS) has resulted in fuel switching from coal to gas in the electric power sector, and fuel switching from oil to gas in the industrial and heating sectors. The Regional Greenhouse Gas Initiative (RGGI) governing nine states in the north eastern and mid-Atlantic region of the United States has achieved emissions reductions mostly from non-price components, e.g., enhanced energy efficiency. There has also been fuel switching from coal to gas but this has been mostly market driven, i.e., based on low natural gas prices in the wholesale power market. Major CO₂ emissions reductions have been achieved as a result, even though there has been carbon leakage to neighboring states. Finally, as the emissions trading policy in California has been in place only two years, there is limited data available to evaluate its results.

The evidence to date suggests that emissions trading in theory and practice are two different things. These schemes are not as effective as anticipated, i.e., they have failed to deliver the desired volumes of emissions reductions in CO₂. This may be because regulators are in the early learning stages of implementing this tool. Another conclusion is that it is hard to predict the price of allowances. Measures such as a floor price on allowance auctions may be necessary to ensure that the policies retain incentives to innovate and invest in low carbon technologies through economic downturns and other fluctuations. These programs also reveal some of the administrative challenges associated with tracking allowance trades.

In addition, the market design is subject to regulatory capture: emissions trading creates concentrated costs for a powerful few (major emitters) across various sectors, while providing dispersed benefits for the broader population. There is little counterweight to these powerful few, as they play a major role in the design of a cap and trade policy.

In sum, the experience with carbon trading schemes to date suggests that they may be effective in the long-term if they send appropriate pricing signals for long-term investment, but in the short-term their efficacy as policy tools is not as straightforward. Moreover, it seems that sector- and/or technology-specific complementary tools are necessary, allowing for more targeted benefits to “winners” and targeted costs for polluters. Three examples of such complementary tools are:

• Regulating the resource out of the market: Ontario has developed a policy to phase out coal;

• Buying off major polluters: Germany has placed existing lignite plants in a security reserve, essentially paying them to lie idle, but to maintain capacity for an emergency;

• Crowding out: Renewable energy support schemes to bring down the costs of technology, in support of carbon prices.

Carbon tax

A carbon tax sets the price of CO₂ and actual emissions levels emerge from this price signal.

In designing a carbon tax, there are key questions that need to be addressed upfront:

• What emissions are subject to the tax, and who will pay it?

• What will the tax rate be and how will it evolve over time?

• What will the revenue be used for? 

• What will be the impact of the tax on a country’s competitiveness and how will emissions leakages be addressed?

• Will the tax complement other taxes and policies or will it supplant these? 

• What impact will a tax have on the overall policy agenda, for example on other policy goals such as research & development, economic resiliency, etc.?

Research indicates that there are several potential advantages of a carbon tax over other policy instruments. First, it can generate a significant amount of revenue that can be used for broader macroeconomic objectives. To give an example, revenues could be used to help protect lower income households and/or lower corporate tax rates. This type of “tax swap” could have a salutary effect on growth helping to offset the burden of the tax. A carbon tax can thus provide a “double dividend”: emissions reductions and economic growth.

Second, the carbon tax is viewed as a more efficient instrument in comparison to other mechanisms: It sends similar price signals across sectors and over time allows for a predictable capital stock turnover. For example, it is estimated that in the U.S. a carbon tax applied to fewer than 2,500 entities could cover 85 percent of GHG emissions.

Evidence suggests that the revenue neutral carbon tax instituted in British Columbia has worked as intended. Emissions have decreased both in absolute terms and relative to emissions in other provinces, and the economy has grown, also in absolute terms and relative to other provinces. Carbon taxes in other places, such as Norway and Sweden, also appear to be effective. However, the carbon tax in Australia was poorly designed, both economically and politically, and was repealed.

Observations and conclusions

One area of general agreement in the discussion was that reducing carbon emissions is a far more difficult and complex environmental problem than reducing criteria pollutants like SO₂. Carbon is a global stock pollutant, with long-term effects, and is deeply embedded in global economic activity. By way of comparison, the annual value of acid rain permits is about $5 billion, whereas a CO₂ tax would have the equivalent allowance value of $100 billion. Despite the consensus on the science of climate change–and overwhelming agreement that some policy action is required to establish a price signal to limit carbon dioxide emissions–there is far less consensus on what policy mechanism to use.

During the course of our Task Force meeting, participants raised several issues concerning the three carbon reduction policies summarized above.

Leakage, international competitiveness, and impacts on economic growth

There seems to be consensus that, once a policy mechanism establishing a price on carbon is in place, there will be the potential for “leakage,” meaning that carbon intensive activities migrate to those areas that do not price carbon. In those areas without a carbon price, industries would have a competitive advantage. However, there are mechanisms and approaches available to address this outcome, were it to occur, including using revenue (from a cap and trade or carbon tax) to promote growth, implementing border carbon adjustments, and leveraging U.S. diplomatic action. The latter would involve incorporating the United States’ major trading partners in a carbon pricing scheme not only to counter leakage, but also to demonstrate U.S. commitment to reducing GHG emissions.

In addition, with regard to a carbon tax, competitiveness could be preserved by initially implementing a low, but credible tax, and then gradually increasing the tax level. The rationale is that even when a carbon tax starts low, if there is the expectation that it will rise, investors can make decisions based on future prices.

Domestically, the impacts of a carbon price may be more difficult to gauge. Research indicates that the broad impact of a carbon tax will increase electricity prices where they are lowest and reduce or flatten them where they are high. Thus, the overall impact would level out electricity prices out across the economy, though regional differences may remain because electricity generation portfolios vary across the nation. To give an example, the Midwest of the United States is coal intensive, and concerns were raised in our discussion over how to address those states that would be impacted the most. Even with the revenues from a carbon tax earmarked for “pro-growth” tax reform, there was some skepticism over how to avoid a “revenue allocation free-for-all.”

Several issues were raised about the impact of carbon pricing on economic growth. First, there was a question of whether use of revenues from a carbon tax to promote growth might increase economic activity, causing an increase in emissions and thus offsetting the purpose of the carbon tax in the first place. Research indicates that there is some “rebound effect,” that the “pro-growth” approach increases emissions in the 2 to 3 percent range, thus yielding only a minor offset in emissions reductions. Second, an important point was made concerning climate policies in general. Even though there may be a rebound effect, there is also a “spillover effect” whereby the development and deployment of clean technology spurs the use of similar technologies.

Complementarity

Several participants in the task force meeting stated that the experience to date with carbon reduction policies indicates that they need to be complemented with other non-carbon price mechanisms, at least in the short-term. To give an example, in the EU, absent a carbon price that incentivizes investments in low-carbon technologies, a variety of other instruments are used, such as a mandatory minimum share of renewables in the generation portfolio. However, there was some skepticism of this approach, especially with regard to the danger of creating vested interests around those complementary policy instruments (for example, tax credits for renewable energy).

The impact on coal and role of carbon capture and storage (CCS)

The experts presenting to the Task Force agreed that research to date largely indicates that carbon reduction policies, regardless of the type, will significantly and negatively impact coal. In the words of one participant, “de-carbonization means de-coalification.”

CCS may be an avenue for continued coal use, but its high cost remains a barrier to market penetration. However, if there is a consensus to reduce carbon emissions, non-renewable options should be on the table, including a major policy push for CCS. We have discussed this in detail in a recent policy brief on the status of CCS in the United States. There was some discussion of what this CCS policy approach would look like, and some argued in favor of a strong governmental role in research, development, and demonstration of technologies on a larger scale, as well as the need for a carbon price to create a market for CCS technology.

Finally, there was discussion concerning coal use in different geographic regions globally. There are concerns that focusing on the declining role of coal in the United States or wider OECD region fails to take into account the projected rising coal use in developing countries, especially in Asia. This projected expansion provides another important reason to further reduce the costs of CCS technologies and create markets for carbon. Not all participants agreed, however, and some called into question the massive build-out of coal-fired generation in emerging markets as suggested by others. This, including the financing of new coal-fired electricity plants, will be a topic of a future Task Force discussion.

Next steps for Brookings

ESCI’s Coal in the 21st Century project will continue to work on several of the issues raised in this discussion.

As previously mentioned, on October 16 we released an issue brief examining what kind of policy approach will be required in the U.S. to commercialize CCS in order for it to become part of a low-carbon portfolio. This brief was launched at a public event at Brookings, featuring remarks from Carnegie Mellon University’s Professor Edward Rubin and Sasha Mackler, vice president of Summit Carbon Capture.

In late November, ESCI will convene its next installment of the CTF and one of the topics under discussion will be the role, status and future of coal in emerging markets, with a focus on the external financing of coal-fired electricity projects.

Finally, ESCI is working on a policy brief that takes an in-depth look at the role that coal plays in the Indian electricity sector, which is expected to be released in early 2016.

      

 

 

Event Information

As the United Nations Conference on Climate Change in Paris approaches, countries around the world are looking for ways to lower carbon emissions. Germany and Japan are both undertaking dramatic transitions in their electricity sectors, moving away from nuclear energy and deploying more renewable power. Germany has set an ambitious goal of 80 to 95 percent reduction in greenhouse gas emissions and a 60 percent market share for renewables by 2050. In Japan, renewable electricity generation is expected to increase and the future role of nuclear energy is uncertain. Many questions still remain about the progress these countries have made and what lessons can be learned by other nations contemplating their future energy mix.

On October 27, the Energy Security and Climate Initiative (ESCI) at Brookings hosted a discussion on renewable energy transitions in Germany and Japan as a follow-up to a policy brief released on this issue last September. Agora Energiewende Director Patrick Graichen and Yu Nagatomi, a researcher with the Power Market Study Group at the Institute of Energy Economics in Japan, provided initial remarks. ESCI Nonresident Senior Fellow John P. Banks joined in the discussion, and ESCI Senior Fellow Charles K. Ebinger moderated.

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• Lessons from energy transitions in Germany and Japan

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• Uncorrected Transcript (.pdf)

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• 20151027_germany_japan_energy_transcript

      

 

 

Next month, global leaders will convene in Paris for the United Nations Conference on Climate Change. Greenhouse gas (GHG) emissions reduction strategies are important to reduce and manage the risks of climate change. While the share of renewable energy in the global energy mix is expected to increase, transitioning to a low carbon economy will take time, and coal and natural gas are projected to play a prominent role in the power and industrial sectors for a number of decades. Climate mitigation technologies such as carbon capture and storage (CCS)—an integrated process of capturing CO₂ from power generation or industrial activities and storing it permanently via processing or injection into suitable geological formations–can play an important role in global efforts to limit GHG emissions.

Why CCS is important

CCS is a low-carbon technology that can form part of a balanced portfolio approach to address climate change, while also offering economic and national security advantages. Today, CCS is the only technology that can achieve significant emissions reductions (90 percent capture or higher) from existing fossil fuel infrastructure. Indeed, many studies have suggested that unless CCS becomes a key part of a low carbon technology portfolio, it is increasingly likely that energy-system carbon emissions will not be reduced to levels that limit global warming to 2 degrees Celsius.

Fossil fuels will continue to feature prominently in the global energy mix

Climate change is an important global issue, and it has been well documented that continued increases in global carbon emissions are fueled predominantly by fossil fuel usage—particularly coal, and to a lesser extent, oil and natural gas. According to International Energy Agency estimates over the next several decades, coal will play a significant role in the global energy portfolio. While coal demand in OECD countries is projected to fall by 2040, in non-OECD economies such as Africa, India, China, Indonesia, Brazil, and Southeast Asia, coal usage is projected to increase by a third. Coal offers a cheap and abundant feedstock for electricity generation in many emerging markets where increasing access to electricity is a priority. It is also important to note that burning natural gas also results in substantial amounts of CO₂ emissions. Given that the International Energy Agency projects the share of natural gas in the global energy mix to rise, CCS for natural gas will, over time, also become a serious political and environmental issue.

CCS can play a crucial role in addressing climate change

While many countries support renewable energy in order to shift away from reliance on fossil fuels, it is uncertain whether this approach alone will achieve sufficient emissions reductions to achieve the 2 degree Celsius target. Low-emission technologies such as CCS can play a vital role in contributing to global mitigation efforts, and research has shown that in the long run GHG emission reduction would be more expensive without CCS deployment.

Conclusions

In our policy brief, we assess the risks and barriers related to CCS at electricity plants, and the existing policy framework to support its application. Our study aims to identify the major obstacles facing CCS commercialization and offer recommendations for policies that can spur technological innovation and effect further cost reductions.

The key conclusions we reached in our analysis are as follows:

1. CCS can meet environmental, economic, and national security objectives: As a carbon disposal approach that can be deployed on new or existing coal- or natural gas-fired power plants, CCS can help in global efforts to reduce CO₂ emissions. Additionally, positioning the United States at the forefront of CCS technology development fosters export markets for U.S. companies, and including CCS in the global energy technology portfolio lowers the costs of transitioning to a low carbon economy. Finally, CCS bolsters national security by offering a way to take advantage of abundant fossil fuel resources while simultaneously meeting climate mitigation goals.
2. Current policy does not adequately address CCS technology status and risks: While current CCS policy offers early stage financial support for research, development, and demonstration projects, additional policies are needed to spur further development of integrated projects at scale and create markets for CCS technology.
   
   U.S. government financial incentives for CCS
   

   Energy Policy Act of 2005		Energy Improvement and Extension Act of 2008
   Loan Guarantees	Tax Credits*	Tax Credits
   • $8 bilion available • Authorizes DOE to guarantee up to 80 percent of total project costs • Borrowers pay “credit subsidy cost” • Two separate solicitations held in 2008 and 2013 • No projects have received a loan guarantee	• IRC §48A – $2.55 billion available for IGCC and other advanced coal projects • Projects must capture & sequester 65 percent of CO2 emissions, and be in service within 5 years • IRC §48B – $600 million available for gasification projects • Projects must capture & sequester 75 percent of CO2 • Emissions, and be in service within 7 years • Tax credit rate of 30 percent of total project cost available for §48A and §48B • Since 2006, USG has awarded $2.3 billion in tax credits under IRC §48A and §48B	• IRC §45Q provides: • $20/metric ton of CO2 captured and sequestered • $10/metric ton for CO2 used in oil or gas EOR and stored • Credit available up to 75 million metric captured and stored • As of mid-2014, 27 million metric tons have been stored as a result of 45Q • 45Q tax credits will total $700 million in the period 2014 to 2018
   *Some of the original terms of the tax credits under EPACT 2005 were supplemented and revised by the Energy Improvement and Extension Act of 2008. Source: Peter Folger and Molly F. Sherlock, “Clean Coal Loan Guarantees and Tax Incentives: Issues in Brief,” Congressional Research Service, 19 August 2014.

3. A portfolio of “next generation” policies is required: The range of risks along the innovation spectrum involved in commercializing CCS means that a portfolio of multiple policies is required, encompassing front end (helping technology launch) and back-end (helping technology commercialize) approaches. Government action is required to both improve existing policy tools as well as implement new mechanisms that would foster a market for CCS technology, such as policies that would require emissions reductions or directly establish a carbon price. A “next generation” policy portfolio would also need to reflect evolving political realities while also offering a longstanding solution that can hold up amidst political cycles and leadership changes.
4. This policy approach requires government financial support: Though increased financial support certainly poses a political challenge, it is vital to continue to lower the costs of existing technologies, as well as to find and demonstrate new and cheaper technologies.
5. Off-ramps for technologies in research and development pipeline should be considered: Creating a process for deciding if and when to drop research and development for certain technologies if they do not show promise has found increasing support. This approach would require that an agreed process—and likely a supporting institutional structure—be established to govern how decisions to drop certain technologies would be made.
6. Enhanced oil recovery (EOR) is a transitional stepping stone for CCS commercialization: The major promise and potential of CCS is deployment for mitigating climate change, which would mean widespread deployment on power plants and long-term geological storage of billions of tons of CO₂ per year. As this would be well beyond the EOR market, selling CO₂ for EOR should be treated as only a transitional step in CCS commercialization.

Recommendations

Development of CCS as a low carbon technology requires a “next generation” policy framework that recognizes the multitude of risks and political challenges along with the policy mechanisms needed to address them. In our study, we highlight specific mechanisms that we believe should form the basis of a thoughtful discussion on what is required to support commercialization of CCS:

1. Addressing technology risk: A dedicated CCS trust fund supported by a wires or public good surcharge could support R&D and large-scale demonstrations along with other policy incentives and mechanisms. A process and structure for program oversight and management that is targeted specifically to CCS should be created.
2. Addressing financial risk through the revision of existing policy as well as implementation of new policy tools: High capital and operating costs present significant barriers for CCS projects. Access to financing could be improved by modifications to the government loan guarantee program and modifications to tax credits. Additionally, new polices should be implemented that would allow CCS projects to be eligible for master limited partnerships and private activity bonds, as well as financial support for front-end engineering and design work.
3. Addressing climate policy uncertainty through creating markets for CCS technology: A federal carbon policy that requires CO₂ reductions or a sufficiently high price on CO₂ is needed in order to create a market for CCS technology. Additionally, an electricity price stabilization framework would help offset operating costs in markets that are not subject to CO₂ reduction requirements or climate change policy.

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• Fostering low carbon energy: Next generation policy to commercialize CCS in the United States

      

 

 

Event Information

In an effort to address climate change, one low carbon mitigation technology that has been widely discussed is carbon capture and storage (CCS), which offers a way to prevent CO₂ emissions from electricity generation and industrial processes from entering the atmosphere. Despite this potential, CCS has not been widely deployed on a commercial basis in the power sector owing to a variety of risks and challenges. Indeed, CCS is in many ways at a stand-still: While many experts and observers consider it a cost-effective low carbon option in the long-term, without appropriate policy support to address these risks, there remains limited progress in commercializing the technology.

On October 16, the Energy Security and Climate Initiative (ESCI) at Brookings hosted a discussion on the status and future of CCS technology, with a particular focus on the United States. ESCI Acting Director and Fellow Tim Boersma and ESCI Nonresident Senior Fellow John P. Banks presented the findings of their recent issue brief, “Fostering low carbon energy: Next generation policy to commercialize CCS in the United States,” the latest in ESCI’s Coal in the 21st Century series. Vice President of Summit Carbon Capture Sasha Mackler and Edward S. Rubin, alumni chair professor of environmental engineering and science at Carnegie Mellon University, joined the discussion.

 Join the conversation on Twitter using #FutureofCoal

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• Policies to commercialize carbon capture and storage in the United States

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• Uncorrected Transcript (.pdf)

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• 20151016_carbon_capture_transcript

      

 

 

The barrage of news about the progress and promise of electricity storage in the last year just got another jolt from two disparate sources: the U.S. Department of Energy (DOE) and Tesla Motors. On April 21, DOE released the first installment of the Quadrennial Energy Review (QER) focusing on improving the nation’s energy infrastructure and notably referring to “energy transmission, storage, and distribution,” emphasis added. On April 30, Tesla’s CEO Elon Musk announced two new business lines: the PowerWall, a re-chargeable lithium ion battery for homes (in either a 10 kWh or 7 kWh size), and the PowerPack, a 100 kWh battery for grid applications. 

These are only two items in a dizzying array of projections, market developments, reports, and statistics emerging in the last year, highlighting that storage is arguably THE big story in the electricity industry. The U.S. Energy Information Administration recently indicated that non-hydro storage capacity in the United States has doubled in the last five years, to 350 MW. A report from Greentech Media and the Electricity Storage Association estimated that the U.S. energy storage market grew 40 percent in 2014 over the previous year, adding 62 MW of storage–and they predict an additional 220 MW will come online in 2015. The growth in the storage market is not limited to the United States: IHS CERA projects that 40 GW of storage will be connected to the grid globally by 2022.

Unlike discussions surrounding net metering and rooftop solar PV, storage appears less controversial. It’s easy to see why—storage provides many benefits across the entire grid. In research we’ve conducted at Brookings, a cross-section of stakeholders describe storage as “emissions-free capacity,” a source of “time value,” and “a great way to make intermittent resources more valuable.” Indeed, storage can help the entire electricity system operate more efficiently and offers something for everybody:

1. At the wholesale level it can provide ancillary services such as frequency regulation;
2. In generation, it can help integrate variable renewable supply;
3. In transmission, it can provide congestion relief;
4. In distribution, it can provide volt/VAR and peak capacity support;
5. On the customer side, it can provide back-up power and store excess onsite energy generation.

With the advent of more widespread deployment of rooftop solar PV, there has been particular excitement on the customer side of the meter for combining residential solar PV with storage. SolarCity and Telsa are partnering to offer a rooftop solar PV and battery package, and Sungevity and Sonnenbatterie have agreed to offer a solar-plus-battery integrated system. Wall Street also recognizes the solar-plus-storage potential. In May 2014, Barclays stated “we believe a confluence of declining cost trends in distributed solar PV and residential scale power storage is likely to disrupt the status quo.” And UBS in August 2014 said that “Solar systems and batteries will be disruptive technologies for the electricity system.”

But the enthusiasm for storage also extends to the front of the meter. In a recent Utility Dive survey, utility executives were asked to choose the top three technologies they should invest in, and the majority chose storage. The reasons are clear: Storage could help utilities firm-up renewable generation, integrate customer-sited distributed generation, and manage peak load, among other benefits. Indeed, as Katherine Hamilton, policy director at the Electricity Storage Association recently pointed out at a panel that I moderated on storage at Johns Hopkins University, of total storage capacity deployed in the United States in 2014, 90 percent was in front of the meter, and 10 percent was behind the meter (most of the latter was in the commercial sector). 

What’s driving the burgeoning storage market are the inter-related factors of policy and cost declines in storage systems, especially batteries. First, we are seeing more supportive policy and regulations at the state and federal level. As Hamilton explained, there are several main policy drivers for storage: the increasing deployment of variable renewable energy generation, the need to address resilience, grid edge innovation, and the EPA’s Clean Power Plan (CPP). Regarding the CPP, over the next 15 years, in addition to reducing fossil fuel generation, we are going to need 40 GW of peak capacity, and storage can play a role in meeting those peaks.  

Examples of leading policy efforts include California’s mandate under A.B. 2514 for the three investor-owned utilities in the state to procure 1.3 GW of storage capacity by 2020, and Hawaii, New York, and New Jersey are also actively promoting storage. The Federal Energy Regulatory Commission (FERC)’s Order 755 calls on the ISOs/RTOs to allow storage to participate in ancillary service markets, specifically to provide frequency regulation.

Costs are also declining. One study estimated that the cost of lithium ion battery packs for electric vehicles declined 8 percent annually between 2007 and 2014. EPRI forecasts that lithium ion battery packs will be one-quarter of their 2010 price by 2022. 

These trends in policy and technology are impacting the market and two big announcements in November 2014 are illustrative. Southern California Edison (SCE) released the results of a procurement—designed to develop a portfolio of resources to replace the retirement of the San Onofre nuclear station and several large natural gas generation units—in which it awarded contracts for 260 MW of storage. Oncor, the largest transmission and distribution company in Texas, announced plans to invest over $5 billion in storage.

Nevertheless, there are important challenges. First, costs remain high. Lazard’s most recent levelized cost of electricity analysis indicates that battery storage costs are still well above other technologies. But cost issues go beyond the battery itself. As Craig Irwin, clean tech analyst at ROTH Capital Partners emphasized at the Johns Hopkins panel, it is critical to reduce costs in supporting infrastructure such as cooling systems—especially for larger MW-scale deployment—and inverters. He added that other improvements are needed in developing a systematic approach to site specification and buyer education beyond the technologies proposed by specific vendors. Moreover, one of the key lessons of the last 20 years is “that you have to own your supply chain.” In this regard, Tesla’s partnership with Panasonic in the $2 billion development of its Gigafactory designed to produce enough lithium ion batteries for 500,000 cars annually, could move the needle in reducing battery costs. Irwin suggested that today the 85 kWh battery in Tesla’s Model S costs about 25 cents per watt hour, compared to other batteries in the 45 to 50 cents per watt range. With Tesla’s goal of knocking costs down to 10 cents per watt hour, this should help drive down lithium ion battery costs worldwide, but it will also affect the competitiveness of other battery chemistries. In addition, there are a number of other unanswered questions about Tesla’s business model, especially regarding cost at the residential level. 

Second, supportive policy and regulatory frameworks need to be in place to help create markets. The example of PJM is illustrative. Of the 62 MW deployed in the United States last year, two-thirds was deployed in PJM’s territory. Indeed, at utility scale, the biggest market is PJM, largely responding to FERC Order 755. The result, according to Scott Baker, senior business solutions analyst at PJM, is that there are currently 100 MW of storage in the PJM market with another 500 MW in the interconnection queue indicating that “clearly this market is not slowing down.” But, overall, the wholesale ancillary services market is small, with Baker describing it as a “starting point to prove the capability of storage and allow the wholesale market to evolve.”

However, one of the challenges for owners of storage participating in a competitive wholesale market is the unevenness of the revenue stream. For this reason, SCE’s recent procurement of 260 MW of storage capacity changes the landscape. For example, Colleen Lueken, director of market analytics at AES Energy Storage noted that the company not only operates as a merchant in PJM, but also now has a competitively procured power purchase agreement (PPA) to provide storage as capacity and as a flexible resource: AES was selected by SCE to provide 100 MW of in-front-of-the-meter battery storage in the West Los Angeles Basin. This is a far more certain revenue stream than bidding ancillary services into PJM. 

Third, figuring out the right policy and regulatory framework requires more progress in sorting out how to monetize the value of storage in different applications. The basic challenge is that the flexibility of storage—in terms of services it can provide—makes it difficult to fit into existing regulatory rules. As Lueken of AES noted, “to access the full value of energy storage you need to break up the resource from a revenue perspective and be able to provide benefits for different applications.” Arnie Quinn, acting director of energy policy and innovation at FERC echoed this sentiment indicating that “We need to move away from the question of where storage fits, to whether it’s the right solution.” There is progress in this area: Quinn believes that “wholesale markets are moving toward attribute based compensation where we define the attribute of the service we want, and then compensate it.”

In sum, there is great potential for storage both in front of the meter and on the customer side of the meter. Costs need to come down, but the longer-term trajectory indicates that this will happen, and policies and regulations to incentivize storage need to continue to be implemented to spur the creation of markets. The DOE’s QER is a step in the right direction, calling for the establishment “a framework and strategy for storage and flexibility.” 

In the near-term, it is likely that most of the market development and storage capacity deployed will be at the grid-scale in competitive markets such as PJM, but the SCE procurement certainly highlights the impact of supporting policy and regulation in spurring competitively procured PPA-type arrangements. In addition, California’s investor owned utilities have initiated the first round of storage auctions in response to the state’s mandate, with final project selection and submission to the California Public Utilities Commission for approval this coming fall.  

In the longer-term, solar-plus-storage could become increasingly economic on the customer side. Indeed, as Hamilton of the Electricity Storage Association described, the three biggest storage markets in the residential sector are California, Arizona, and Hawaii and what they all have in common is lots of solar. But beyond selected markets, residential-scale storage systems such as Tesla’s PowerPack won’t likely lead to mass defection from the grid in the next five to 10 years. The important point, however, is that Tesla’s announcement—and all the other recent news—is exciting because it shows the progress and potential of a technology with multiple applications and benefits across the grid, providing something for everybody.

      

 

 

Long-term forecasts by the private and public sectors predict that coal will continue to play a significant role in the global energy mix for decades to come. At the same time, coal is the largest source of carbon dioxide and other harmful emissions. 

Energy access is still not the reality for hundreds of millions of people and the world’s population continues to grow. Most of these people will live in emerging markets where access to cheap coal-based electricity is, correctly or incorrectly, often viewed as vital for economic development. The overall increase in global energy demand has momentous implications for the world’s efforts to combat global climate change as well as to improve public health in fast growing emerging economies. This is particularly the case in countries where state of the art new coal technologies are not currently available. Coal exemplifies the difficulty in balancing tradeoffs among the environmental, economic, and energy security objectives embedded in energy policymaking.

The Energy Security and Climate Initiative (ECSI) at Brookings has launched a major new research project, Coal in the 21st Century, to assist policymakers in understanding the complexities associated with coal usage worldwide and provide an unbiased assessment of how to deal with coal moving forward. In this first policy brief, "Coal Markets in Motion," ESCI provides an overview of the global and domestic coal markets, discussing the major trends in coal exports, consumption, and pricing. Internationally, we pay particular attention to China, India, Indonesia, and Australia, who together will account for 70 percent of global coal production by 2040. On the domestic side, we address the state of U.S. coal exports, the impact of climate policy on domestic coal usage, and prospects for clean coal technology in the United States.

Over the course of the next year, ESCI will continue to delve into major issues influencing the future of coal. We invite you to follow our work on our Coal in the 21st Century series page and engage with us in the conversation on Twitter using #FutureofCoal.

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• Coal markets in motion

      

 

 

As Brookings described in an earlier commentary, while it is certainly true that there is a confluence of trends threatening the existing the utility business model, several key developments and challenges demonstrate that a more flexible distribution grid is already emerging with utilities at the center.

First, the power grid in the United States is evolving to meet three critical needs:

1. To integrate new energy resources.
2. To provide customer solutions.
3. To serve as an optimized and efficient platform for energy services and technologies.

Much of what we are talking about regarding innovations and change in the power sector – more distributed resources, more customer engagement and a smarter system that manages two way power and information flows – takes place on the electric distribution grid or distribution system. Thus, in a future that involves more variable generation and more distributed energy resources (such as distributed generation, demand response, energy efficiency and storage) a “flexible distribution grid” is critical. Across the United States, investments in grid technologies, digitization, data analytics, system monitoring, etc. are well underway to enhance the operational efficiency of the distribution grid (and distributed services) and to integrate new energy resources.

In fact, of the expected $100 billion in annual capital expenditures by the investor-owned utilities in the power sector over the next few years, more is going to the distribution system and less to generation. This alone signals the critical importance of the distribution system going forward. As Ted Craver, CEO of Edison International, recently stated: “We’re investing a lot in increasing the capabilities of that grid, of that wires system, of that network. That’s really where we investing the vast majority of our capital…and we wouldn’t do that if we didn’t think that that was actually essential to make all these other things work.”

One example of these capital expenditures is the deployment of smart meters. To-date, the electric utility industry has deployed over 50 million smart meters representing about 43 percent of U.S. households. We view smart meters as the building blocks to integrating new resources into the grid and providing new customer services and solutions (such as smart pricing, outage/restoration management, bill alerts, etc.). Thirty of the largest utilities in the United States have fully deployed smart meters to their residential customers.

Second, a multi-year integrated grid vision is critical for resource optimization.

This isn’t just about IT (information technology) and OT (operations technology) system integration or connecting legacy assets and systems to new ones. It is also about a vision to ensure that future electric distribution grid processes, customer interfaces, and services can be scaled. Scale is what creates efficiencies and cost savings.

Third, the states are leading the policy and regulatory discussion shaping the future of the electric distribution grid.

California, New York and Hawaii are the furthest along. In Hawaii, with a goal of 70 percent clean energy by 2030 for the HECO companies, the focus is on integrating distributed energy resources into the distribution grid. In California, as a result of a wide range of regulations, laws, and policies, the distribution grid is evolving into a network platform and will need to have the capability to integrate about 15 gigawatts of distributed energy resources by 2025. New York state has embarked on a comprehensive, market based plan which includes the Reforming the Energy Vision (REV) regulatory proceeding. The first part of REV involves a “collaborative process to examine the role of distribution utilities in enabling market-based deployment of distributed energy resources.” As a senior New York state official remarked to us, “New York wants to create a platform for third parties to innovate around needs of customers, with the utility getting paid for integrating something onto that platform. We need to figure out how to create markets to get innovation and capture value, and create a business that builds out capital from the customer, not the rate base.” Interestingly, New York is one of the states that has yet to make a significant investment in smart meters for its electricity customers.

Fourth, a critical element for realizing the future flexible and more distributed power grid is getting the pricing right.

A key element is understanding the complete value chain for all parties of distributed energy resources, including both demand-side resources such as energy efficiency and demand response as well as supply-side resources such as solar, storage, combined heat and power and other resources. Getting pricing right is, in part, what New York, California and others are trying to do. This is important because distributed energy resources and large scale renewable resources are increasing exponentially in the United States and are becoming a critical part of the 21st century power grid. For example, in 2010 the United States had just over 2,000 megawatts of solar capacity. In 2014, we expect to have over 14,000 megawatts of solar capacity with much of that growth in solar photovoltaics – a mix of large scale solar, community solar, and rooftop solar.

Fifth, the development of a flexible distribution grid will not be possible without technology and innovation.

Utilities and technology companies are, more than ever, joining forces to deploy an “intelligent, resilient, modern and digital grid.” However, more research and development funds to focus on energy technologies that will make a difference are absolutely critical. The Advanced Research Projects Agency – Energy (ARPA-E) is a key institution working in this area, but its budget of $289 million is a drop in the bucket relative to the Department of Energy’s total budget of $24.8 BILLION! Conversations between ARPA-E and the utilities have escalated with a recognition that technology and innovation are key drivers of business opportunities. While most grid-related projects supported by ARPA-E to-date have focused on transmission, the agency is turning increasingly to distribution – and addressing how a given technology works with other parts of the overall system.

In sum, the “flexible and evolving distribution grid” concept – harnessing the integration of new energy resources, customer solutions and grid efficiency and optimization – points to a central enabling role for utilities as grid builders, operators, and service providers. Many actors – not just in the utility industry – concur on this vital role for utilities. Jim Hughes, CEO of First Solar, Inc., recently stated that utilities need to position themselves as “trying to enable customer choice and innovation... and provide reliability.” And, Thomas Werner, CEO of SunPower, Corp., declared that “the idea that you’re going to eliminate the need for the grid or go off the grid is ridiculous.” Larry Ellison, the former CEO of Oracle, has often referred to the electric utility industry as the best plug-and-play industry in the world. Bob Rowe, president and CEO of NorthWestern Energy sees it this way: “The U.S. power grid, for most customers and most applications, is amazingly ‘plug and play’ in a way that is still aspirational in the IT world.” The challenge is figuring out the institutional, regulatory, and competitive frameworks that will lead to a flexible distribution grid platform that interconnects and enables all of the emerging energy technologies and services that customers want.

      

 

 

Many countries are confronted with the challenge of de-carbonizing their power sectors, but Germany and Japan stand out in their approach. These two global economic powers and major export economies are undertaking a dramatic transformation of their electricity portfolios, characterized most prominently by moving away from nuclear energy and toward the large-scale deployment of renewable energy. The Energy Security Initiative (ESI) has recently completed a research effort examining each country in a new policy brief released today.

In our discussions with stakeholders in both countries, four common themes emerged.

• First, Germany and Japan use the feed-in-tariff (FIT) at the national level as their primary policy instrument to promote renewable energy. Stakeholders in both countries argue that the FIT is superior to quotas or short-term financial incentives, and is the most effective tool in providing a guaranteed long-term revenue stream, stimulating more widespread deployment and bringing costs down.
• Second, both countries are confronted with grid-related challenges in integrating larger shares of renewable energy. These include building more transmission capacity and associated cost and planning requirements.
• Third, the increasing penetration of renewables is posing a challenge for existing electricity markets and for the profitability and existing business model of incumbent utilities. In addition, there is concern in some quarters that rapid transition to renewables is threatening broader economic competitiveness through rising electricity costs.
• Finally, there is criticism that the shutdown of nuclear generating capacity in Germany and Japan is leading to growing use of fossil fuels, increasing CO2 emissions and creating complications for meeting longer-term climate policy goals.

There are also significant differences between the two countries. Japan’s reliance on energy imports in the electricity sector is far greater than Germany’s, and there is currently much more debate and uncertainty in Japan over setting objectives and implementing overall energy policy, specifically the future role of nuclear power. In addition, Germany is a completely unbundled electricity sector with robust wholesale and retail markets, extensive competition and interconnections with neighboring systems and regional markets. In fact, one challenge unique to Germany, relative to Japan, is that of coordination with neighboring systems and integration with the broader European electricity market.

Japan has a regulated market dominated by vertically-integrated, monopolistic utilities, limited interconnections among the utilities’ service territories (owing to an electricity system based on two frequencies), absence of interconnections with neighboring countries’ markets and geographic constraints (limited suitable land area) that all make a transition to higher levels of variable renewable energy very challenging. To address this situation, the Japanese government is targeting much higher levels of renewable energy and has introduced an ambitious plan to restructure dramatically the electricity sector.

ESI’s discussions with stakeholders in Germany and Japan revealed that these policy, market design, regulatory, technical and infrastructure-related issues need to be addressed early and in a cohesive, ongoing manner in order to integrate high levels of renewable capacity. Both the German and Japanese experiences illustrate just how challenging these issues are, but Germany also demonstrates that they can be addressed in a manner allowing renewable energy to play a much larger role in the electricity portfolio of the future.

      

 

 

Event Information

With constant reports of growing and inexorable global climate change and the dangers posed by the world’s continued energy use practices, Germany and Japan stand out in their energy policies and response to climate challenges. These two global economic powers and major export economies are undertaking a dramatic transformation of their electricity supply portfolios, characterized most prominently by moving away from nuclear energy and toward the large-scale deployment of renewable energy. Japan and Germany both offer important lessons for the United States as it tries to reformulate its own energy policies.

On September 19, the Energy Security Initiative (ESI) at Brookings hosted a discussion on renewable energy in Germany and Japan. This event served as the launch of ESI’s new policy brief, “Transforming the Electricity Portfolio: Lessons from Germany and Japan in Deploying Renewable Energy.” Report authors John Banks, a nonresident senior fellow with ESI, and Charles Ebinger, ESI’s director, joined ESI Nonresident Senior Fellow and Public Policy Consulting Principal Ron Binz in a panel discussion on the findings of the study. Lisa Wood, the executive director for the Institute for Electric Innovation and a nonresident senior fellow at ESI, moderated.

Join the conversation on Twitter using #Renewables

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• Transforming the Electricity Portfolio: Lessons from Germany and Japan in Deploying Renewable Energy

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• Transcript (.pdf)

Event Materials

• 20140919_Electricity_portfolio_transcript

      

 

 

Amid an ongoing international debate on the reduction of carbon emissions, Germany and Japan are undertaking a dramatic shift in their electricity portfolios. The 2011 Japanese earthquake and the subsequent Fukushima Daiichi nuclear facility accident have sparked both Japanese and German energy policy to shift away from carbon-free nuclear energy and towards renewables. However, despite large gains in market share by renewables, these two countries have seen increases in both fossil fuel usage and carbon emissions as the market share of nuclear energy has declined.

This shift raises fundamental energy policy questions: how can countries simultaneously decarbonize their electricity mix while phasing out nuclear energy? What are the costs and challenges of large-scale renewable integration? Who will bear these costs? In the Energy Security Initiative’s latest policy brief, authors John Banks, Charles Ebinger and Alisa Schackmann seek to answer these questions while identifying potential relevant lessons for large-scale deployment of renewables in the United States.

     

 

 

In the past several years there has been intense discussion over the future of the electricity industry, centering on how existing utilities will adapt and evolve as they confront numerous transformational challenges.

A recent working paper from the Governance Studies program at Brookings examining the characteristics of the millennial generation offers some insights into this question. Millennials, or those born after 1982, will account for one-third of the adult population by 2020 and 75 percent of the workforce by 2025. Thus, what this group wants and how it behaves will be critically important for the future of utilities and the electricity sector broadly.  

Of the many characteristics of the millennial generation assessed in the paper, three struck me as noteworthy for the electricity industry.

• First, in contrast to previous generations, millennials are socially conscious: they shop and buy products and services from entities that prioritize social causes that align with theirs, including the environment.
• Second, they distrust big companies: in one survey, 83 percent of millennials agreed with the statement that “there is too much power concentrated in the hands of a few big companies.”
• Third, this generation is more favorable to government regulation: in another survey, most millennials disagree with the statement that “government regulation of business usually does more harm than good.”

It’s not hard to see the potential impact on traditional utilities: this generation is more disposed to support clean energy, wants more choice in its energy decision-making, and may favorably view government intervention to achieve these goals.

More specifically, the millennial customer wants information, services and products that meet the criteria of the three “Cs”: cheap, convenient and cool. For a moment, let’s consider what “convenient” means. First and foremost, customers want information and services instantaneously and accessible anytime, anywhere. But, perhaps more importantly, they want personalization, packaging and sharing. Personalization refers to the ability to customize how they get their information and service. Packaging refers to the ability to access multiple products in one place. Finally, this generation loves to share: any service that allows sharing of information or the ability to collectively benefit is highly valued – just think of Twitter, iTunes, Facebook, YouTube and Uber.  

These are exactly the main challenges confronting traditional utilities. Utilities are not used to personalizing their product for customers. Instead, they have provided electricity to essentially captive customers and have not had to win, retain or otherwise figure out what their customers want. Utilities have also not had to package their product with other distinct services or products to meet customer needs because they have largely focused on selling one product reliably and cheaply.  In addition, sharing is not a traditional utility characteristic. As one municipal utility executive recently pointed out, “utilities love their assets and their territories,” suggesting that they are not inclined to partner with others to share their market.

Utilities who will thrive in the coming years are the ones who will find ways to understand and meet the needs and preferences of the millennial generation and especially the millennial customer. We already see signs of this. Utilities are well-placed to develop and utilize customer information, and the emergence of “data analytics” as a hot topic is reflective of utilities trying to figure out how to access and use – or "personalize" – customer information.  

Utilities are also increasingly sharing their traditional business space by partnering to expand services. The Institute for Electric Innovation recently documented dozens of examples of utilities working with technology companies to meet customer needs at the industrial, commercial and residential levels. In another example of this trend, some utilities are partnering with solar companies to develop community solar projects for customers who might not otherwise have the ability to install solar technology on their rooftops.

Packaging is also a trend utilities may increasingly consider – where the utility serves as an “optimizer” or “integrator” (think bundling of services or functioning as a gateway for customers to a variety of services and technologies). Their potential competitors are already making steps in this direction: Google’s purchase of NEST and the latter’s acquisition of Dropcam are examples of combining electricity with home energy management services. Comcast’s venture with a retail electric supplier in Pennsylvania is an example of bundling electricity with cable, internet and telecom services.  

Maybe the real challenge for utilities, though, is the third “C:” what can utilities offer that is “cool”? One investor-owned utility executive admitted to me that this might be the biggest challenge – utilities are not seen as cool. Moreover, if they are viewed as the big incumbent pushing back against clean energy and protecting their existing business model (fighting net metering, for example), this will not bode well for the relationship with millennials. On top of this, there is considerable competition with new entrants, those non-utilities offering a variety of services and products from generation to end-use. Do utilities embrace them, or compete with them? I admit that I don’t yet see what the business model will look like that allows utilities to offer a cool product or service in the same manner as the latest app or start-up. But that doesn’t mean it’s not out there, or that utilities should not be looking for it.

Finally, utilities need to consider another angle. The millennials are not only the utilities’ customers of the future, but are also their future workforce. How does the industry attract this generation? In my role as an educator I see more and more students each year interested in the electricity sector as a career path, in particular in those “new entrants” mentioned above in areas such as energy efficiency, renewable energy, distributed energy, storage and vehicle electrification. Students have gone out and test-drove a Tesla after our class on electric vehicles, and I often get asked about other companies such as Solar City, Silver Spring Networks, EnerNOC and Opower. These are seen as “cool,” and reflect the statement by David Crane, CEO of NRG, that “there is no Amazon, Apple, Facebook or Google in the American energy industry today.” He was referring to these four companies’ ability to give customers what they want – the three “Cs” – but it applies also to their ability to offer an exciting and innovative place to work.

     

 

 

Germany’s energy transition, or Energiewende, offers lessons for the United States, just not the ones typically cited on this side of the Atlantic. The challenges and concerns that have arisen in Germany should not be taken as indicators that the Energiewende is failed policy, or more specifically, to dismiss the importance of renewable energy.

In the past year the U.S. Government has intensified efforts to highlight climate change as a critical national policy issue. The White House unveiled a Climate Action Plan in June 2013 outlining three ways to address climate change, including reducing carbon emissions from power plants. In March 2014, the Department of Defense’s Quadrennial Defense Review 2014 concluded that the impacts of climate change are “threat multipliers.” In May, the Global Change Research Program released the National Climate Assessment, concluding that the U.S. is already experiencing the impacts of climate change, from drought, severe weather, ocean acidification and sea level rise. Then on June 2, 2014, the EPA issued its proposed rules to reduce carbon emissions from existing power plants by 30 percent by 2030.

This revitalized interest in crafting policy to address greenhouse gas emissions, in particular from the electric power sector, is in contrast to Germany which, for over a decade, has had a robust, comprehensive energy-climate policy centered on dramatically increasing the share of renewable energy in the electricity portfolio, and since Fukushima accelerating the phase-out of nuclear power. The cornerstone of the support for renewable energy is a feed-in tariff (FIT) providing a guaranteed above-market price and grid access for power generated from a renewable energy source over a fixed, long-term period (e.g. 20 years).

The results are impressive. Germany’s share of gross electricity consumption from renewable sources increased from 6 percent to 17 percent of the national total in just one decade (2000- 2010), and renewables now account for 23 percent of electricity consumption, surpassing the government’s goals: they had been projected to reach 20 percent by 2020. In addition, the country is on pace for much larger capacity additions: by 2022, it is expected that Germany will have 220 GW of total capacity, of which 90 GW will be from conventional sources and 130 GW from renewables, with wind and solar accounting for 90 percent of the added renewable power capacity.

German policymakers also point to robust investment in the country’s energy sector, job creation, a burst of renewable energy technology innovation and Germany’s status as a global leader in the renewable energy sector as positive outcomes of the Energiewende.

Nevertheless, the Energiewende also poses challenges. During a recent Brookings private roundtable with German counterparts, U.S. utility industry representatives expressed skepticism regarding the efficacy and viability of the Energiewende, reflected in the following issues and questions raised during the meeting:

• Cost Impact on Households. Would rising household rates evidenced in Germany be acceptable in the United States? 
• Implications for the Economy and Industrial Competitiveness. How do the costs of renewable energy policy affect long-term economic growth and competitiveness? 
• Impact on utilities. Will traditional utilities be driven out of business? Or are new business models emerging? 
• Fairness and equity. Would a policy in which one sector (households) bears most of the costs be politically or socially viable in the United States? 
• Technical barriers. How is Germany overcoming technical challenges in integrating large shares of variable renewable energy, including impacts on neighboring countries? 

The Energy Security Initiative (ESI) at Brookings will be exploring these and other issues in detail in a policy brief to be released later this summer, but for now, based on our roundtable discussion and related research, we can see that Germany’s Energiewende provides several useful lessons for the U.S. as it thinks strategically about the future of its electricity industry.

1. Setting objectives and developing national policy are important. If a country can agree politically on fundamental objectives, designing and implementing effective policy mechanisms is easier. For German policymakers, renewable energy is a pathway to achieve the environmental objective of addressing climate change, as well as to bolster economic goals (promoting a new industry, creating jobs, stimulating exports and trade), and enhance security (diversifying sources of energy). In spite of high costs, and despite the realization that elements of the Energiewende need to be reworked, Germany has rolled out a sweeping and effective suite of policies and legislation successfully, supported by a remarkable political and social consensus. In particular, it has been able to come to an agreement about the exigencies of climate change and the importance of emissions reductions, as well as reach a strong consensus on phasing out nuclear power primarily for safety concerns. Gaining a consensus on a clear policy direction is critically important and should precede and inform debates about which specific policy mechanisms to implement and how.

2. Monitoring and course corrections are required, with solutions tailored to local conditions. Policymakers should be prepared not only to monitor continually the effectiveness of policy, but also to alter the policy as technology and market conditions change. Importantly, fine-tuning policy or market design should not be viewed as a failure.

   German policymakers acknowledge that the FIT policy was not responsive sufficiently to market and technological changes. As a result, proposed revisions to the law currently under consideration are intended to make policy more market-oriented, moderate renewable energy capacity additions, and have industry shoulder more of the cost. Policymakers also are focused increasingly on how to adapt market design in order to ensure sufficient flexibility to accommodate high levels of variable renewable energy.

   Even supporters of the Energiewende do not believe that other countries should follow suit with exactly the same approach, and recognize the enormous scope of the challenge. German policymakers see the energy transition as a worthwhile experiment in the global effort to address climate change, and accept that this will come at a high cost. As one architect of the renewable policy has noted, “With the Renewable Energy Act that we created in 2000, we financed a learning curve that was expensive. But the good news is that we have learned in only 13 years to produce electricity with wind power and solar facilities at the same price as if we were to build new coal or gas power stations.”

   Moreover, cultural, economic and industry differences between the two countries mean that we cannot expect every element of the Energiewende to work in the U.S. For example, the FIT is not likely to be a policy tool widely deployed in the United States. As part of Brookings’ research in recent years, we have heard considerable skepticism of this approach among key stakeholders, with concerns largely revolving around the experience with the Public Utility Regulatory Policies Act. Abundant, cheap natural gas also seems to offer one low-cost and politically palatable pathway to reduce carbon emissions significantly (i.e., a widely available alternative to coal), though over-reliance on natural gas brings its own set of challenges.

   In addition, electricity consumption of the average American household is significantly greater than the average German family of four which uses about 3,500 kWh/year, while the U.S. average is 10,800 kWh/year, making a U.S. ratepayer much more sensitive to price increases. Furthermore, despite the Energiewende’s costs, German households and politicians remain ideologically committed to the goal of emissions reduction and highly tolerant of the associated costs. The fact that alarm over climate change and its impacts have not penetrated American politics or society in the same way may be the most significant cultural difference between the two countries and may explain American disbelief that Germans could remain supportive of an increasingly costly policy.

3. A high level of renewable penetration presents unique challenges, but is manageable. Germany has demonstrated that high levels of renewable energy penetration are possible, with limited to no impact on reliability and system stability. This is commensurate with numerous recent studies that have concluded that “proven technologies and practices can dramatically reduce the cost of operating high penetration variable renewable energy,” including at penetration levels above 50 percent, without negative impacts on reliability. A recent analysis from the International Energy Agency stated that system integration of renewables is not a “significant challenge” at penetration levels of up to 10 percent of total generation, although “minimizing total system costs at high shares…requires a strategic approach to adapting and transforming the energy system as a whole.” Cost-effective solutions are emerging for implementing this system transformation approach – some in Germany – including developing market rules that enable system flexibility, diversifying resources and expanding the geographic footprint of operations, and improving system operations. In particular, resources such as demand response, storage and energy efficiency are important tools complementing such a systemic transformation. Indeed, we are witnessing higher renewable energy penetration levels in several U.S. states. In Iowa and South Dakota, for example, wind provides more than 25 percent of total electricity generation. In short, high shares of renewable energy in the electricity mix present less of a challenge for technical integration, than for existing business models and market design. 

We don’t have to copy the Energiewende in the United States. We should, however, not let challenges raised in Germany’s experiment disparage renewable energy. Rather it is an abundant natural resource that can serve as a critical asset in meeting multiple energy policy goals: economic, environmental and national security.

On April 29, 2014, ESI hosted its second Global Electricity and Technology Roundtable, chaired and moderated by Charles K. Ebinger, Director and Senior Fellow at ESI, and Mr. Jim Rogers, Former Chairman and CEO of Duke Energy, and a Trustee of Brookings. In this off-the-record session, ESI brought together U.S. electricity industry stakeholders and German experts to share their perspectives, raise questions and discuss concerns regarding the Energiewende and its impacts. In this post, Brookings’ Nonresident Senior Fellow John P. Banks and Kathryn Archer, Economist at Keybridge, describe key takeaways from the Roundtable. Some information in this post is taken from a Brookings policy brief in progress with the working title “Transforming the Electricity Portfolio: Lessons from Germany and Japan in Deploying Renewable Energy.” The views expressed are those of the authors only.

     

 

 

The Arctic is changing. As the polar ice cap recedes, new shipping routes are opening up and access to Arctic energy resources is expanding. John Banks, a nonresident senior fellow with the Energy Security Initiative at Brookings, explains what these changes mean for Arctic governance and for U.S. leadership of the Arctic Council in 2015.

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• Offshore Oil and Gas Governance in the Arctic: A Leadership Role for the United States:
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• Finland Trip Report: Harnessing Offshore Opportunities in the Arctic
• Energy, Indigenous Communities and the Arctic Council
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The Arctic is estimated to hold large undiscovered oil and gas resources – the vast majority located offshore. As a result of climate change and the retreat of Arctic sea ice, the waters of the region are increasingly open for longer periods of the year. Despite unique environmental conditions, regulatory uncertainties, and high costs, there is broad agreement that there will be increased offshore hydrocarbon activity in the future. The Arctic coastal states support offshore oil and gas development, and there is significant commercial interest and growing activity in the region.

On March 26, the Energy Security Initiative (ESI) at Brookings hosted a discussion to launch the release of Offshore Oil and Gas Governance in the Arctic: A Leadership Role for the U.S., its Policy Brief on how the U.S. can meet the challenges posed by this activity, especially as it assumes Chairmanship of the Arctic Council in 2015.This Policy Brief is the result of a year of research including over 80 interviews with leading Arctic specialists (government, industry, academia, native leaders, and NGOs) across the region.

Heather Conley, director of the Europe Program at the Center for Strategic and International Studies moderated a discussion with two co-authors of the Brookings policy brief: Charles Ebinger, senior fellow and director of ESI and John Banks, nonresident senior fellow at ESI.

Join the conversation on Twitter using #ArcticEnergy

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• Offshore Oil and Gas Governance in the Arctic: A Leadership Role for the United States

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The Arctic is changing and increasingly drawing the world's interest, with the potential for vast reserves of offshore oil and gas constituting arguably the most attractive, yet challenging prospect in the region:

 
As the U.S. prepares to assume chairmanship of the Arctic Council in 2015, this policy brief is designed to inform the legislative and executive branches of the U.S. Government of the current state of oil and gas governance in the Arctic, and to address the following questions:

How can the U.S. elevate the Arctic region as a priority national interest?

How can the U.S. lead in strengthening offshore oil and gas governance in the Arctic?
 

     

 

 

The oil and gas boom in the United States is overshadowing another revolution in electricity. Changes are occurring that will alter dramatically the fundamental structure and operations of this century-old industry, and electricity will play a greater role in the national economy and energy sector with attendant effects on national security.

The Slow Burn

Recently, there has been considerable attention given to the threats posed to the traditional utility business model by distributed generation (DG). Dire headlines abound: “Why the U.S. power grid’s days are numbered,” “Renewables turn utilities into dinosaurs of the energy world,” “Adapt or die? Private utilities and the distributed energy juggernaut,” and “The end of utilities.”[1] This theme is not limited to the U.S.: in a recent strategy paper RWE (Germany’s second largest utility) noted that “the growth of German photovoltaics constitutes a serious problem for RWE which may even threaten the company’s survival.”[2]

But in reality, distributed generation represents the most recent trend in a decades-old evolution of a changing industry. Since the late 1970s, utilities in the U.S. have been undergoing changes that cumulatively have chipped away at the traditional regulated, vertically-integrated industry model. This erosion of monopoly control started with generation after the 1978 passage of Public Utility Regulatory Policies Act (PURPA) spurring the build-out of non-utility independent power generation: In 2011, this represented about 40 percent of total installed capacity in the U.S. The Energy Policy Act of 1992 and several subsequent Federal Energy Regulatory Commission (FERC) orders created open access to the grid and led to the formation of independent system operators (ISOs) and regional transmission organizations (RTOs) governing transmission primarily in the Northeast and the Midwest. Starting in the late 1990s, the restructuring of utilities in 15 states and the District of Columbia further eroded the revenue earning asset base of the industry by unbundling generation.  

Now the last bastion of the utility’s monopoly business – distribution – is under attack. Solar photovoltaic PV distributed generation is being deployed at such a fast pace that many stakeholders see a disruptive trend impacting the financial health of the utilities over the long-term.[3] In particular, utilities are increasingly advocating an overhaul of the net metering policy originally established to incentivize distributed generation. When the first net energy metering policy was passed in Minnesota in 1983, renewable energy sources contributed a negligible part of the country’s energy mix. Although the percentage is still quite low, the growth in the past few years has been exponential. According to the Lawrence Berkeley National Laboratory, cumulative PV capacity in the U.S. reached 500 MW in 2007, doubled by 2009, and then doubled again in 2010 and 2011.[4] The popularity of solar reflects several factors, including falling solar prices, state mandates requiring renewable energy and distributed generation, a policy emphasis on de-carbonizing the electricity portfolio, a growing interest in local self-reliance, and a business model that takes advantage of the net metering tariff mechanism.

All of this has taken place amid a decoupling of GDP growth from electricity consumption. During the 1960s, a 1 percent increase in GDP corresponded to about a 2 percent increase in electricity sales. By the 1990s, a 1 percent increase in GDP accounted for less than 1 percent growth in electricity sales.  In a recent report, the Natural Resources Defense Council highlighted that since 2000, “for first time in modern history, the national growth rate for electricity consumption has dropped below that of the population for an extended period.”[5] This decoupling has come as a result of rapid advancements in technology, including the expanded use of highly efficient natural gas combined cycle plants, and the widespread deployment of energy efficiency programs.  In fact, while the number of electronic devices in our homes has grown rapidly over the past 10 years, the overall electricity use associated with them has not grown that much owing to efficiency gains. So, in fact, the same amount of electricity provides far more value today than it did a decade ago. Improvements in efficiency have allowed the financial health of utilities in many jurisdictions to be decoupled from the quantity of electricity sold, edging some utilities away from a commodity-based business model. As the demand curve plateaus (described below), it will be increasingly important to reward utilities for generating more electricity with less. Thus far electricity providers have not been systematically rewarded for investments in efficiency in the same way as they have been for increasing generation capacity.

Turning up the heat

Now, however, several major trends are converging to accelerate potentially far more existential changes with wide-ranging implications.

First, over the next several decades the real price of electricity will rise in stark contrast to the past 50 years where the real price of electricity has been flat. Meanwhile replacing or retiring virtually every power plant by 2050 (except hydro facilities) including 70 percent of the nation’s existing carbon-free generating capacity, modernizing the grid, meeting stricter environmental regulations and renewable mandates, and upgrading the transmission and distribution infrastructure are all converging to exert upward pressure on utility expenditures. For example, the annual capital expenditures of U.S., investor-owned utilities in 2012 and 2013 have been around $95 billion, the most of any sector, and the Brattle Group has estimated that $1.5 to $2 trillion in investment is required by 2030 in the U.S. electric utility industry, mostly in generation.[6]

Second, rising costs are occurring against a flat to declining demand for electricity. The U.S. Energy Information Administration forecasts that electricity demand will increase just 0.9% per year by 2040, representing a marked difference from growth rates in most of the 20th century. Slower economic growth and the accelerated deployment of energy efficiency programs, codes and standards, and demand response are flattening demand. At the same time, the structure of demand is changing with the enormous increase in information and communications technologies. As one analyst has noted the “always-on” digital economy is driving the need for more resilient and reliable power supply for microprocessors, data centers, and an array of home and office devices.[7]

Third, we’re witnessing the increasing threat of cyber attacks – a recent congressional survey of the industry revealed that many utilities report being “subject to daily, frequent or constant cyber attacks.”[8] Perhaps not receiving as much attention is the threat of physical attacks on infrastructure, some of which have already caused smaller scale outages around the country.

Fourth, the increasing frequency of extreme weather events, such as Hurricane Sandy, is forcing utilities to spend more on grid resiliency and reliability. This is extremely important to customers in today’s electricity driven economy. Given these trends, utilities are working to optimize the grid, deploy sensors across the grid, manage around problem areas, and create a more flexible grid. In some cases, utilities are looking at micro-grids and “islanding” parts of the power system, particularly around critical facilities.

Fifth, rising costs, flat demand and increasing concerns related to the integrity, security, and resiliency of the grid mentioned above are occurring as the costs of solar and wind technologies decline and policy support for renewable energy has increased. These trends are driving greater interest in distributed energy resources (DER), a combination of various distributed sources of power production, energy storage, and demand-side resources. With the increasing deployment of DER, the electricity system will become less reliant on large, centralized generation, and become more decentralized with many households, institutions, and localized mini- or micro-grids producing power for their own use and/or possibly selling back to the grid.

Proponents of DER and greater decentralization tout an array of benefits including improved efficiency of the distribution system, reduced strain on the grid during peak demand periods, providing back-up generation to improve system reliability, offsetting costs of new or upgraded transmission and generation assets, reducing environmental impacts of power generation, decreasing the vulnerability of the civilian grid to disruption and attack, and as a resource for the defensive and offensive operations of the U.S. military. Critics and skeptics of DER highlight the high cost of distributed sources of power generation, including integration and management costs, and the danger of subsidies and incentives for DER technologies creating an unfair burden for customers not deploying them. This latter issue is raising specific concerns amongst utilities that the net metering approach in place today in most states results in a significant and unfair cost shifting from DG customers to non-DG customers. This has spawned a variety of efforts to seek better ways to value the costs and benefits of DG, in particular rooftop solar PV.

Sixth, other technology innovations are driving decentralization of electricity and empowering consumers with greater knowledge and choice in their energy use. The proliferation of grid modernization technologies—generally referring to the convergence of energy technology and information communications technologies —represents the intersection of the physical power layer (transmission and distribution system) with a data transport and control layer (communications and control), and an applications layer (applications and services) that enables two-way information and power flow between utilities and consumers. As a result, consumers are becoming more actively engaged, becoming what some call “prosumers,” both producers and consumers of electricity.  

Seventh, all of the above trends are occurring simultaneously and rapidly, outstripping the adequacy and relevance of existing regulatory and business models. There is a consensus that a new regulatory paradigm is needed. It should address not just efficient rate design, but more broadly a greater degree of flexibility critical to ensuring that utilities and consumers are properly incentivized to help meet the requirements of the transformation underway.  As America’s Power Plan states, “the power sector increasingly demands a service business rather than a commodity business,” and thus a move is required from the existing regulatory model that asks “did we get what we paid for?” to a performance-based model that asks “did we get what we wanted?”[9] Regulatory and pricing reform will allow utilities to adopt technologies faster, as the existing discrepancy between the cycle of adoption (three to five years) for utilities and the rate of technological improvement (six to 18 months) is a major source of inefficiency and lost opportunity.

The existing utility business model is also under threat: the transformative trends described above are creating opportunities for a wide array of new players providing services. Some call this “disintermediation,” or “edge power” where services such as data analytics, DG, storage, demand response, energy efficiency, and financing, are provided by non-utility entities along the value chain from generation to customer end-use. How are utilities reacting and what future utility business models could emerge?  Most analysts suggest three pathways along a wide spectrum of utility activity and involvement in the market: In one model, the utility serves as a wires and battery company providing only the grid and back-up power; in the second a utility plays the role of “optimizer” or “integrator” of grid services and new services and applications; and in the third, the utility becomes an energy services company engaging in a full range of activities on both sides of the meter.[10] It remains to be seen what models or hybrids may evolve, but it appears many utilities recognize the challenge and opportunity: for example, in the most recent global power and utility survey conducted by PwC, 82 percent of the companies participating viewed distributed power generation as an “opportunity” vs. 18 percent as a “threat.”[11]

The Emerging Market Challenge

Finally, while distributed generation will be incorporated in the U.S. and other industrialized countries, the real application is in the developing world. This is where the most critical learning will occur and where costs will come down even faster. Most importantly, however, distributed generation for people with no access or limited access to electricity addresses an issue that is in the U.S. national security interest.[12] There are 1.3 billion people in developing countries – or 20 percent of the world’s population – who have no access to electricity. By some estimates as many as 2 billion others have very limited access, perhaps one fan and several light bulbs. This energy poverty has highly detrimental effects on the quality of life: per capita consumption of electricity is linked to a variety of human development indicators such as life expectancy, school enrollment, the empowerment of women and girls, availability of life saving vaccines, and access to clean water. Lack of access to electricity also undermines economic development, fueling political instability and the creation of failed states. Without electricity and other forms of commercial energy to support economic growth and modernization, the pathway to jobs and the middle class for hundreds of millions of young people in the developing world will be stymied, sowing growing dissatisfaction.

In sum, we can no longer afford to take electricity for granted. Most people probably couldn’t say how many kWh they use in a month, what they pay for a kWh, what fuel source is used to generate the electrons they use in their home or business, and how those electrons get to their flat screen TVs, iPhones, air conditioners, and DVRs. Most assuredly, most could not fathom – or accept – the indignity of daily life without power that is the norm for billions throughout the developing world, and how this intolerable situation goes beyond a humanitarian issue to affect our long-term national security interests. Nevertheless, electricity is undergoing dramatic changes at the nexus of the economy, environment and national security. Indeed, we are in the midst of an electricity revolution arguably more transformative than shale gas and tight oil.

On October 8, 2013 the Energy Security Initiative (ESI) launched its first Global Electricity and Technology Roundtable, chaired and moderated by Dr. Charles K. Ebinger, Director and Senior Fellow at ESI, and Mr. Jim Rogers, Chairman of Duke Energy, and a Trustee of Brookings. The purpose of this and future roundtables is to gather a cross-section of stakeholders to discuss major issues challenging the industry. In this essay, Dr. Ebinger and Nonresident Senior Fellow John P. Banks summarize and expand on key issues raised during the October roundtable. They emphasize that major transformative trends are underway, and that electricity is assuming far more prominence at the nexus of the environment, economy, and national security. 

     

 

 

Editor's note: In this chapter from Energy and Security: Strategies for a World in Transition, Charles Ebinger and John P. Banks write that a focus on fiscal austerity and the boom in U.S. domestic hydrocarbons cannot be allowed to shift the progress of U.S. policy away from the objectives of eliminating energy poverty and expanding electricity access. Read the beginning below and buy the whole book here.

Ensuring access to affordable energy for the world’s population has been on the agenda of governments and other institutions worldwide since the oil price shocks of the 1970s staggered the world economy. Although the price spikes had a devastating impact on the macroeconomies of all nations, the skyrocketing costs of imported oil in developing countries had an especially destabilizing effect. In India and Pakistan, farmers either could not obtain oil or had to pay staggeringly high prices to run their tube well irrigation pumps. In much of Asia and Africa, the oil price rise led to a surge in demand for fuelwood, forcing women and girls to spend many more hours a day searching for fuel far from their villages. At the same time, the demand for fuelwood led to accelerated deforestation and rising emissions of greenhouse gases (GHGs), both from the greater use of fuelwood and from the removal of large forests that had previously served as global carbon sinks. In the desert regions of the world, the destruction of already fragile vegetation for use as energy led to growing desertification and the first climate change refugees.

Although these events increased the focus on energy in the world’s poorest nations—reflected in the demand by the Group of 77 at the Conference on International Economic Cooperation held in Paris in 1977 for enhanced energy access—the world development community was slow to recognize the critical role that energy, in requisite volumes and at affordable prices, plays in all key development issues. Too often energy was viewed as a subsidiary issue to addressing a host of socioeconomic human development challenges, such as poverty eradication, improved health, higher crop yields, greater access to markets for goods and services, and female empowerment.

Access to electricity is particularly important for most measures of human development, economic modernization, and living standards. Although there has been progress—the electrification rate in developing countries increased from 25 percent to 76 percent from 1970 to 2010— an unacceptably high percentage of the developing world’s population re¬mains without access to power.

     

 

 

Despite Africa being the “new frontier” in oil and gas resources, much of the population still has little to no access to energy and electricity. John P. Banks discusses why both these trends deserve more attention from the U.S. for economic, national security and humanitarian reasons.

This chapter is part of Top Five Reasons Why Africa Should Be a Priority for the United States. Read the full report here and tell us why you think Africa matters to the U.S. Join the conversation on Twitter using #AfricaMatters.

The Priority

The countries of sub-Saharan Africa are confronted with a confluence of energy challenges and opportunities directly relevant for U.S. foreign policy and economic interests.

The first challenge is the lack of access to affordable, modern forms of commercial energy. The International Energy Agency (IEA) estimates that there are 590 million people in sub-Saharan Africa, mostly in rural areas, without access to electricity, representing nearly 6 in 10 people in the region.[1] In addition, 700 million people, or 70 percent of the population, rely on traditional, non-commercial sources of energy, such as biomass, for cooking.

Second, with the exception of a few oil-producing states, sub-Saharan African countries do not have large domestic energy resources, relying on imports of energy for over 65 percent of total energy use.[2] The IEA recently estimated that the region spends more on oil imports ($18 billion) than it receives in international aid ($15.6 billion),[3] with attendant negative impacts on trade balances, debt and GDP growth.

Third, significant new discoveries have prompted the IEA to anoint sub-Saharan Africa the “new frontier” in global oil and gas.[4] Countries such as Cameroon, Ghana, Equatorial Guinea, the Republic of the Congo, Kenya, Tanzania and Uganda are emerging as potentially major new producers of oil. There have also been discoveries of large offshore natural gas resources in Mozambique and Tanzania, prompting plans to develop East Africa into a major exporter of liquefied natural gas. South Africa is estimated to have significant shale gas resources as well.

Why is it Important for the U.S.?

Failure to expand energy access, reduce energy imports, diversify energy sources and manage newfound oil and gas wealth for the benefit of society, especially the poor, directly impacts U.S. interests.

Humanitarian Interests

There is a clear moral imperative for the U.S. to play a leading role in expanding energy access for hundreds of millions of people in the region. Helping to lift people out of energy poverty—creating dignified living conditions and expanding economic opportunity— is consistent with our democratic values.

National Security Interests

Energy poverty undermines economic development, fueling political instability and the creation of failed states that can harbor our enemies and threaten our allies. Indeed, there is a strong correlation between political stability and electrification rates. A joint effort of the Fund for Peace and Foreign Policy magazine, the Failed States Index indicates that 15 of world’s 20 most vulnerable states are in sub-Saharan Africa, many with electrification rates below 20 percent. Among them are countries confronted with the emergence of non-state terrorist groups or undergoing violent civil strife such as Niger, Chad,Somalia and the Democratic Republic of the Congo. Mali, currently in the midst of battling a radical Islamic threat, has a rural electrification rate of just 15 percent.[5] Without commercial energy to support economic growth and modernization, the pathway to jobs and the middle class for hundreds of millions of young people will be stymied, sowing growing dissatisfaction.

The emergence of new oil and gas producers in the region presents potential benefits for U.S. national security interests, if this new-found wealth is managed appropriately. Oil and gas resources not only can provide energy and revenues for local use, but also can help stabilize oil and gas prices by diversifying and enhancing available supplies for regional and global markets. Several countries could also potentially become oil suppliers to the U.S., further diversifying the sources of U.S. imported oil.

Economic Interests

The energy trends described above offer trade and investment opportunities for U.S. businesses. In the area of expanding electricity access, there is a large potential market for off-grid and mini-grid decentralized power solutions, especially in rural sub-Saharan Africa where electrification rates are well below the global average. The IEA estimates that most of the capacity deployed in this area will be renewable, clean energy technologies.[6] For cooking facilities, there is also an opportunity to capture a market now satisfied by traditional and dirtier forms of energy with advanced cook stoves based on commercial energy sources. Furthermore, the emergence of new oil and gas producers offers investment opportunities for U.S. firms in exploration, production and related services, and infrastructure development.

The Opportunity for the U.S.

Energy needs to play a more prominent role in U.S. policy toward sub-Saharan Africa. This enhanced role could be achieved by utilizing and leveraging existing programs and institutions to incorporate more sub-Saharan African countries, and expanding financial resources available to target the energy sector. Some specific opportunities for further engagement include:

1. Operationalize a greater sub-Saharan focus within the Department of State’s newly- formed Bureau of Energy Resources, created to address three strategic pillars of energy strategy: energy diplomacy, energy transformation and energy poverty. 
   
   
2. Continue and expand financial support for energy access initiatives in sub-Saharan Africa through the Overseas Private Investment Corporation, the U.S. Treasury, USAID’s Development Credit Authority and the Millennium Challenge Corporation, as well as through multilateral entities.
   
   
3. Promote the strengthening of institutions and governance especially related to the development of hydrocarbon resources, utilizing the Department of State’s Energy Governance and Capacity Initiative and U.S. participation in the Extractive Industries Transparency Initiative.
   
   
4. Support and promote U.S. energy investment, trade and technology and knowledge transfer in the region with a focus on renewable technologies for mini-grid and off-grid solutions, and sustainable oil and gas development, utilizing institutions and programs such as: (a) Global Alliance for Clean Cookstoves; (b) Department of State’s Unconventional Gas Technical Engagement Program; (c) U.S. Trade and Development Agency; (d) U.S. Export-Import Bank; (e) the Department of Commerce’s “Doing Business in Africa” program; and (f) bilateral and regional trade and investment agreements.

Endnotes

[1] World Energy Outlook 2012, International Energy Agency, 532

[2] “Data: sub-Saharan Africa”, World Bank 2010

[3] Fiona Harvey,“Overseas aid to Africa being outweighed by hefty costs of importing oil,” The Guardian, April 1, 2012

[4] Oil and Gas Markets 2011, International Energy Agency, 240

[5] “Scaling Up Renewable Energy Program in Mali”, SREP-Mali Investment Plan, Republic of Mali, Ministry of Energy and Water, September 21, 2011

[6] “Special Excerpt: Energy for All: Financing Access for the Poor”, World Energy Outlook 2011, International Energy Agency, 2011, 26

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Editor's note: As Jordan looks to develop a civilian nuclear energy program, some domestic and international analysts are questioning the feasibility and intentions of its efforts. In an interview with Monocle, John Banks suggests that while Jordan’s efforts are the result of domestic energy shortages, its program will be hard to develop for a number of reasons. Read an excerpt below.

Monocle: Now the generally accepted role of Jordan is to be the Middle Eastern country which doesn’t make everybody nervous. Possibly because they would like just a little bit of attention for a change, possibly because, who knows, they have a sincere desire to provide for their future energy requirements, Jordan is about to commission two nuclear reactors.

Amman is believed to be choosing between tenders from a French Japanese consortium and a Russian competitor. Jordan is almost totally dependent on oil and gas imports and this twelve billion euro project would spare Jordan from relying on the stability of their neighbors, which as recent events have reemphasized, is one of the world’s very least reliable qualities. Well joining us now to tell us more is John Banks, non-resident Fellow of the Energy Security Initiative at The Brookings Institution in Washington DC.

First of all, should we be pleased about this?

John Banks: Well, first thanks for having me. It depends on your perspective. Certainly from the Jordanian perspective there are several major drivers why they are pursuing a civilian nuclear energy program. The first is they are looking at annual electricity demand of about eight percent per year over the next decade or so. They are expected to need to add several thousand megawatts of capacity just to keep up with that electricity demand. And secondly, as your intro made reference to, they have energy security reasons for pursuing civilian nuclear power. They really have a situation where they’re highly dependent, as the intro mentioned, overwhelmingly on imports of energy, more than 90% dependent imports for energy across the economy, but in particular in transport and in power generation. One of their overall strategies is to diversify fuel sources and in particular to limit reliance on imported fossil fuels.

Monocle: The trouble that has been in the past though is that Jordan has had quite a stop-start nuclear program. It has been stopped by the Israelis; it has been stopped by the Americans. Obviously there is some fundamental concern about, not lightly, the safety of this.

Banks: Any country, but particularly a country that is pursuing its first nuclear reactor is going to be faced with a variety of very serious challenges, not the least of which is the need to develop a very robust framework to provide for the safe operation of the facilities as well as the security of the facilities and also to prevent proliferation. These are some of the major challenges that any county is faced with, but particularly for a country pursuing its first reactor. If you are starting from a position where you have no nuclear infrastructure and very little human resources capacity, this is a very big challenge. You need to develop a legal and regulatory framework, put in place the human resources capabilities, and allocate sufficient funding to ensure that this sector is operating according to the highest standards. So there is no question that, I think the Jordanian government recognizes the challenges, the question is are they going to be able to overcome them.

Listen to the full interview » (starts at 17:30)