India Already Has a Problem With Wasting Renewable Energy on the Grid

India ratified the Paris climate agreement this week, officially underscoring its commitment to reduce greenhouse gas emissions. Yet just two years after embarking on an ambitious campaign to scale up renewable energy, India is facing a curious problem: too much solar and wind power in some parts of the country.

In July, for the first time, the southern Indian state of Tamil Nadu was unable to use all the solar power it generated. Later in the month, Jayaram Jayalalitha, the chief minister of Tamil Nadu, wrote a letter to Prime Minister Narendra Modi urging him to speed up the construction of an inter-state green energy corridor that would allow renewable power to be transmitted and used in other states instead of being wasted.

And in August, Tarun Kapoor, India’s joint secretary of the Ministry of New and Renewable Energy, wrote a letter asking electricity regulators to fully utilize solar power following complaints that grid operators were letting renewable energy go to waste.

As developing countries lead the world in renewable energy investment, India’s experience highlights a larger question: Will the grid be a major roadblock for renewable energy development across the developing world?

From India to China to Chile, a significant portion of future renewable energy could go to waste without careful planning.

Solar and wind only accounted for 3.5 percent of the power generated in India in 2015. But if the government achieves its ambitious targets for renewable energy deployment, the amount of solar and wind power on the grid could quadruple by 2022. Yet there are already signs that the grid’s ability to absorb these new power sources could be a major bottleneck for renewable energy growth in India, jeopardizing the country’s energy and climate goals.

Although there is not clear national data, regulatory filings from Tamil Nadu, where the problem is thought to be the most extreme, put the curtailment rate for wind power between 33 percent and 50 percent — an astonishingly high figure.

The problem is, in part, a technical one. Solar and wind power are not as easy to control as traditional fossil fuel plants, so power grids need to become flexible enough to handle last-minute changes in power generation.

Distance is also an issue. In India, six states in the western and southern regions account for 80 percent of all of the country’s currently installed solar capacity, but only 38 percent of power demand. For grid operators used to being able to turn fossil fuel plants on and off at will, these changes can take some getting used to. If new measures are not put into place to accommodate variable renewable energy sources, a situation can arise where the physical grid — or the grid operator — is unable to use solar and wind power when it becomes available.

Other countries have already dealt with this problem with varying degrees of success. Germany and the U.S. have relatively high levels of solar and wind penetration and low curtailment rates, while China has had major issues with curtailment as the share of wind and solar in the energy mix increases.

Indeed, China currently has more wind and solar power capacity than any other country in the world after scaling up very quickly. In the five years between 2010 and 2015, the share of solar and wind power generated in China quadrupled. Yet in 2015, the U.S. still produced more electricity from wind than China, despite having only 58 percent of China’s installed wind capacity. A large reason for this discrepancy is that much of China’s solar and wind power is wasted: 21 percent of wind power was curtailed in the first half of 2016 (with Gansu province reaching a 47 percent curtailment rate), and solar curtailment reached 11 percent in the first three quarters of 2015.

Although China has been able to build out renewable energy capacity quickly over the past decade, it has taken much longer to develop the transmission infrastructure and make the institutional changes required to utilize all of this new power.

How can India learn from China’s mistakes and rapidly scale up renewables without waste?

Luckily, the challenge has not caught Indian policymakers by surprise. There are already a number of initiatives underway to help integrate renewables into the grid. Perhaps most important is that, unlike China, India already has a wholesale power market, which can provide much-needed flexibility for utilities to buy and sell power at short notice.

There is also the aforementioned green energy corridor, a series of transmission lines that will connect states with excess renewable energy to areas where there is demand. And similar to China, solar and wind already have “must run” status, meaning that any power they generate should always be accepted by the grid.

Yet even these steps may not be enough. A recent survey found that 31 percent of senior corporate leaders in Indian solar companies think that grid integration will be the biggest challenge for expanding solar in India going forward.

The first priority for India when addressing this issue is to finish the green energy corridor and other new transmission lines so that renewable power can be transmitted where it is needed. There are significant power surpluses in some states and power deficits in others.

For instance, Uttar Pradesh has a peak power deficit of 9.7 percent (meaning 9.7 percent of demand at peak times cannot be met with the power available in the state), whereas the bordering state of Madhya Pradesh has a peak power surplus of 8.3 percent. Yet the power connection between the two states was at full capacity 73 percent of the time in May 2016, meaning some surplus power in Madhya Pradesh may not have made it to Uttar Pradesh. Nationally, 10 percent of the power supply available on the short-term markets last year could not be used because of transmission constraints.

New investment in inter-state power lines will help balance out such disparities. It is particularly important for India to attract private investment in these projects. The green energy corridor will cost an astounding USD $3.4 billion, and is funded in part by government funds and partially by a $1 billion loan from the Asian Development Bank and 1 billion loan from GiZ. But the public sector can only fund so many multibillion-dollar projects, and many state utilities are already in poor financial conditions.

Private capital is projected to be required for 47 percent of infrastructure investment in India between 2012 and 2017. India’s planning commission has created a framework for public-private partnerships for transmission investment, but land acquisition and permitting are still major roadblocks for private developers hoping to complete a project on schedule. Reducing the time and cost of land acquisition will be essential to making infrastructure projects attractive to developers and unlocking the private capital needed to finance transmission lines.

Second, focusing on deploying distributed energy technologies like rooftop solar can help increase the amount of renewable energy in use where new transmission lines are infeasible or too expensive.

India hopes to get 40 percent of its solar capacity from rooftop solar by 2022, but the market has been slow to take off despite a 30 percent capital subsidy from the government. The barriers to rooftop solar deployment are often more institutional than technical. In China, slow subsidy disbursement and a lack of financing have caused rooftop solar deployment to fall short of government targets. In India, a recent survey found that 93 percent of senior corporate leaders in the Indian solar sector did not think the country would even reach half of its rooftop solar target by 2022, citing ineffective net metering policy, unavailable and expensive financing, and consumer awareness as top issues.

There are a number of potential solutions: Training for distribution utilities unaccustomed to having customers generate their own electricity; streamlining the application and approval process; creating certifications to ensure installer quality; and even allowing rooftop solar systems to serve as backup power when the grid goes down. Quickly implementing such solutions can allow renewables to grow without worsening curtailment.

Energy storage can also play an important role in reducing curtailment. The cost of storage is still a major barrier to mass adoption, but prices are dropping quickly.

Moreover, Germany and Texas have achieved low curtailment rates with minimal energy storage and high renewable energy penetrations through improved grid planning and changes to the power market structure. Still, India is planning on installing 10 gigawatts of pumped hydro energy storage across the country to accommodate increased renewable energy penetration (China is taking similar measures to reduce curtailment). As the price of energy storage drops, it will become an increasingly compelling complement to variable renewable energy.

Finally, India can look to other countries to find grid planning and operational solutions to help manage curtailment as renewable power scales up. One such change, highlighted in a recent Paulson Institute report on curtailment, is to create financial incentives against curtailing renewables.

Currently, Indian solar and wind generators are not compensated for curtailment, and compensation should not be necessary because renewables have “must run” status. However, financial incentives can help reinforce such regulations when mandates alone are insufficient. China has had a similar experience with “must run” mandates: multiple policies have stated that solar and wind should always receive priority on the grid, but curtailment continues to be an issue because there are few penalties for ignoring this regulation.

recent regulation released by China’s National Development and Reform Commission requires that coal plant owners pay wind or solar plant owners whose energy is curtailed, creating a stronger incentive for grid operators to fully utilize renewables. An even simpler solution would be to compensate solar and wind projects for any curtailed energy at a fixed rate. This not only penalizes grid operators that choose to curtail renewables, but also provides more certainty for power producers when trying to forecast revenue.

Even smaller changes to how the grid is operated can make a difference. In Texas, grid operator ERCOT shifted from 15-minute dispatch intervals on the intra-day market to 5-minute intervals, allowing for more granular planning around variable wind and solar power plants. (India currently uses 15-minute dispatch intervals.) ERCOT also shifted from targeting 0 percent curtailment to a maximum acceptable curtailment rate of 3 percent of annual renewable energy production — a more cost-effective solution than trying to utilize every unit of electricity generated at peak times.

Such institutional changes can provide flexibility to the grid without the high risk and cost of major new transmission and storage projects.

India has already set a moonshot goal for renewable energy deployment that would have been unthinkable just a few years ago. Indeed, in the five years between Copenhagen and Paris, India went from being a hindrance to an enthusiastic participant to in the United Nation’s global climate negotiations.

Yet a successful energy transition will require a broader change in the infrastructure and institutions that support renewables — not just targets themselves.

View original post:

Massachusetts Goes All-In on Energy Storage

energy storage

The next wave of clean energy policy making will be more focused on energy storage, as evidenced by the release this week of the long-awaited Massachusetts energy storage report, titled “State of Charge.”  The study was co-funded by the Massachusetts Department of Energy Resources (DOER) and Massachusetts Clean Energy Center (MassCEC), and it represents a major new policy direction for the state on how to capture the economic and environmental benefits of emerging energy storage technologies.

In impressive fashion, the 200-page report, supported by detailed economic analysis, lays out how Massachusetts can use a smart combination of procurement, financial incentives, market economics, and economic development strategies to expand storage deployment and help grow the storage industry. It is a road map showing how energy storage can save money, increase penetration of renewable power and address climate change in Massachusetts — and, by extension, in other states.

The report proposes that the state invest millions in storage deployment incentives and market development, with the goal of incentivizing 600 MW of new advanced storage capacity by 2025, resulting in an anticipated $800 million in system benefits to ratepayers. These policy actions would be a big step in moving the state toward the report’s modeled optimal deployment level of 1.766 GW of storage, and may be augmented by the new Massachusetts energy diversity law that empowers DOER to set an energy storage procurement mandate for the state’s utilities.

DOER is supposed to decide by the end of this year whether to establish an energy storage procurement mandate, and if so, for how much additional storage. State utilities would then have until 2020 to meet the mandated procurement target. If established, this would make Massachusetts the third state to create a storage mandate, and the first in the Northeast.

While the study does not recommend an energy storage mandate, it does provide a sophisticated cost/benefit analysis model showing the economic benefits of procuring 1.766 GW of energy storage. According to the study that procurement would cost between $970 million and $1.35 billion, but would yield $2.3 billion in system benefits to ratepayers, plus $1.1 billion in market revenue to the resource owners; and $250 million in regional system benefits to the other New England states due to lower wholesale market prices across ISO New England (ISO-NE). Climate benefits include a carbon emissions reduction of more than 1 million metric tons of carbon dioxide over 10 years — equivalent to taking 223,000 cars off the road.

The study begins by laying out the business case for storage. The state’s electric system is inefficient, it says, with storage capacity accounting for less than 1 percent of the state’s daily electricity consumption. The grid must be balanced by the nearly-instantaneous ramping up and down of fossil fuel generators, requiring the building and maintenance of numerous gas “peaker” plants that only run 2 percent to 7 percent of the time. That means these plants sit idle more than 90 percent of the time.

The report also points to inefficiencies in the grid infrastructure and resulting high costs to ratepayers due to “highly variable” electricity prices. The report claims that from 2013-2015, the top 1 percent most expensive hours for electricity consumption accounted for more than 8 percent ($680 million) of Massachusetts ratepayers’ annual electricity costs, and that the top 10 percent of hours during those years, on average, “accounted for 40 percent of annual electricity spend, over $3 billion.”

The report suggests that energy storage is “the only technology that can use energy generated during low cost off peak periods to serve load during expensive peak periods, thereby improving overall utilization and economics of the electric grid.”

So, if storage is so beneficial, why isn’t there more of it already? The Massachusetts study identifies the single biggest barrier to energy storage deployment:

“While the system benefits alone justify an investment in storage from a ratepayer perspective, the revenue mechanisms that would encourage investment from a private storage developer are insufficient. Without a means to be compensated for the value the storage resource provides to the system, private investors will simply not invest in building storage projects in Massachusetts…. The biggest challenge to achieving more storage deployment in Massachusetts is that there is a lack of clear market mechanisms to transfer some portion of the system benefits… to the storage project developer.”

This is the main problem addressed by the study’s policy and program recommendations, which fall into two broad categories: (1) recommendations to expand deployment of advanced energy storage in the state, and (2) recommendations to grow the energy storage industry.

The deployment-oriented recommendations include grant and rebate programs, such as doubling funding for demonstration projects from the previously-announced $10 million to $20 million; offering $20 million in rebates for customer-sited storage out of state ACP funds; dedicating $150,000 to support commercial/industrial feasibility studies; awarding the remaining $14.2 million in DOER’s Community Clean Energy Resiliency Initiative budget; and allocating $4.5 million in demonstration project grants for utilities and market actors to demonstrate peak demand management.

The study also recommends adding storage as an eligible technology within the existing Green Communities Grant, Alternative Portfolio Standard, and Next Generation Solar Incentive Programs, and allowing storage to be included in all future long-term clean energy procurements.

There are also recommendations that the state clarify the regulatory treatment of utility storage, including the treatment of storage in grid modernization plans; adopt storage safety and performance standards; clarify interconnection requirements; facilitate sharing of electricity customer load data and use cases by facility type; and create an advanced storage working group at ISO-NE to remove regulatory and market barriers that keep storage from participating in regional wholesale energy markets.

Recommendations to grow the energy storage industry in Massachusetts include creating an energy storage cluster and expanding the MassCEC investment programs to support energy storage companies; expanding MassCEC’s workforce training programs; and engaging the state’s universities to support energy storage startups in Massachusetts and invest in research and development and testing facilities to anchor an energy storage cluster.

The bottom line is that Massachusetts — assuming programs and policy making follow this study’s recommendations — is about to throw nearly every tool in its considerable policy toolbox at the problem of how to make energy storage go, and go big, in the Commonwealth.

The study is a landmark product, not just for Massachusetts, but for all states; and it serves as an example of what can and should be done to move our electricity grids out of the 19th century and begin leveraging real and significant support for technologies that will save money, improve reliability and resiliency, reduce greenhouse gas emissions, and support the transition to renewables and distributed generation.

But no report is perfect; so what’s missing from this one? Well, for one thing, there is no mention of how to make the benefits of energy storage accessible to low- and moderate-income communities, which need energy cost savings and resiliency the most; nor is there any discussion of storage in multifamily affordable housing, where it can provide both resilient power and economic benefits.

Given the Baker-Polito Administration’s heralded $15 million Affordable Access to Clean and Efficient Energy Initiative — a cross-cutting initiative designed to focus the state’s multiple energy and housing agencies on expanding clean energy opportunities for low- and moderate-income residents — this omission may be remedied during implementation.

And there is still the open question of whether the state will implement measures to reach the modeled, economically optimal, storage deployment level of 1.766 GW. Between the report’s policy recommendations and new enabling legislation, the state may have the new tools to get there. How far it will actually go, still remains to be seen.

On the whole, though, the report is an impressive piece of work — the kind of thorough analysis other states should look to when teeing up energy storage policy development. And if even half the report’s recommendations are quickly implemented, it will position Massachusetts as a clear leader in the development of meaningful energy storage policy, programs, and deployment. It’s now up to other states to follow Massachusetts’ example.

Clean Energy Group and the Clean Energy States Alliance (CESA) are working to support MA DOER and MassCEC in their energy storage and resilient power initiatives, by providing technical assistance directly to municipal awardees of DOER’s Community Clean Energy Resilience Initiative, and by providing policy and program development support to both agencies, through the Energy Storage Technology Advancement Partnership (ESTAP) and Resilient Power Project. ESTAP is supported by US DOE-OE through a contract with Sandia National Laboratories, while the Resilient Power Project receives foundation support.

Lead image credit: AES Energy Storage

View Original Post on Renewable Energy World:

EIA: Natural gas to generate more than one-third of US power this year


Dive Brief:

  • Natural gas will generate 34% of the United States’ power this year, with production peaking this month and next as the families fire up their air conditioners to cope with hot summer weather.
  • Total gas generation will be 4% higher this year compared with 2015, according to new analysis from the U.S. Energy Information Administration.
  • Coal’s share of the power mix is expected to be 30%, with nuclear and renewables following at 19% and 15%, respectively.

Dive Insight:

Coal’s decline and the rise of natural gas generation is accelerating. EIA’s latest predictions regarding the United States generation mix show a significant shift from the estimates released less than a year ago.

“Natural gas-fired electricity generation in the United States is expected to reach a record level this year,” the agency said in a note digging into data form its most recent Short-Term Energy Outlook. “Monthly natural gas-fired generation is expected to reach record highs in July and August, when weather-related demand for air conditioning increases electricity demand.

Gas will generate 34%, compared to coal’s estimated 30%, edging out EIA’s prediction in December when the agency estimated gas’ share of generation would be 31.6%, with the coal generation set at 34.1%.

Gas was second to coal for years and first generated more energy in April of last year. But since then, its share has been rising while environmental regulations and cheap fuelstock have pressured coal plants offline.

However, renewable growth will soon begin to cut into gas’ dominance, EIA said.

“Notably, the natural gas share of power generation is expected to decline for several years after 2016 as it competes with renewables and as natural gas prices rise,” the agency said. In its Annual Energy Outlook 2016 Reference case,  EIA predicts gas generation share falls until about 2020, then climbs steadily over the next two decades.

“Natural gas is projected to regain the largest share in the electricity mix by 2022 and maintain that position through 2040,” EIA said.

View Original Post on Utility Drive: