Energy Finance Report

Six Questions to Consider about Microgrids

Posted by Jim Wrathall on 7/14/15 2:30 PM

microgrid ThinkstockPhotos-156606910


What is a microgrid?

The traditional electricity distribution model can be viewed as a “macrogrid,” using a large centrally located power station to provide electricity over an extensive service territory. This model was designed during the early days of electrification with the objective of providing affordable and reliable power to as many customers as possible. However, with technological advancements, a localized microgrid may provide the multiple benefits of grid resiliency and cleaner, more efficient energy production and distribution. Regarding resiliency, the microgrid may be able to disconnect or “island” from the macrogrid, minimizing and isolating blackout incidents and providing for power redundancy. Concerning energy efficiency, the microgrid uses local sources of energy to serve local loads, reducing energy loss in transmission and distribution. Additionally, this smaller grid can more easily deploy distributed energy resources (DER) such as solar energy and combined heat and power (CHP) to meet grid demand.

Why the push towards microgrids?

As stated above, microgrids provide the dual benefits of energy efficiency and resiliency. Picture Superstorm Sandy in Manhattan, if downtown had the capability to island and maintain power notwithstanding the downed Con Edison station? Or, perhaps, picture the upper east side of Manhattan being able to provide some power to the seven million people left without electricity? Even the nation’s capitol is vulnerable, as demonstrated when a PEPCO transmission line recently took out power in downtown D.C., with power disruption affecting federal buildings including the White House Complex. Not to mention, electricity can be saved by diminishing losses from long transmission.

Ok great! Why not build microgrids everywhere?

Currently, developers face uncertainties as there is not a clear policy or regulatory path in place, thus affecting the potential to obtain private financing. Previously, we lacked the technological capability to deploy a variety of distributed generation (picture roof-top solar, a traditional combined heat and power station, and a small wind turbine working together in different locations) through a set of advanced, real-time controls to manage energy demand across the entire microgrid. While the idea of a clean-tech microgrid is relatively new, the concept of a microgrid is not so new. University campuses, military bases and some industrial parks have been operating them for years, maybe even decades, but all such grids are on a solitary campus with one stand-alone energy customer. What is new is the desire to place microgrids throughout a utility grid system servicing commercial customers, perhaps in competition with the utility. The potentially competitive relationship with the utility may be why we haven’t seen microgrids popping up everywhere, unless they are utility-sponsored.

What is the utility’s stake in microgrid adoption?

Where a third-party, non-utility provides electric generation and distribution to retail customers, the utility may have a lot at stake. The traditional model always has been the use of a macrogrid, in which a solitary utility provides both the generation and distribution of electricity for a specified geographic area, their “service territory.” Simplifying the regulatory terrain, utilities are heavily regulated in exchange for their exclusivity and must set rates through a proceeding before the state’s public service commission (PSC). This is why electricity bills typically remain constant because change can only occur in a rate making proceeding. Depending upon how the state set up its relationship with the utility (during the late 1800s or through some subsequent restructuring), the utility may own its right to exclusivity, making it very difficult for a state to change its laws.

Some states and their utilities have opened the market to multiple electricity generating entities and, for example, enabled solar providers such as SolarCity through third party roof-top leasing. However, utilities have invested a great deal of capital in fixed wire distribution systems that physically connect your homes or businesses to electricity. Microgrids would directly compete with such fixed wire distribution; therefore, utility resistance may be expected. Depending upon the jurisdiction, fixed wire distribution may be the exclusive franchise of the utility. However, some states, like New York with its Reforming the Energy Vision (REV) docket, are seeking to modify the utility relationship, showcasing the vast differences in utility precedent by jurisdiction.

Are there other obstacles to microgrid adoption?

Lawmakers and public service commissions may need to realign their energy laws and regulations to enable the clean-tech microgrid. For example, to make a private microgrid financeable, the developers will need to know approximately how many customers (ratepayers) they can lock into their grid. Many states have competition laws that allow customers to choose their electric generation supplier. This approach may disadvantage a financed microgrid, as customers may be able to switch providers. Also, it is unclear what level of regulation microgrids will experience. Are they utilities? The common answer is most likely not, but the question remains: will there be any requirements in place to prevent rate spiking? Another unknown, will the microgrid as a whole be able to net-meter to the macrogrid? What will the interconnection procedures look like? The list of uncertainties needs to be addressed to provide developers and financers with better clarity.

With all of these challenges, what is the future for microgrids?

There is accelerating momentum behind the push to deploy microgrids. SolarCity already is offering a microgrid service to collaborate with municipalities and universities. With more severe and unpredictable storms and increased vulnerability to cyber-attack, microgrids are becoming the next horizon for our energy future. Utility and policy concerns are surmountable as demonstrated by REV and the market restructurings that enabled competitive generation. To gain a foothold, the microgrid revolution will take a tailored approach to local issues, and will be led by some pioneering developers, and, perhaps, a handful of forward-thinking utilities that are ready to capitalize on a new opportunity.

Topics: Utilities, Energy Policy, Structured Transactions & Tax, Energy Storage, Energy Efficiency, Microgrid, Energy Finance, Distributed Energy, Energy Management, Solar Energy, Renewable Energy, Public/Private Partnership, Wind

Managing the Risks of Renewable Energy Projects in Developing Countries

Posted by Jeffrey Karp on 5/18/15 10:46 AM

Risk Reward-180977510

Co-author Morgan M. Gerard

Driven by rapid expansion in developing countries, renewables are becoming a significant source of the world’s power. According to the United Nations Environmental Programme’s (UNEP) 9th “Global Trends in Renewable Energy Investment 2015,” investment in developing countries was up 36% in 2014, totaling $131.3 billion. China ($83.3 billion), Brazil ($7.6 billion), India ($7.4 billion) and South Africa ($5.5 billion) were all in the top 10 of investing countries while more than $1 billion was invested in Indonesia, Chile, Mexico, Kenya and Turkey. As renewables continue to expand into developing nations, it is incumbent upon developers to understand the risk features of some of these environments.

Best Practices for Renewable Development in Developing Countries

Geo-Political Risk

Renewable developers need to be mindful of the politics when they locate their projects. Unstable governments may expropriate projects, change laws, or even change regimes due to war or internal uprisings during the life of a long-term Power Purchase Agreement (PPA). Political risk insurance may be available, but coverage plans may be costly or incomplete. Partnering with an international organization like the World Bank or International Finance Corporation (IFC) may ease some of these worries since even unstable regimes look to these international organizations for financial stability and support in the global markets in the event of government default.

Legal Risk

Developing countries may lack the general rule of law that provides for predictability and transparency of business transactions. In some countries, bribing government officials to obtain required permits may be the norm. Additionally, local courts may not offer developers relief for their claims as judicial officers may also request bribes or be closely aligned with the government decision-makers. U.S. companies need to be mindful to steer clear of engaging with such officials to avoid allegations of violating the Foreign Corrupt Practices Act (FCPA). Corruption risk may extend beyond just bribery; there are reported instances of local counsel threatening projects and extorting foreign developers to pay increased legal fees.

Currency Risk

A developing country’s local currency may fluctuate greatly, and if their currency inflates the project’s revenue stream loses its value in international markets. To protect against currency risk, developers should either negotiate their PPAs to receive payment in a predictable currency or hedge this risk. Although, financial institutions offer exchange rate hedging instruments, such as currency swaps or currency futures options, the upkeep on these agreements may be expensive if the developer negotiates a good position on a volatile currency.

Physical Risk

In negotiating the terms of PPAs and debt financing agreements, project sponsors should consider the potential impact on their projects of adverse weather/climate conditions or other natural disasters. Thus, developers should be mindful that, if for example completion or ongoing operation of their projects could be delayed or interrupted by flooding or other impacts from a major storm, they may need to invoke a force majeure clause due to an unavoidable event or occurrence.

Counterparty Risk

The offtaker in many of these countries may be the government-sponsored utility. If the utility refuses to accept the project’s renewable power or fails to make payments, developers could find themselves seeking relief in a government-sponsored court. Developers should ensure that their PPA agreements provide for arbitration in a neutral venue to help alleviate this concern. Additionally, involvement by the World Bank or IFC could help developers navigate such situations.

If you have any questions regarding assessing risk or developing risk management strategies for renewable energy projects in developing countries, please contact our Energy Finance practice.


Topics: Energy Policy, Energy Finance, Distributed Energy, Renewable Energy, Public/Private Partnership

Virginia Solar Projects Moving Forward: A New Growth State for Clean Energy?

Posted by Jim Wrathall on 2/25/15 6:28 AM

Co-author Eli Hinckley

Governor McAuliffe Issues Public-Private Partnership Request

While Virginia historically has not offered robust clean energy incentives and programs, Governor Terry McAuliffe appears determined to reverse the trend. On January 16, 2015, the Governor’s office released a request for information (RFI) seeking data on potential public-private partnerships (P3s) for solar energy development in and around state owned property. The RFI is directed towards experienced individuals, firms, teams, and organizations that can help in development, financing, design, or building of P3 solar projects above 100kW. Responses are due by March 13, 2015.

magnifyglassDominion Power Proposed Solar Facility

Four days after this announcement, Dominion Virginia Power filed a request with the Virginia State Corporation Committee (SCC) to build what reportedly would be the largest solar facility in the Commonwealth. Dominion proposes to build the 20 MW facility near its Remington Power Station in Fauquier County on a 125-acre plot owned by the company. Dominion’s experience in solar energy includes 334 megawatts of solar generating capacity in six states outside of Virginia. The new solar array will be capable of powering around 5,000 homes at peak productivity, estimated by Governor McAuliffe to nearly double Virginia’s production of solar energy. Dominion Virginia Power is currently evaluating three fixed-price bids and will make a decision on contracting by April 1. The project targeted to be in service by October 2016.

Thoughts for Solar Developers and Investors

The recent actions by Dominion Power and Governor McAuliffe support the Governor’s statement that “Virginia is serious about enhancing its solar energy industry.” Last year the Virginia Office of Transportation Public Private Partnerships (OTP3) issued a project screening report that gave guidelines of suitability for public-private partnerships and identified hindrances to rapid solar energy uptake in Virginia. Among the challenges to development is Virginia’s voluntary Renewable Portfolio Standard (RPS), as opposed to the mandatory structure successfully adopted by twenty-nine states. Another obstacle noted is the lack of state tax incentives for private developers, causing project sponsors to rely solely on national tax incentives such as the Investment Tax Credit (ITCs), which will only apply to systems in service by the end of 2016 unless extended by Congress.

While the current RFI focuses on government support for leveraging state-owned sites, the P3 approach will bring private development and investment into the mix. The Governor’s stated objective is that with continued government support the market will take note of Virginia’s major untapped solar potential. The state has become haven for large commercial and industrial facilities, including data centers and manufacturing, which require high loads of power and may act as reliable off-takers for renewable generation. However, as was the case with Ikea, companies may choose to own their systems and possibly monetize the Renewable Energy Credits (RECs) in the nearby Pennsylvania market. Prospects for increased solar development and investment would be heightened by a mandatory and stable Virginia REC market. But this would require action by the Virginia General Assembly, which thus far has acted more as an obstacle for renewable advancement. The big question for the next couple of years is whether the substantial economic benefits called out by these kinds of projects will be able to overcome legislative inertia and opposition.

Investors and developers should stay tuned. As in certain other states in the South and Southeast, including Louisiana, Georgia and South Carolina, solar looks to be on the upswing in Virginia. Policy changes and projects such as these may unlock major new opportunities.

Special thanks to Morgan Gerard and Emma Spath who assisted in the preparation of this post.

Topics: Energy Policy, Solar Energy, Public/Private Partnership

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