The Tides Are Turning for Offshore Wind in the US

Author: Valerie Stori, Clean Energy Group | Project: Offshore Wind Accelerator Project

blogphoto-Offshore-Wind-FarmOffshore wind excitement is growing in the Northeast with the recent arrival of foundations for Deepwater Wind’s Block Island offshore wind farm. This ground-breaking, demonstration-scale project’s impacts are reverberating all the way to the Gulf Coast, where the specialized turbine foundations were constructed by Gulf Island Fabrication. Closer to home in Warren, RI, Blount Boats is building the nation’s first offshore wind farm crew vessel. And out at Quonset Business Park, Specialty Diving Services has been busy manufacturing ladders, platforms, and railings for the steel foundations. Overall, Deepwater Wind estimates that it will bring 330 jobs to Rhode Island.

Other states are paying close attention to this project, keeping a close eye on costs and public reaction. International developers with expertise in offshore wind construction are also paying attention. Danish developer DONG Energy has purchased commercial leasing rights from RES Americas, Inc. for a large wind development area off the coast of Massachusetts, indicating that the US market has the potential for significant development. Senators Susan Collins of Maine and Tom Carper of Delaware have introduced a bipartisan bill calling for a 30% investment tax credit for the first 3000 MW of offshore wind.

Despite the tremendous potential of offshore wind, its high cost is a major barrier to development. The overnight capital costs of OSW are estimated to run over $5000/kW, compared to land-based wind projects which average $2000/kW. Deepwater Wind’s initial power purchase contract with National Grid for power from its 30 MW Block Island wind project is priced at $244/MWh with an annual 3.5% escalation.

Getting to scale is a key step to reducing costs. The European experience has demonstrated that a market of sufficient scale and duration can reduce costs.  Europe has installed over 8 GW and costs have decreased dramatically. A recent report by BVG Associates predicts that offshore wind projects in the UK will be cost-competitive with new natural gas plants by 2020.  The 3000 MW target in the Carper/Collins bill is large enough to attract international developers with offshore wind expertise to construct manufacturing plants and invest in the US supply chain. At this scale, offshore wind can attract investors, support a domestic supply chain, and drive economic development.

If offshore wind can be developed at a significant scale along the Northeast and Mid-Atlantic coast, it would provide a range of benefits to the region, including improved grid reliability, reduced transmission costs, less expensive peak load generation, and economic development. Furthermore, offshore wind is the largest renewable resource in the region that can help meet RPS mandates, comply with the EPA Clean Power Plan, and achieve individual state renewable energy targets.

New York, for example, has just released its state energy plan with an ambitious goal of 50% renewable energy by 2050; offshore wind is the only large-scale renewable resource that can meet New York’s energy demands. The state energy plan recognizes offshore wind’s potential and outlines steps the state can take to support offshore development, including collaboration with other states. The OSW technical potential in the region and off New York’s coast is significant—11.6 GW, of which 4.7 GW are estimated to be economically recoverable.  Offshore wind could supply 12% of the state’s electric generation while displacing 12.3 million metric tons of carbon dioxide.

New York City has pledged to reduce its GHG emissions by 80% by 2050. Through a recently released request for information, the city is seeking to identify new sources of large-scale renewable energy that can reduce peak demand, spur economic development, and reduce the city’s emissions. Offshore wind could be a key part of the solution.

There is reason to be hopeful about a vibrant offshore wind industry in the US. First and foremost, by this time next year, the first turbines will be spinning off our Atlantic coast. Several commercial wind energy areas have been leased to a variety of developers, including an area off of Long Island with the potential to generate 1GW of capacity. New York, as one of the biggest energy consumers in the country—the city’s purchasing power alone is significant at nearly $650 million per year—can help set the stage for developing a domestic wind industry.

The Block Island five-turbine, 30 MW project is small, but it is a big step forward symbolically.  With foundations in the water and Rhode Islanders at work constructing the project, the US has advanced towards capturing its offshore wind energy potential. Both Rhode Island and Deepwater Wind should be applauded for their leadership, foresight, and planning. Other states should follow Rhode Island’s lead.


This blog post was also published on Renewable Energy World.

Utilities Seek to Integrate Distributed Storage

Author: Todd Olinsky-Paul, Clean Energy Group | Project: Resilient Power Project

blogphoto-Utilities-Seek-to-Integrate-Distributed-Storage-Blog-ImageFor the past year or two, there have been many stories in the press about how utilities view distributed generation and storage as a threat, rather than an opportunity. Now, there is evidence that this is starting to change.

According to a new survey of electrical utilities by Black & Veatch, over 74 percent of utilities are looking to incorporate distributed behind-the-meter resources, such as solar PV and storage, into their business model. This is because they see distributed generation as a growing threat to their current business model, but also see that solar+storage is a key technology for operational demand response. The utilities surveyed stated that renewables combined with battery storage is the demand response technology that will have the greatest impact on their business going forward.

A current example is provided by San Diego Gas & Electric (SDG&E), which has proposed a pilot program to incentivize customers in specific high-demand areas to install behind-the-meter energy storage systems.  SDG&E proposes a tiered system of cash incentives and/or reduced rates that could, when combined with the state’s SGIP incentives, render the storage free to customers. The payoff for SDG&E is that it will be able to draw on these aggregated behind-the-meter batteries during peak usage periods to reduce demand, thereby deferring expensive distribution system upgrades. The utility would also benefit from avoided purchases of the most expensive electricity to meet the highest demand peaks, and from using the aggregated storage to provide ancillary balancing services to the grid. The utility believes this pilot program could represent a new business model for utilities to incorporate and benefit from customer- and third-party-owned distributed energy resources.

SDG&E officials say there are three keys to the success of the pilot. First, incentives must be substantial enough to attract customers to the program. Second, the utility needs to see an adequate return from its demand management and ancillary services provision. And third, SDG&E must be able to sign mutually beneficial contracts with third parties like SolarCity and Tesla, which will provide the batteries to customers at no up-front cost.

The interesting thing about this proposed pilot program is that SDG&E’s customers, not the utility, would own the storage assets. A contract would define when the utility could use the storage systems, and customers would be able to choose what level of control to give the utility.  Those customers giving the utility more control would receive higher incentives, those ceding less control would receive lower incentives.

That’s a significant difference from utility-owned storage pilots, because it implies that during non-peak times, customers could use their battery systems any way they chose… to lower demand charges, for example, or to reduce the overall amount of electricity they purchase by relying more heavily on on-site solar than they would be able to do without storage. Presumably, customers could also configure their systems to island during a grid outage, providing them with resilient power to support critical loads.

As important as it is that utilities in deregulated markets be allowed to own storage when doing so will benefit ratepayers – as recognized in the NY REV proceedings – it is equally important that utilities begin to integrate customer- and third party-owned distributed storage service provision into their business models, so that storage owners can begin to be properly compensated for the benefits the technology can provide. The SDG&E pilot would demonstrate one way to do it.


This blog post was also published on Renewable Energy World.

Energy Storage and the Clean Power Plan

Author: Seth Mullendore, Clean Energy Group | Projects: Resilient Power Project, Energy Storage and Climate

blogphoto-bigstock-Hamburg-Coal-Power-Plant-Moo-85268189The Environmental Protection Agency (EPA) released the final version of its monumental Clean Power Plan last week – all 1,560 pages of it. I skimmed through the document to find out what it might have to say on the subject of energy storage. Turns out, not a lot.

The plan makes several references to the fact that the U.S. electric power system has limited capacity for electricity storage. However, unlike solar, wind and natural gas, storage is not listed among the measures comprising EPA’s Best System of Emission Reduction (BSER). EPA determines BSER by looking at existing emission reduction mechanisms and technologies and how effective they are in reducing air pollution. In the Clean Power Plan, BSER measures are used to calculate achievable emission reduction targets for each state. As for storage, EPA notes that energy storage can help enable emission reductions by making the power system more efficient and facilitating renewables integration, but asserts that that storage on its own cannot necessarily reduce power plant emissions.

The following three excerpts are the only significant references to energy storage I came across throughout this massive document:

Page 767 Storage can be helpful but is not essential for the feasibility of RE deployment because there are many sources of flexibility on the grid. DOE’s Wind Vision and many other studies have found an array of integration options (e.g., large balancing areas, geographically dispersed RE, weather forecasting used in system operations, sub-hourly energy markets, access to neighboring markets) for RE beyond storage. Storage is a system resource, as its value for renewables is a small share of its total value.

Page 1240 (5) Energy storage.

Energy storage may not be directly recognized as an eligible measure that can be used to adjust a CO2 emission rate, because storage does not directly substitute for electric generation from the grid or avoid electricity use from the grid. The electric generation that is input to an energy storage unit may be used to adjust a CO2 emission rate, but the output from the energy storage unit may not. However, energy storage can be used as an enabling measure that facilitates greater use of RE, which can be used to adjust a CO2 emission rate. For example, utility scale energy storage may be used to facilitate greater grid penetration of RE generating capacity and can also be used to store RE generation that may have otherwise been shed in times of excess generating capacity. Likewise, on-site energy storage at an electricity end-user can enable greater use of RE to meet on-site electricity demand.

The EPA received multiple comments regarding the overall merits of energy storage. Consistent with the discussion above, the majority of commenters observed that storage technology enables greater grid penetration of RE and supports more efficient and effective operations of both RE and fossil-fuel plants. Commenters further noted that energy storage can provide RE to the grid when it is most needed, while simultaneously taking pressure off fossil-fuel plants to respond to sudden shifts in demand. Despite broad acknowledgment of the benefits of storage, public comments underscore its indirect and supporting role in providing zero-emission MWh to the grid (consistent with the EPA’s decision to exclude energy storage as an eligible measure that can be used to adjust a CO2 emission rate).

(6) Transmission and distribution (T&D) measures.

Electricity T&D measures that improve the efficiency of the T&D system and/or reduce electricity use may be used to adjust a CO2 emission rate. This includes T&D measures that reduce losses of electricity during delivery from a generator to an end-user (sometimes referred to as “line losses”) and T&D measures that reduce electricity use at the end-user, such as conservation voltage reduction (CVR). The EPA received many comments in support of advanced energy technologies, including energy storage and transmission and distribution upgrades, and including these technologies in the suite of potential measures that states could consider for emission rate adjustments in their state plans. Comments pointed out that in addition to helping achieve emission standards, T&D efficiency improvements make the grid more robust and flexible, as well as delivering environmental benefits. In many parts of the country, grid operators, transmission planners, transmission owners and regulators are already taking steps to expand and modernize T&D networks. Commenters suggested that the EPA clarify the eligibility and criteria under which such measures would be permitted in a state plan.

To be eligible, T&D measures must be installed after 2012. This general eligibility requirement is discussed above in section VIII.K.1.a. The MWh of avoided losses or reduction in end-use that result from T&D measures must be appropriately quantified and verified, as discussed in section VIII.K.3.

Page 1379 Implementation of other measures not included in the BSER calculation or compliance modeling, such as nuclear uprates, transmission system improvements, use of energy storage technologies or retrofit CCS, could also mitigate gas price and/or electricity price impacts.

The takeaway seems to be that, while many commenters and at least someone at EPA recognizes the valuable role that energy storage can play in the transition to a less carbon-intensive electric power system, EPA considers the impact of energy storage as too indirect to be included in BSER reduction targets. That doesn’t mean states can’t and shouldn’t consider storage in their emission reduction planning. In fact, a number of states have already incorporated energy storage into current and proposed grid modernization plans.

The California Public Utilities Commission stated it well in their 2013 Assigned Commissioner’s Ruling, which set the stage for California’s 1.3 gigawatt energy storage mandate:

Page 2 Energy storage has the potential to transform how the California electric system is conceived, designed, and operated. In so doing, energy storage has the potential to offer services needed as California seeks to maximize the value of its generation and transmission investments: optimizing the grid to avoid or defer investments in new fossil fuel-powered plants, integrating renewable power, and minimizing greenhouse gas emissions.



This blog post was also published in Renewable Energy World.

Energy Storage, Electricity Markets, and Economics

Author: Seth Mullendore, Clean Energy Group | Project: Resilient Power Project

blogphoto-Energy-Storage-and-Electricity-MarketsA lot of people are talking about energy storage these days, which is hardly surprising considering energy storage has often been idealized of as a kind of Holy Grail for the energy industry. It is widely acknowledged that storage can provide an array of beneficial services to the power system. From adding flexibility to an increasingly complex and distributed grid to saving customers money on their electricity bills, there is value to be realized at every segment of the power system.

However, despite the many benefits of distributed storage and steadily dropping technology costs, it can still be difficult to pencil out the expense of energy storage systems based purely on economics in most regions of the U.S. This is largely due to the fact that while energy storage technologies are advancing at a rapid pace, the market mechanisms supporting them are still in their infancy. Until markets have been developed and properly structured to value energy storage services, the full beneficial impact of energy storage on the power system will remain unrealized.

The current state of energy storage in U.S. electricity markets is examined in a new report by Clean Energy Group, Energy Storage and Electricity Markets: The value of storage to the power system and the importance of electricity markets in energy storage economics. The report examines several instances where market structures have been implemented in a way that compensates energy storage services adequately enough to encourage increased deployment.

Among these markets, the ancillary services market for the PJM Interconnection, an independent system operator (ISO) territory that covers much of the Mid-Atlantic region, is the best example of a storage enabling market. By applying specifications mandated by the Federal Energy Regulatory Commission (FERC), PJM was able to structure its frequency regulation market so that energy storage is compensated for the speed and accuracy it can provide to the system, thereby making it cost-competitive to participate in a traditionally fossil-fuel dominated market. Other areas of the country have developed additional market structures, such as demand response, where energy storage resources can actively participate and generate revenue for the system owner. Unfortunately, these markets are currently quite limited.

The report also details cost saving opportunities that exist for storage in areas with high utility demand charges or time-of-use rates that encourage less electricity consumption during peak periods. These and other potential value streams are discussed along with the successes and limitations of existing markets.

This report serves as an initial primer on the interplay between electricity markets and other economic opportunities for energy storage technologies. Clean Energy Group’s Resilient Power Project and the Clean Energy States Alliance (CESA), through its Energy Storage Advancement Partnership (ESTAP) project, will be co-hosting a webinar to provide an overview of the report on Thursday, August 27th at 1 pm ET. The webinar will also include presentations from energy storage industry professionals active in U.S. electricity markets. (Webinar details here.)

To continue the discussion of markets and energy storage economics, Clean Energy Group and CESA/ESTAP will be hosting a new series of free webinars featuring market experts from Customized Energy Solutions. The first of these quarterly energy storage market update webinars is scheduled for Wednesday, September 30th at 1pm ET. Information about this and other Clean Energy Group webinars can be found here.


This blog post was also published on Renewable Energy World.