Energy Finance Report

Northeast States See Surge in Plans for Offshore Wind Projects, But Developers Must Address Remaining Barriers

Posted by Jeffrey Karp on 6/18/18 12:37 PM

Offshore-Wind-Farm_trans_NvBQzQNjv4BqZyr7RvqrFlHdIeGHHfdSfl4_WL6q5zndbubD7CiBKV0By Jeffrey Karp and Kevin Fink

As previously discussed, offshore wind is  well-developed outside the United States. In Europe, the first offshore wind facility was installed in 1991, and a record 3,148 MW of capacity was added in 2017. In comparison, the first and only operating offshore wind farm in the U.S. is Block Island, a 30 MW facility off the coast of Rhode Island, which began operation in 2016. While the U.S. lags behind European wind energy leaders, Northeast states have sought to facilitate large scale offshore wind development by setting goals and awarding contracts to offshore lease areas. These recent activities have been met with optimism and promise; however, there still are challenges beyond initially securing leases that must be met before offshore wind projects in the U.S. are successfully implemented from start to finish.

Within the past year, New York, New Jersey, Massachusetts, and Rhode Island have announced intentions to incorporate offshore wind resources into their respective energy portfolios. In January 2018, the New York State Energy Research and Development Authority (NYSERDA), issued an Offshore Wind Master Plan, which identified four areas for proposed offshore wind projects, each capable of supporting at least 800 MW. Acting on NYSERDA’s request, the Bureau of Ocean Energy Management (BOEM), the federal agency responsible for approving offshore lease areas beyond state jurisdiction (3 nautical miles offshore), sought public comment on the proposed areas (BOEM published a “Requests for Nominations: Commercial Leasing for Wind Power on Outer Continental Shelf in New York Bight”  in the Federal Register, which gave the public until May 29, 2018 to respond). In May 2018, BOEM extended the comment period to July 30 at the request of New Jersey Governor Phil Murphy to enable the state to adequately address commercial fishing industry concerns. Also in May, Governor Murphy signed legislation committing New Jersey to develop 3,500 MW of offshore wind.

Recently, Massachusetts and Rhode Island also committed to facilitate offshore wind projects. In May 2018, Massachusetts acted on 2016 legislation -- which committed the state to 1,600 MW of offshore wind -- by awarding Vineyard Wind LLC an 800 MW wind farm on the Southern Coast of Martha’s Vineyard. Additionally, Rhode Island chose Deepwater Wind to develop a 400 MW wind farm.

While the offshore wind industry in the U.S. is gaining momentum through lease awards, there still are several barriers that must be addressed if the industry is to successfully construct and operate wind farms. One such potential barrier is the federal Merchant Marine Act of 1920, more commonly known as the Jones Act. Originally enacted to ensure that a domestic merchant fleet could meet shipping needs in case of an international shipping conflict, the Jones Act, among other things, requires shipments made between U.S. ports to be conducted on U.S. vessels manned by U.S. citizens or permanent residents. Additionally, in the context of wind turbines, once a monopile -- the vertical piece struck into the seabed to secure the turbine -- is set into the seabed, it becomes a “point” under the Jones Act, triggering the “U.S. built and manned vessel” requirement. An exception to this requirement is that merchandise may be transferred by foreign crane in conjunction with U.S. vessels transporting materials between points. This method was used to install the 30 MW Block Island Wind Farm; however, industry experts have commented that while the approach worked for a small scale wind farm, it may be too costly for larger scale projects. Therefore, a major consideration may arise shortly because no U.S. entity presently owns Jones Act-compliant vessels capable of transporting and installing large scale offshore wind turbines.

However, some stakeholders have questioned whether the Jones Act applies to offshore wind projects. The Jones Act’s jurisdiction reaches three nautical miles from shore, and the proposed offshore wind projects in the Northeast are beyond that range. Thus, clarification is required as to whether activity occurring outside three nautical miles from shore is subject to the Jones Act. The applicability of another federal law, the Outer Continental Shelf Lands Act (OCSLA), to offshore wind installations also needs to be clarified. The OCSLA initially was enacted to address the exploration, development, and production of mineral resources, but in 2005 Congress amended the law to include licensing requirements for “alternative energy” projects. There still is ambiguity regarding whether the OCSLA applies to offshore wind installations. If both the Jones Act and OCSLA are determined to apply to offshore wind projects, development may be stymied from both a transportation standpoint (via point to point shipments), and in the licensing and construction of projects.

Various approaches to address these potential constraints have been proposed to eliminate any further delay once the leasing stage of a wind farm is completed. A long-term solution, to build Jones Act compliant vessels, already has begun with the first vessel expected to be delivered by the end of 2018. However, some short-term measures also could be taken to further facilitate offshore wind development. Regarding the ambiguity surrounding the jurisdictional reach of the Jones Act, a waiver could be pursued for renewable energy projects until the supply chain side of the industry is mature enough to handle all of the transportation and construction phases domestically. Additionally, an advisory ruling could be sought from U.S. Customs and Border Protection (CBP) regarding whether the OCSLA applies to offshore wind projects.

A second challenge facing offshore wind developers is that U.S. ports will require infrastructure upgrades to handle wind turbine parts that are more than 800 feet tall with blades the length of a football field. Currently, there are no ports or manufacturing facilities in the Northeast capable of adequately handling these parts. In January 2018, the Coalition for More Efficient Ports -- whose members include the Port Authority of New York and New Jersey -- sent a letter to President Trump highlighting the need for ports to receive adequate federal funding. Moreover, Orsted A/S, a Denmark power company with offshore wind projects worldwide, publicly called for East Coast states to expand their ports to accommodate offshore wind development.

Thirdly, delays have ensued due to stakeholder litigation over potentially negative impacts from turbine construction and operation. For example, Statoil (now Equinor), which was awarded a lease for an offshore wind facility off the coast of New York in December 2016, has faced considerable delays from a lawsuit filed against BOEM by the Fisheries Survival Fund and other commercial fishing organizations, businesses, and three municipalities alleging violations of several federal environmental laws, including the National Environmental Policy Act (NEPA). The case, Fisheries Survival Fund v. Jewell, No. 16-cv-2409, is ongoing in U.S. District Court for the District of Columbia. Thus, developers must be cognizant of opposition from interest groups, and be prepared to address their concerns.

Therefore, while states in the Northeast are ramping up plans for large scale offshore wind farms, it is important that developers fashion strategies to address impediments, including the potential impact of Jones Act and OCSLA requirements, port expansion needs, and stakeholders’ environmental and other concerns.

Jeffrey Karp is a partner and Kevin Fink is a law clerk with Boston-based law firm Sullivan & Worcester LLP.

 

Topics: Renewable Energy, Massachusetts, Offshore Wind, Rhode Island, New York, New Jersey, Jones Act, Port Infrastructure, Shipping, Outer Continental Shelf Lands Act

FERC ENERGY STORAGE RULE CREATES NEW OPPORTUNITIES FOR SMALL, LOW-IMPACT HYDROPOWER PROJECTS

Posted by Administrator on 2/28/18 3:49 PM

By Edward Woll Jr.

OVERVIEW

The United States has produced clean, renewable electricity from hydropower for more than 100 years. Today there are approximately 2,500 domestic dams and pumped-storage facilities that provide roughly 100 gigawatts (“GW”) of electricity. In addition, there are more than 80,000 non-powered dams, i.e., existing structures that could produce power, with the potential capacity of 12 GW. New England’s non-powered dams potential capacity is 243 mega watts (“MW”).  Many of the 80,000 non-powered dams could be converted to produce hydropower at relatively low cost and within a relatively short timeframe. See U.S. Department of Energy, An Assessment of Energy Potential at Non-Powered Dams in the United States (2012).

The energy storage rule, Order No. 841, issued on February 15, 2018 by the Federal Energy Regulatory Commission (“FERC”), creates new opportunities for hydropower facilities to participate in the wholesale power market, and thus incentivizes the conversion of non-powered dams to hydropower and the addition of storage to existing hydropower facilities. This article explores the opportunities presented by the new energy storage rule, particularly with respect to small, low-head non-powered dams where the installation of energy generation capacity can be achieved with lower installed costs, lower levelized cost of energy, fewer barriers to development, less technological and business risk, and in a shorter time frame than development requiring new dam construction.  Moreover, energy from low-head hydropower installations can be aggregated for coordinated dispatch into a regional transmission organization (“RTO”), thereby leveraging its ability to be a peak shaving resource, which is an area FERC has determined is important for removing barriers, but has concluded should be the subject of a separate proceeding in order to permit the Commission to gather more information.

UNDERSTANDING ENERGY STORAGE

An “energy storage resource” is a commercially available technology that is capable of absorbing energy, storing it for a period of time, and thereafter dispatching the stored energy to the wholesale or retail electricity market. Existing technologies include (1) batteries (lead acid, lithium ion, sodium sulfur, flow, dry cell); (2) fly wheels (mechanical devices that harness rotational energy to deliver instantaneous electricity); (3) compressed air storage that uses electricity to compress air and store it, which is then expanded through a turbine to generate electricity later; (4) electrochemical capacitors that store electricity in an electrostatic charge; (5) thermal energy storage that uses either heat sinks like molten salts to store heat energy which can be used to either generate electricity or provide heating later; or electricity to freeze water into ice that can be used to provide air conditioning later and (6) pumped hydro power. New developing battery technologies include, for example, sodium-ion and solid magnesium electrolyte.

Energy storage technologies are viewed favorably by most regulatory bodies for many reasons that conform to smart energy policy. They can reduce the emission of greenhouse gases, reduce demand for peak electrical generation, defer or substitute for an investment in generation, transmission or distribution assets, improve the reliable and stable operation of the electrical transmission or distribution grid and reduce or eliminate variability and flicker that accompany some renewable energy sources. These storage technologies are seen as essential to the continued expansion and value of renewable energy, and as key to balancing energy generation and consumption and to maintaining grid stability.

Prior to issuance of the current rule, FERC regulated U.S. interstate wholesale electrical energy markets by participant categories – generators, transmitters and distributors, with different rules for different categories. While generators were authorized to sell into the wholesale market at market-based rates, transmission remained largely subject to cost-of-service ratemaking and required strict adherence to open-access transmission tariffs and non-discriminatory service to customers.

Because energy storage technologies can both inject electricity into as well as withdraw (i.e., be charged by) electricity from the grid, they transcend the Commission’s traditional “siloed” regulatory framework for generation, transmission and distribution resources. Understandably, therefore, FERC’s rules on how to connect energy storage to the electricity grid were inadequately defined and were designed to accommodate traditional technologies that are markedly different from energy storage.  See Massachusetts Clean Energy Council and Massachusetts Department of Energy Resources, State of Charge: Massachusetts Energy Storage Initiative (2016).

FERC’S ENERGY STORAGE RULE

In November 2016, FERC proposed amendments to its regulations to remove barriers that discouraged energy storage resources and distributed energy resources aggregators from participating in the capacity, energy and ancillary services markets operated by the six regional transmission organizations (“RTOs”) and independent system operators (“ISOs”) subject to FERC jurisdiction. Pending public comment on the proposed rule, in January 2017 FERC issued a policy statement clarifying that an energy storage resource may provide services at both cost-based (e.g., transmission, which is regulated) and market-based (generation, which may be non-regulated or market-based) rates at the same time so long as (1) there is no double recovery of costs to the detriment of cost-based ratepayers, (2) the potential for cost recovery through cost-based rates does not inappropriately suppress competitive prices in wholesale electric markets to the detriment of other competitors who do not receive such cost-based rate recovery, and (3) the level of control in the operations of the electric storage resource by an RTO/ISO does not jeopardize its independence from market participants.

The February 2018 final rule adopted the conceptual approach set forth in the 2016 proposed rule and 2017 policy statement. That approach opened and leveled the playing field for energy storage resources by making the resources eligible to participate in the wholesale capacity, energy, and ancillary services markets.  FERC deferred regulatory action with respect to distributed energy resources aggregators until a later date.  The final rule provides regulatory flexibility to effectively deploy energy storage technologies in an array of applications that include improving (i) utility energy efficiency as well as grid stability and security; (ii) grid modernization; (iii) emergency back-up power; (iv) effectuating full use of variable renewable clean energy production facilities such as solar and wind; and (v) lowering annual energy costs.  Each of these applications will contribute to expand state renewable portfolio standards goals and replace fossil fuel and nuclear generating plants.

APPLICATION TO HYDROPOWER

Energy storage resources that are deployed in conjunction with, and charged by small, low-head hydropower projects, can function as an independent energy source that provides: (1) reliable energy for a predictable time period, (2) peak power shaving at a substantially lower cost of electricity than the cost of peak power from conventional fossil-fueled sources, (3) reduced variability and flicker that have accompanied renewable energy sources, and (4) reduced greenhouse gas emissions by displacing demand for more natural gas powered electric power generating plants and natural gas pipelines that have heretofore been relied on to satisfy peak demand. In addition, the Senate Energy and Natural Resources Committee will shortly take up consideration of H.R. 2786, an amendment to the Federal Power Act to incent small-conduit hydropower.  The bill passed the House last year 420-2.

Pursuant to Section 203 of the Federal Power Act (“FPA”), a hydropower facility must be licensed by FERC, receive an order from FERC indicating that it is non-jurisdictional to FERC, or obtain a determination from FERC that it is a “qualifying conduit hydropower facility.”   FERC requires federal licensing when a hydropower project ties into the grid because interstate commerce is affected. 

A non-federal hydroelectric project must also be licensed if it is located on a navigable water of the United States. The complicated issue regarding which waters are deemed “navigable” for purposes of federal jurisdiction is currently being litigated, and the current EPA is seeking to rescind and revise the navigability rules promulgated during the Obama Administration. Non-federal hydroelectric projects are also subject to federal jurisdiction if they (1) occupy lands owned by the United States; (2) use surplus water or water power from a government dam; or (3) are located on a body of water over which Congress has Commerce Clause jurisdiction, project construction occurred on or after August 25, 1935, and the project affects the interests of interstate or foreign commerce. See GZA GeoEnvironmental, Inc., Report on Permitting Small and Low Impact Hydropower Projects in Massachusetts (2016).  

Even small hydroelectric projects that are connected to the interstate grid are deemed to affect interstate commerce by displacing power from the grid, and if the cumulative effect of the national class of these small projects is deemed significant for purposes of FPA section 23(b)(1). However, FERC does not require federal licensing if the hydro project is not tied into the grid, but its power is simply used on site.

Battery storage currently is a preferred technology for shaving peak energy demand and eliminating variability and flicker in renewable, clean energy resources, whether solar, wind or low-head hydropower. Especially important is the fact that battery storage generally can be deployed more quickly and flexibly than other storage technologies to meet peak demand, and at a cost that is expected to continue its significant rate of decline. Hydropower also runs twenty four hours a day seven days a week, subject to water level and environmental requirements. Further, according to the Low Impact Hydropower Institute (“LIHI”), the average capacity factor for LIHI Certified Hydropower is 54.4%.  A “capacity factor” describes how intensively a fleet of generators is run.  A capacity factor near 100% means operation is continuous close to 100% of the time.  In comparison to low-head hydro, the 2017 capacity factor for nuclear was 92.2%, natural gas fired combined cycle – 54.8%, coal - 53.5%, wind - 36.7%, and solar photovoltaic – 27.0%. 

CONCLUSION

A significant opportunity is presented by the potential development of hydro-charged battery storage for peaking facilities at currently existing small to midsize hydro sites. Peaking facilities can be deployed quickly, although installation may require upgraded and smarter transmission and grid infrastructure as well as new grid interconnection construction.  Smart siting and distributed grid integration of battery stored power through hydroelectric generation can significantly reduce the pressure to build more natural gas pipelines to meet peak demand, and cut costs if available when natural gas prices for electricity generators peak.  Other benefits would include enhanced grid reliability, and relatively more stable and predictable electricity prices since these hydroelectric peaking facilities would have small marginal operating costs. 

Advanced energy storage resources are capable of dispatching electricity within seconds without producing direct air emissions. Therefore, significant modifications would not have to meet air quality standards.

In addition, the permitting process for advanced energy storage projects is simpler than for more complex infrastructure projects, and construction timelines are considerably reduced. The modular design of many energy storage systems allow components to operate and interconnect the storage resource using simple containerized structures.  Such projects require a much smaller footprint than conventional power plants and easily can be added in local areas to provide grid stability, thus eliminating the need for new gas-fired generation or new transmission facilities to solve local reliability needs. 

Edward Woll Jr. is a partner with Boston-based law firm Sullivan & Worcester LLP.

Topics: Energy Storage, Renewable Energy, Massachusetts, Low-head hydropower, FERC, hydropower

U.S. Offshore Wind Seeks Critical Mass

Posted by Jim Wrathall on 3/9/16 3:30 PM

Co-author Hayden Baker

Wind_Turbine_Offshore_Under_Construction.jpgLast week’s U.S. Offshore Wind Leadership Conference in Boston had the vibe of a technology sector ready to break out. Industry leaders, federal officials, and a panel of Massachusetts legislators extolled the economic opportunities, and U.S. Senator Edward Markey and Massachusetts Energy and Environmental Affairs Secretary Matthew Beaton delivered inspiring keynotes. Speakers were interspersed with high-energy videos of offshore wind installations in European waters, along with many side meetings among project developers and hopeful supply chain participants.

Offshore wind is garnering more than just hype in 2016. Key developments have this once fledgling energy source poised to finally gain momentum in the United States.

As detailed in our Wind Systems magazine article, the merits of U.S. offshore wind are compelling. At the conference, representatives of DONG Energy and other developers active in U.S. waters described the enormous wind potential of the mid-Atlantic and New England coastlines, focusing on the proximity to underserved energy demand around major urban centers.  Siemens U.S. Offshore Wind Director Jason Folsom discussed a recent study demonstrating the overwhelming economic value of offshore wind relative to conventional power generation when all costs and benefits are considered – even before taking into account greenhouse gas reductions.  Comparing cost curves to other renewable energy technologies in the U.S. marketplace, industry observers expressed confidence that as the industry ramps up there will be sufficient competition to quickly drive down the costs of installation and transmission.

With backing from D.E. Shaw, Deepwater Wind is on schedule to complete its Rhode Island Block Island Wind Farm later this year. The 30 megawatt, 5 turbine project will be the first to come online in U.S. waters.  Block Island is only a precursor to the larger projects currently slated for Massachusetts by DONG Energy, Deepwater Wind and Blackstone-backed OffshoreMW, each of which holds a sizeable federal lease south of Martha’s Vineyard. 

The U.S. industry appears at a tipping point. Sophisticated, experienced developers are ready with mature technology, supportive regulators and abundant wind resources located near load centers.  But the sector needs sufficient reliable demand to justify the massive supply chain investments necessary to scale-up development. 

As the necessary parties for offshore wind step into place, the desire for coastal wind resources, particularly in New England, is becoming acute. Major coal and oil fleet retirements in ISO New England alone are expected to drive at least 3,500 MW of new capacity demand by 2018 – and the ISO estimates several thousand more megawatts are at risk of retirement by 2020. Natural gas plants are not a viable replacement at this scale without significant investment in pipeline infrastructure, leaving offshore wind and imported Canadian hydropower as the primary options for new energy resources in the region. Responding to these factors, Massachusetts legislators reported they expect to announce a comprehensive energy bill this spring.  The sector is poised to receive a huge boost if the bill promotes long term utility purchases of offshore wind energy – and assuming it becomes law. A strong Massachusetts bill could be a prompt for other states, particularly New York, and set the stage for regional cooperation on supply chain development and transmission. Recognizing that the U.S. industry would benefit from a longer glide-path to achieve those lower rates, Senator Markey also touted his forthcoming proposal to extend the 30% federal investment tax credit for offshore wind until 2025.

While all eyes are on the Massachusetts energy bill for the next step, developers are positioning themselves for growth down the coast as well. For instance, in New Jersey, DONG Energy recently acquired from RES Offshore a lease in federal waters off the Garden State’s coast.  Meanwhile across the Hudson River, Deepwater Wind is reportedly considering a waterfront terminal in Brooklyn to stage its offshore activities in the Empire State and to build up the regional infrastructure. In Maryland, US Wind’s proposed $2 billion, 250 MW project has passed initial screening tests and is in the process of qualifying for valuable credits under Maryland’s Offshore Wind Energy Act of 2013.

State policies supporting long term utility offtake agreements are the key to filling the project pipeline. But as the Massachusetts legislators reminded Leadership Conference participants, short term electricity rates are the political measuring stick against which state energy proposals will be evaluated. Koch brother-supported opponents are well funded and undoubtedly will continue their grass roots strategy stoking fears of increasing electricity rates.

In light of these developments, what was the bottom line takeaway from the U.S. Offshore Wind Leadership Conference? The opportunity is huge.  But given the broader political dynamics, business as usual for offshore wind developers likely will not be sufficient.  For offshore wind proponents, now is the time for redoubled public advocacy informing both politicians and the public alike of the vital stakes in this debate.

Topics: Wind, Massachusetts, Offshore Wind, Wind Energy, DONG Energy, Deepwater Wind, BOEM, Siemens

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