Energy Finance Report

U.S. House Committee on Energy and Commerce Hearing on Energy Storage Highlights Need for Further Federal and State Initiatives

Posted by Administrator on 8/7/18 3:42 PM

By Kevin Fink

On July 18, 2018, the U.S. Congress House Committee on Energy and Commerce held a hearing to assess the progress being made by federal and state governments to promote the role of energy storage in the U.S. electrical system. A panel of five witnesses – an executive from the California Independent System Operator (“CAISO”); a partner at an energy and environmental economic consulting firm; and executives from E.ON, Fluence Energy, and Duke Energy – were present to testify and answer questions of the legislators.

The experts were largely favorable in their assessment of the steps taken by the federal government to promote energy storage and reduce existing barriers through opening up wholesale markets. In particular, there was a nearly universal consensus that FERC Order 841 (February 2018) had the desired effect of catalyzing energy storage’s role in the electrical grid by directing Regional Transmission Operators (RTOs) and Independent System Operators (ISOs) to create market rules for energy storage participation in the wholesale energy, capacity, and ancillary services markets. However, the testifying experts also expressed the view that Order 841 was but an initial step to promote energy storage, and that additional measures must be taken to allow energy storage to reach its full potential by clarifying certain provisions of the order, creating of additional policies and roadmap(s), and creating federal tax credits. Moreover, most experts agreed that finalizing Order 841 and 845 (Order revising the definition of generating facility to explicitly include energy storage) and denying requests for a rehearing would speed up the implementation process.

A prominent talking point focused on the need to extend federal tax credits to energy storage projects, particularly those that were not incorporated into larger renewable energy developments and are eligible to receive an investment tax credit (“ITC”). Most notably, the experts concurred that extension of the ITC to include stand alone energy storage projects would both lower the cost of the investment and accelerate its implementation. A continuing theme was that almost everyone in the renewable energy space benefits from tax credits and that energy storage technologies were maturing at such a rate that any targeted tax benefits would only be necessary for a few years. Moreover, one expert noted that application of the ITC to energy storage should be commonplace as Section 48 of the Internal Revenue Code (“IRC”) allows renewable energy paired with energy storage to receive the ITC – raising the question of why should energy storage not be able to receive credit as a stand alone, when it is performing the same function when paired with renewables. The expert suggested that the definition of which technologies qualify for the ITC be broadened to include energy storage. It should be noted that legislation has been introduced in both the Senate (S. 1868) and the House (H.R. 4649), proposing to amend the IRC to allow investment tax credits for energy storage technologies and battery storage technology.  

Federal vs. state initiatives was another hot button topic, and it was noted that a number of states, such as New York and Massachusetts, have begun to adopt their own energy storage policies and roadmap)s. Nonetheless, most believed that a federal energy storage roadmap was imperative in order to reiterate the federal government’s commitment to energy storage, and to serve the critical function of educating stakeholders on the benefits of energy storage.

There is little doubt that energy storage technologies will become integrated in the renewable energy sector by necessity, given the intermittent nature of wind and solar power. However, the House is still grappling with how the federal government can best accelerate the development of the energy storage market and incentivize competition. 

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

Topics: Energy Storage, U.S. House of Representatives, Investment Tax Credit, Renewable Energy

Energy Storage and Hydropower Experts Offer Industry Perspectives at 2018 Grid Scale Energy Storage Summit

Posted by Administrator on 7/23/18 1:26 PM

By Kevin Fink

Sullivan & Worcester counsel recently participated in the “Grid Scale Energy Storage Summit,” part of the expansive Hydrovision International conference held at the end of June in Charlotte, North Carolina. For the first time on an international scale, the Summit brought together both energy storage and hydropower experts from around the world for the purpose of debating, among other things, the future role of hydropower in the mix of energy storage options.  

In addition to Sullivan & Worcester and other counsel, energy sector participants included representatives from the U.S. Department of Energy, renewable energy trade associations such as the Solar Energy Industries Association, and Regional Transmission Organizations (“RTOs”) and Independent System Operators (“ISOs”).  The hydropower industry was represented by a variety of trade associations including the National Hydropower Association, International Hydropower Association, and the Low Impact Hydropower Institute.

The energy storage industry is growing exponentially in the United States. Total installed capacity exceeded 1,000 MWh in 2017 – a record amount – and energy storage is forecast to add an additional 1,000 MWh capacity in 2018. As a result, energy industry experts in both the private and public sectors are grappling with how best to manage energy storage’s role in the electrical grid as well as capitalizing on the maturing industry.

Discussions focused on the role of energy storage in addressing new challenges to the reliability of the electric grid posed by increasing reliance on wind and solar, the implications and adequacy of new policies and regulations that have created expanded opportunities for energy storage participation in interstate markets, and whether sufficient market demand exists to encourage the pairing of “pumped hydro” with other renewable technologies such as wind and solar.  “Pumped hydro” facilities are currently the predominant form of energy storage, and typically operate through the storage of water in one or more reservoirs.  During periods of peak electricity demand, water from an upper reservoir is released to a lower one and moves through turbines to generate power. In instances of low demand, low-cost electricity from the grid is used to pump water back up into the upper reservoir. 

pumped-hydro

A common theme throughout the Summit was the expression of frustration by the hydropower industry that while “pumped hydro” has existed since the 1920’s and currently accounts for 97% of the nation’s installed energy storage capacity, current regulatory policies tend to encourage the development of newer, not yet matured energy storage technologies such as batteries, compressed air, and flywheels.  A consensus emerged regarding the need for a level playing field so that all energy storage technologies, including “pumped hydro,” are utilized to their greatest potential. It was further agreed that stakeholders and the public need to be educated regarding the untapped potential of “pumped hydro” and that the public’s perception of “pumped hydro” is often associated with large, conventional hydropower (which involves larger impacts from both an environmental and financial perspective) rather than smaller, local projects which can present lesser environmental impacts and financial burdens.    

In conclusion, although the deliberations largely focused on hydropower’s role in the emerging energy storage market, there were many key takeaways that apply to the energy storage industry beyond just hydropower.  Of particular interest was the February 2018 FERC Order 841, which directed RTO/ISOs to establish “participation models” for energy storage. While viewing Order 841 as a favorable start in terms of establishing a regulatory framework for energy storage, most conferees expressed the desire that FERC take a more expansive approach in the Order and set more explicit requirements governing “participation” and “interconnection,” but also acknowledged that each ISO/RTO region has different needs and resources to address those needs.  

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

Topics: hydropower, Energy Storage, Renewable Energy, FERC

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: Offshore Wind, New York, New Jersey, Massachusetts, Rhode Island, Jones Act, Port Infrastructure, Shipping, Renewable Energy, 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: FERC, hydropower, Energy Storage, Massachusetts, Renewable Energy, Low-head hydropower

Renewables Can Play a Big Role in Puerto Rico's Fresh Start

Posted by Jeffrey Karp on 6/27/17 11:23 AM

This article originally appeared on Recharge.

Just two years ago, the future seemed promising for renewable energy development in Puerto Rico. Much of the groundwork was established, numerous developers had entered into Power Purchase Agreements (PPAs) with the state-owned utility, PREPA, and discussions were ongoing with funding sources.

However, decades of fiscal irresponsibility and bad deals finally caught up with Puerto Rico, leading to a terrible debt crisis. The government defaulted on bonds, sales taxes escalated to 11% (higher than any mainland state), and businesses began fleeing the island.

The generous incentives that initially had attracted development dried up. For the last couple of years, energy investment has been at a virtual standstill, with the exception of Oriana Energy’s solar plant that commenced operations in May 2017.

Despite these setbacks, and with the Commonwealth’s [government's] bankruptcy filing in May 2017, the Puerto Rican government now has a second chance to regain its financial footing, and the development of renewable energy may play an integral part in accomplishing such a task.

In 2010, the Commonwealth enacted Renewable Energy Portfolio Standards (REPS) that required 12% of the island’s electricity to come from renewable sources by 2015 and 20% by 2035. Following the enactment of the REPS, utility PREPA entered into dozens of PPAs with renewable energy developers agreeing to purchase the power to be generated. By the end of 2015, Puerto Rico had 318MW of renewables in place, according to latest available data from the International Renewable Energy Agency.

However, as Puerto Rico became mired in its debt crisis, developers were unable to secure financing as investors grew fearful of funding long-term energy deals with PREPA. Adding to the uncertainty, due to PREPA’s financial woes, the utility serially renegotiated the terms of developers’ PPAs, which only served to make investors more jittery about financing the underlying renewable energy projects. Eventually, most of the agreements expired before the power plants could be financed or built.

Despite its financial travails, Puerto Rico’s commitment to renewable energy has not waned. In June 2016, Congress passed the Puerto Rico Oversight, Management and Economic Stability Act (PROMESA). The legislation, intended to provide Puerto Rico with a pathway out of its debt crisis and establish a baseline for fiscal responsibility, also established the framework within which investment may occur. In providing a blueprint for interested investors, PROMESA also reaffirmed Puerto Rico’s commitment to renewable energy.

Recognizing that PREPA was incapable of shouldering the burden of energy development entirely on its own, PROMESA emphasized the need for public-private partnerships that shifted the initial funding burden to private investors. In April 2017, a P3 Summit was held to encourage developers and investors to collaborate with the Commonwealth on a wide variety of infrastructure projects, including energy, water, waste management, and transportation. The presentation on the energy sector reaffirmed Puerto Rico’s commitment to achieving the REPS of 20% renewable energy by 2035.

In setting the stage for infrastructure investment, PROMESA created an Oversight Board, which has authority over revitalization and infrastructure development. Importantly, the Oversight Board may “fast-track” projects deemed “critical,” such as projects that reduce the Commonwealth’s reliance on oil and diversify its energy sources. Moreover, the Oversight Board gives priority to privately-funded projects.

Following PREPA’s recent settlement with its bondholders, we understand the utility is ready to reengage with developers to amend PPAs that have been in limbo for several years. Many of these developers already have performed much of the engineering for these renewable energy projects. Once PREPA amends the extant PPAs, the underlying projects would qualify as “existing projects,” which would enable the Oversight Board to prioritize them.

In light of these recent fiscal and regulatory developments, investors again are inquiring about “shovel ready” renewable energy projects that require funding. Investors also may have gained a level of comfort having seen Oriana Energy successfully reengage in Puerto Rico. Since May 2017, the company is operating the largest solar plant in the Caribbean at 58MW, the power from which PREPA is purchasing pursuant to a renegotiated PPA.

Puerto Rico appears primed for renewed interest by energy investors. For several years, investors have been unwilling to accept the risks inherent in financing long-term energy projects in which PREPA is the counterparty. More recently, these concerns have shown signs of abating as PREPA has successfully engaged with its bondholders, and the Oversight Board created by the PROMESA legislation appears to have imposed an acceptable level of fiscal discipline on the Commonwealth.

With solar energy on the cusp of coming to Puerto Rico, the question is which financiers will enter the market soon enough to bathe in the sunlight.

Jeffrey Karp is a partner in the Washington, D.C. office of Sullivan & Worcester LLP and leader of the firm’s Environment, Energy & Natural Resources practice group. Zachary Altman, an associate, and Paul Tetenbaum, an intern at the firm, were co-authors of this article.

Topics: Puerto Rico, Renewable Energy, Power Purchase Agreements, Renewable Energy Portfolio Standards, Energy Finance, Energy Investment

Opportunities Abound in the U.S. Offshore Wind Market

Posted by Jeffrey Karp on 5/30/17 12:52 PM

Offshore wind projects have taken root in America. The country’s first operating offshore wind farm, in Block Island, Rhode Island, began contributing energy to the power grid in December 2016. Now, more than 23 offshore wind projects — collectively expected to produce 16,000 MW of power — reportedly are being planned. Thus, opportunities abound for developers, contractors, and investors in the U.S. offshore wind market.

The recent spike in offshore wind activity has been fueled largely by a surge of political interest. Some critics have decried President Trump’s apparent lack of commitment to renewable energy, but the U.S. Department of the Interior (DOI) has proved to be a willing partner in offshore wind energy development. In March 2017, DOI leased 122,000 acres off the coast of North Carolina to Avangrid, a subsidiary of Iberdrola, a Spanish company. Recently, DOI also finalized a lease with a Norwegian company, Statoil, for Long Island, New York waters. DOI evidently sees a future for U.S. offshore wind. According to a spokesperson, the Bureau of Ocean Energy Management currently is receiving annual rent payments of over $4 million for offshore wind project leases.

State activities also have primed the pump for offshore wind development. In August 2016, Massachusetts Governor Charlie Baker signed a law requiring utilities to procure 1,600 MW of electricity from offshore wind facilities by 2026. In May 2017, the Commonwealth’s Department of Energy Resources issued a request for proposals to develop up to 800 MW of offshore wind. New York Governor Andrew Cuomo announced that the state would commit to installing 2,400 MW of offshore wind by 2030, furthering his goal that renewable energy resources would supply 50% of New York’s power. To that end, in January 2017, Governor Cuomo approved Deepwater Wind’s 90 MW, 15 turbine South Fork Wind Farm project, which is expected to power 50,000 Long Island homes.

Moreover, the Maryland Public Service Commission recently awarded two developers, U.S. Wind and Skipjack Offshore Energy, contracts to build offshore wind farms totaling 368 MW. The projects are expected to create 9,700 new direct and indirect jobs.

With each completed project the supply chain grows stronger and developers become more efficient, making each successive project more cost-effective. For example, the estimated total cost of the South Fork project already has decreased 25% since Deepwater Wind’s first projections, and the energy generated is expected to cost 30% less per unit than at Block Island. Furthermore, the Department of Energy predicts that the cost of offshore wind energy will fall 43% by 2030. As this trend continues, there will be greater incentives to promote offshore wind as a clean energy resource.

Also, each successful project increases investor confidence. Deepwater Wind, developing its second offshore wind project, is owned by D.E. Shaw, a hedge fund and private equity firm managing over $40 billion in assets. Moreover, both Citigroup and HSBC have expressed interest in financing future offshore wind projects.

The U.S. offshore wind market is growing rapidly and approaching maturity. State and federal government actions appear to support a long-term horizon for offshore wind development. With every completed project, production and financing costs will continue to drop, the market will grow, and new jobs will emerge. The question now is whether the players in the renewable energy market — developers, investors, contractors, and vendors — are well-positioned to reap the rewards of this burgeoning industry.

Jeffrey Karp is a partner, Zachary Altman is an associate, and Leigh Ratino is a law clerk with Boston-based law firm Sullivan & Worcester LLP.

Topics: Energy Finance, Energy Investment, Energy Project, Energy Project Finance, Wind Energy, Offshore Wind, Renewable Energy

New York Unveils Details of its Clean Energy Program

Posted by Merrill Kramer on 8/9/16 11:46 AM

Co-author Morgan M. Gerard

New_York_Clean_Energy_Standard_Solar-1.jpgThe New York Department of Public Service (DPS or Commission) on August 1, 2016 issued its long-awaited Clean Energy Standard order (“Order”). The Order sets forth the means by which the Empire State intends to achieve its ambitious goal of supplying 50% of the State’s electricity needs with clean energy by 2030 (50x30). By attaining this target the State will reduce its overall carbon emissions by 40%.

The Clean Energy Standard (CES) Order is a companion to a State initiative already underway called Reforming the Energy Vision, or REV. REV creates a transformative competitive framework for increasing the use of locally-sited or “distributed” energy, energy efficiency, energy storage, and customer load controls, collectively referred to as Distributed Energy Resources or DER. REV is seeking to establish a locational market-based platform through which DER resources are priced and may be bought, sold and traded. REV also includes an initiative to promote development of large-scale renewable projects to be integrated into the State’s electricity grid.

The CES order primarily focuses on three large-scale resources to supply the bulk of electrical supply needed for the State to achieve its ambitious 50x30 goal:

  • Large scale solar, wind and other renewables which the DPS expects to contribute approximately 29,000,000 MWh toward the goal;
  • Off-shore wind resources, which the DPS praises as a significant resource of potential value;
  • Existing uneconomic nuclear facilities that, while not renewables, constitute low carbon resources. Without ensuring that these plants continue to operate, DPS concludes that their output would be replaced by fossil fuel power plants whose emissions would undermine the State’s carbon emissions reduction goals. The program thus announces subsidies that it will provide to several nuclear facilities.

The plan to subsidize nuclear power plant operations is sure to be the most controversial aspect of the CES program.

To maximize the reach and uniform application of the clean energy program, the DPS establishes a renewables mandate not merely for utilities subject to its rate jurisdiction such as investor-owned utilities, but also retail energy service providers (ESCO’s). In addition, the CES Order applies to the Long Island Power Authority (LIPA), the New York Power Authority (NYPA), municipalities, and companies that purchase power from the New York Independent System Operator (NYISO).

The DPS solicits public comment on certain aspects of the Order and directs NYSERDA to implement other portions of the Order. Notably, the Commission solicits comments to seek to ensure that its clean energy standards are designed to “expand energy development by retaining and creating investor confidence” by “providing clarity and certainty to investors in implementing the Program.” The highlights of the CES program are as follows:

The New Renewable Energy Standard

The CES program is centered on a Renewable Energy Standard (RES). The RES is effectively a compliance obligation placed upon Load Serving Entities (LSEs) such as investor-owned utilities and retail energy service providers (ESCOs) to procure a target percentage of their generation mix from renewable resources. The procurement can be accomplished in three ways: (1) building new renewable facilities, (2) entering into power purchase agreements with third party renewable developers and (3) purchasing Renewable Energy Certificates (RECs), including from NYSERDA. The Order allows LSEs to choose to meet its renewable obligations by making an “Alterative Compliance Payment” or ACP. The ACP effectively acts as a ceiling on the price entities will pay for RECs.

NYSERDA will continue its program of providing cash incentives to third party renewable developers through solicitations and Statewide procurement in exchange for receiving the project’s RECs (which NYSERDA will in turn sell to LSEs and others to meet their respective RES obligations). A New York Generation Attribute Tracking System (NYGATS) operated by NYSERDA will provide a liquid trading platform for RECs in New York. Renewable resources may register their project’s environmental attributes to qualify them for RECs eligible for sale to LSEs and others.

The DPS divides eligible technologies for REC generation into three tiers: (1) Tier 1, which includes solar, fuel cell, wind, ocean/tidal, biogas, biomass and liquid biofuel; (2) Tier 2, a maintenance program to provide incentives to certain capital intensive existing technologies such as small-hydro; and (3) Tier 3—a special credit generated by nuclear energy called Zero Emission Credits, or ZECs. ZECs are specially priced certificates designed to preserve the ailing nuclear industry in New York. LSEs will be required to purchase a certain percentage of ZECs. 

In addition to RES requirements, the DPS envisions the development of a thriving “voluntary” green market, and encourages market participants to go above and beyond the mandatory thresholds to create and participate in a green energy products market that achieves additional greenhouse gas reductions.

Annual Renewable Targets and the Voluntary REC Market

The 2030 target of 50% renewable resources is allocated to individual LSEs and others based on an allocation formula tied in part to the LSE customer’s percentage contribution to the total System Benefits Charge (a DPS mandated charge to customers that is levied by distribution utilities and used to fund renewable energy incentives among other programs). The actual target of MWh in any period may be adjusted based on a number of factors. Among other things, LSE targets may be impacted by other market activity that includes retail, end-user participation in opt-in or other voluntary programs, energy efficiency, behind the meter third party renewable investments, conservation and other variations in demand and supply. Creation of a voluntary REC market that generates “additionality” is hoped to have an impact that will result in renewables consumption above and beyond the CES goal.

New Breath for Offshore Wind

The CES Order focuses on large-scale resources that can help the State meet its goals. Offshore wind is viewed as a potentially abundant energy resource in New York. The CES Order therefore sets a path for “steel in water” development.  Depending upon the distance from the shoreline, offshore wind projects will either be in state or federal waters.  The jurisdictional complexity inherent in offshore wind project development therefore requires coordination of clear state and federal programs and policies. 

With support from the State, the Deepwater Wind Project, a 90 MW project off the coast of Montauk, Long Island, has been going through the regulatory review and approval process. A coalition including NYPA, LIPA and Con Edison has also submitted a proposal for an additional project off the coast of the Rockaway Peninsula of Long Island.  Both project areas are far-enough off the coast to qualify as the “Outer Continental Shelf” (OCS), which is under the jurisdiction of the federal government and the Bureau of Ocean Energy Management (BOEM). 

NYPA, LIPA and Con Edison’s unsolicited project was denied by BOEM, and BOEM will now seek proposals in a competitive bidding process. The bidding process for the identified wind area is just under way. A Proposed Sale Notice (PSN) issued by BOEM, which is open to public comment, provides detailed information concerning the area available for leasing and proposed leasing terms. The PSN comment period also serves as the timeframe during which any company wishing to participate in the final lease auction may submit a qualification package.  Currently, there are seven companies that are already qualified to participate in the potential auction for the New York Wind Area.

State action will be necessary to implement the Deepwater and other offshore wind projects to run new transmission and distribution lines to the site, as well as provide for a stable offtaker to provide the required assurances for a financeable energy project. The CES Order includes a “program to maximize the value potential of new offshore wind resources,” and DPS directs NYSERDA to “identify the appropriate mechanisms the Commission and the State may wish to consider to achieve this objective.”

Warming up to Nuclear Power

Nuclear generation has a long history in New York. Several State plants are nearing the end of their useful life and are planned for retirement. Many nuclear plants, such as Entergy’s Fitzpatrick nuclear plant in upstate New York, have high operation and maintenance costs and are no longer economic. These plants generate a tremendous amount of energy - around 16% of the State’s overall energy. However, due to high operation and maintenance (O&M) expenses and low natural gas prices, coupled with their inability to quickly ramp up and down to respond to demand, these plants are not competitive in the NYISO market.

DPS has expressed concern that shuttering these plants could lead to their replacement by fossil fuel resources. This in turn would threaten the emissions reductions achieved through low-carbon programs. Therefore, the CES Order provides nuclear plants with a separate tier that includes a premium payment to avoid this result.

Nuclear electric generation will have its own designated emissions allowances called zero emissions credits, or ZECs. LSEs will be required to purchase a certain percentage of ZECs, and the required level will be set by NYSERDA.  To procure and allocate ZECs, NYSERDA will enter long-term contracts with nuclear facilities that are considered “at-risk.”  Plants within the Tier 3 category include Entergy's Fitzpatrick, Exelon’s Nine-Mile Point and Ginna nuclear facilities, but not Entergy’s Indian Point nuclear plant. The 43-year old Indian Point nuclear reactor has faced a series of safety and operational problems, and Governor Cuomo has called for the plant to be permanently shut down.

Shortly following issuance of the CES Order, Exelon agreed to purchase Entergy’s Fitzpatrick nuclear plant for approximately $110 million. Following the purchase Exelon will own all three nuclear plants in the State eligible for ZECs.

The effect of the ZECs is to create a price floor for nuclear energy. Providing these base load plants with a price subsidy is a legally uncertain area as it raises Constitutional questions under the Supremacy Clause regarding the authority of a State agency to set rates in an area that may be preempted under federal law, in this case, FERC jurisdictional authority. Only recently, in 2016, the U.S. Supreme Court in Hughes v. Talen Energy Marketing struck down a plan in Maryland to incentivize the installation of a new in-state power plant by providing it with a price floor that would allow the plant to competitively bid its power into the PJM power pool. The Supreme Court found that the rate incentive interfered with the FERC’s exclusive jurisdiction to set prices for the wholesale sale of power into PJM.

DPS anticipates these potential challenges. The DPS distinguishes its actions by arguing, among other things, that: (1) the Supreme Court has not directly barred bilateral power purchase agreements outside of the ISO competitive process; (2) the ZEC payment is not for electric power but, rather, for the environmental attributes or REC’s from the plants, an area that the FERC has stated is outside the purview of its rate authority; (3) the ZECs quantify the environmental benefits to New York caused by lowering carbon emissions and thus have an independent rational basis; and (4) the State has clear authority over the health, welfare and environmental protection of the State and its citizens. While the ZECs may have an impact on wholesale rates, the Supreme Court has recognized that such incidental impact on wholesale rates is a permissible exercise of state authority.

Conclusion

The CES Order lays out additional details on how the State plans to achieve its clean energy goals, and in what areas it intends to rely upon the private market to help it meet those targets. The order emphasizes the need for its rules to not only attract outside capital, but to insure that the program is sufficiently competitive with clean energy programs in neighboring states to attract these projects to New York.

The Commission has solicited comments on various aspects of the clean energy program with an eye toward having LSEs implement the program and commence their obligations by the beginning of 2017. The Order lays out an ambitious program that pushes the boundaries for new renewable generation, including paving the way for offshore wind, while announcing a major policy turn in deciding to preserve and maintain portions of the State’s nuclear fleet in operation. The DPS has sought to carefully balance its desire for utility financial stability with its commitment to attracting competitive renewable energy development to the State, on-shore and off-shore.  Only the future will tell if the State has struck the right balance.

Topics: NY REV, Reforming the Energy Vision, New York Solar, clean energy standard, Renewable Energy

The New Gold Standard for Building Performance - PEER

Posted by Van Hilderbrand on 7/19/16 10:20 AM

Co-authors Jeffrey M. Karp and Morgan M. Gerard 

PEER.jpgElectricity-grid vulnerabilities were deeply exposed in the wake of Superstorm Sandy and its associated storm surge, as a single outage at a substation caused a sweeping black-out across downtown Manhattan, New York. Making matters worse, climate change science anticipates that future storms will be both stronger and more frequent.  To facilitate and improve the security, resiliency, and reliability of the macrogrid system, the U.S. Green Building Council (USGBC) has developed PEER, Performance Excellence in Electricity Renewal, the nation’s first comprehensive, consumer-centric, data-driven tool for evaluating power system performance. 

Modeled after the Leadership in Energy and Environmental Design (LEED) certification program, PEER seeks to incentivize the development of smarter buildings and communities by adopting a rating system that addresses power quality and supply availability, ability to manage interruptions and mitigate risk, and increase restoration, redundancy, and microgrid capabilities.

The expectation is that as a critical mass of buildings and developments achieve PEER certification, the electricity-grid system will become stronger and more resilient, thus preventing disasters caused by extreme-weather events.

PEER Will Help Create a Market to Capture the Benefits of Smart Grid Capabilities

Today, there are no adequate markets and metrics to capture the benefits that smart grid capabilities and smarter buildings provide to the larger electrical system, although proceedings like Reforming the Energy Vision (REV) in New York are attempting to tackle this challenge. PEER helps fill this major market gap by providing an opportunity for power technologies, systems, and other innovations to gain competitive advantage. 

The PEER program also may serve to assist in the creation of monetization pathways for service providers seeking to enable grid secure benefits.  For example, once the PEER rating system is used more broadly, commercial tenants and buyers may demand resiliency benefits for which they may be willing to pay a premium to reduce exposure to power-outages, business interruptions, and other grid losses.  For instance, a Whole Foods may be willing to pay an energy premium for the security that its refrigerators and air-conditioning will not lose power in a storm event, hedging the risk of spoiled stock.  Similarly, an investment bank with on-site servers may also be willing to pay the premium for the security that their servers will not stop trading—preventing potential losses from reconciliation events.  Thus, PEER may bring new participants into the energy mix such as main street corporates and traditional real estate firms as they learn about the benefits of and opportunities provided by expanded demand response capabilities, distributed renewable generation, and smart grid readiness.

Projects eligible for PEER certification may involve everything from retrofits to existing buildings and infrastructure, to a newly developed business campus. Projects first must be registered with the Green Business Certification Inc. (GBCI), which administers the LEED certification program, as well as several other performance standards rating certifications.  GBCI provides a toolkit for developers to self-screen projects and prepare their application for certification.  To achieve certification, projects are considered against four metrics: (1) reliability and resiliency; (2) energy efficiency and environment; (3) operational effectiveness; and (4) customer contribution.  The PEER process is relatively new, with only a few projects working their way through the new program, but once the new standard catches on certifications are expected to increase.

Microgrids, the Nation’s Capital, and PEER

A particular concern for national security is the susceptibility of the District of Columbia to flooding and black-outs due to its close proximity to several rivers. This concern has prompted the White House to announce significant targets for federal buildings to combat grid vulnerabilities and the D.C. Public Service Commission to further examine grid modernization through an open case, Formal Case 1130.

Earlier this month, USGBC and GBCI, in partnership with Urban Ingenuity, sponsored a meeting to support the District of Columbia’s efforts to encourage the development of microgrids, generally a localized, self-contained, contiguous power generation system within close proximity to demand. Microgrids provide grid efficiencies and resilience because they can “island” themselves off from larger macrogrid disturbances.  Thus, during a stress event on the macrogrid, microgrids can help service the larger system, isolate the event and prevent it from causing sweeping outages, and serve as a “power oasis” to the affected public.  

The development of microgrids are the kind of project that will be supported by a PEER evaluation and certification. The availability and widespread acceptance of PEER’s metrics will serve as a tool to incentivize the development of microgrids and other types of energy innovations that help facilitate movement of the electrical system towards a smarter-grid marketplace.  

 

The Energy Finance Report will continue to monitor PEER as the program matures.

Topics: USGBC, United States Green Building Council, Performance Excellence in Electricity Renewal, PEER, LEED, Renewable Energy, Resiliency, Distributed Energy

U.S. Offshore Wind:  Mid-Year Update

Posted by Jim Wrathall on 6/7/16 2:13 PM

Co-Authors Hayden S. Baker and Morgan M. Gerard

Several speakers at the recent American Wind Energy Association (AWEA) annual conference in New Orleans lauded the positive impact of Congress's extensions of the production tax credit (PTC) and investment tax credit (ITC) in December 2015. As they noted, these extensions position wind energy for a period of unprecedented stability and growth—at least for the onshore wind sector.

Offshore_Wind_Update.jpgOffshore wind has tremendous potential in the United States, but unlike the onshore wind sector, offshore still has a long way to go to reach critical mass. The recent PTC/ITC extensions ramp down by the early 2020s. As a result, only a few early offshore projects are likely to be far enough along to benefit from the PTC/ITC extensions. Absent a further tax incentive specifically directed to offshore wind, as recently proposed by Senators Markey (D-Mass) and Whitehouse (D-RI), offshore wind will continue to rely on state-level policies to build out the necessary supply chain.

Where will U.S. offshore wind find support to attain critical mass? Here are six major areas of recent progress:

1. Massachusetts Offtake Legislation 

Massachusetts lawmakers recently introduced an omnibus bill, H.4336, which could spur as much as $10 billion of investment in offshore wind, according to Bloomberg. Several major Massachusetts projects could benefit, including those of DONG Energy, D.E. Shaw-backed Deepwater Wind and Blackstone-backed OffshoreMW. The bill would impose offshore wind energy procurement requirements on Massachusetts utilities, thereby ensuring guaranteed power sales and long-term revenues. In its current form, H.4336 would require utilities to purchase 1,200 megawatts of offshore wind, although industry proponents are pushing for a 2,000 megawatt commitment. Governor Baker is expected to support enactment of the bill although final details remain in play, particularly with regard to the balance between offshore wind and competing proposals to source clean energy from Canadian hydropower.

2. New York Renewables Standard and Proposed Lease Sale

Offshore wind should receive a major boost from Governor Cuomo’s Clean Energy Standard goal of 50% renewable generation by 2030. As Richard Kauffman, the state’s Chairman of Energy & Finance, has observed, New York is not going to meet that goal without offshore wind. Offshore developers and supply chain participants have heeded the call and are already mobilizing in anticipation of an offshore wind market centered in Long Island.

East_Coast_Offshore_Wind.jpgLong Island is a prime target for offshore wind developers. The wind resource is ample and the service territory massive (approximately 1.1 million people). In addition, the existing transmission infrastructure is constrained and the island’s geography is such that it would be difficult to construct new transmission lines. New lines would also likely become a rate-based asset, the costs of which would be passed along to the retail customer. Offshore wind could meet the island’s demand closer to the load reducing the need for new long-distance transmission lines coming from the mainland. Additionally, the price of power in Long Island and New York is generally expensive in comparison to the rest of the country, allowing developers room to benefit from higher competitive pricing.

On June 2, 2016, the U.S. Department of Interior (DOI) announced the proposed lease sale of over 81,000 acres for development approximately 11 miles south of Long Island. The proposed lease area was identified in March 2016 by the Bureau of Ocean Energy Management (BOEM) as a wind energy development area in response to an unsolicited proposal by the New York Power Authority to construct a potentially 700 megawatt installation. BOEM expects to issue its proposed sale notice soon, which will be subject to a 60-day public comment period. Additionally, there will be an associated environmental assessment and a 30-day comment period.

3. New Jersey Anticipating Post-Christie Policy Support

New Jersey is entering its gubernatorial election cycle, and offshore wind proponents are eagerly awaiting the next administration. Outgoing Governor Chris Christie recently vetoed legislation that would allow the New Jersey Board of Public Utilities (BPU) to approve qualified offshore wind projects and offer a 30-day window for developers to submit applications. The bill would have revived the 25 megawatt proposed Fishermen’s Energy project off the coast of Atlantic City, which was previously denied by the BPU. Fishermen’s Energy has garnered federal support and is eligible to obtain a nearly $50 million grant from the Department of Energy (DOE). Fishermen’s and other offshore proponents expect legislative efforts will ultimately succeed under a supportive state executive.

4. Steady Progress for Maryland 

Maryland has been supporting offshore wind since 2013 when Governor Martin O’Malley signed the Maryland Offshore Wind Energy Act. This legislation allows for the creation of credits to support wind projects 10 or more miles off the coast. The credits will act as fiscal mechanism in place to pay for at least some of the electricity generated from projected wind farms. Recently, US Wind procured federal leases to support approximately $2.3 billion in project development slated to start in 2017.

5. Industry Cooperation and Advocacy

In the last year activities of offshore sector groups and developers have picked up the pace in advocating for helpful state policies, coordinating strategies, and developing the supply chain. Offshore Wind Massachusetts and the Business Network for Offshore Wind have been central to the sector’s organizing efforts, supported by lobbying of several dozen other groups and companies. The entry of European heavyweight DONG Energy has been a major catalyst in moving the field forward not only in Massachusetts, but also elsewhere along the Eastern Seaboard, including New Jersey, where it recently acquired RES America's 160,480 acre lease area. DONG has been very active and successful in working with state policymakers.

6. Federal Activities and Preparing for the Next Administration

DOI and BOEM are pushing forward with ocean area wind leasing, environmental analysis and streamlined permitting. The Obama Administration has been generally supportive of offshore wind, but has not launched any major support at the federal level. The outcome of the upcoming presidential election obviously will be critical for offshore wind. Donald Trump is on record as a virulent opponent of offshore wind and has embraced a fossil-focused energy policy. By contrast, a Clinton Administration in 2017 could be fertile ground for executive actions seeking to accelerate progress in the industry. Offshore wind participants should begin organizing now to present transition materials and advocate for inclusion in first 100 days initiatives.

Topics: Renewable Energy, Offshore Wind, Wind Energy, DONG Energy, BOEM, New Jersey Offshore Wind, Maryland Offshore Wind, Massachusetts Offshore Wind, New York Offshore Wind

Confluence of Emissions Regulations Favor Renewable Energy Investment (Part 2)

Posted by Van Hilderbrand on 5/24/16 12:01 PM

In yesterday’s Part 1, we discussed the Environmental Protection Agency’s (EPA) rules regulating emissions from existing and new stationary electricity generating units. In today’s post, we discuss EPA’s regulations regarding emissions of mercury and air toxics, and emissions of methane and other volatile organic compounds.

Mercury and Air Toxics Standards

MATs_Rule.jpgOn February 16, 2012, EPA published its Final Rule regarding air toxics standards for coal‐ and oil‐fired electricity generating units, also known as the Mercury Air Toxics Standards or “MATS” rule. The MATS rule regulates power plant emissions of mercury and other hazardous air pollutants. 

Industry and state petitioners challenged the MATS rule asking the court to determine whether EPA erred when it concluded that the appropriate and necessary finding under Clean Air Act Section 112 could be made without consideration of cost.

  • On June 29, 2015, in Michigan v. EPA, 135 S. Ct. 2699 (2015), the Supreme Court ruled 5-4 that EPA had erred when the agency concluded that cost did not need to be considered in the appropriate and necessary finding supporting MATS. Despite the ruling, the MATS rule has remained in place while EPA considered the cost question.
  • On December 1, 2015, in response to the Supreme Court’s direction, EPA published a proposed supplemental finding that a consideration of cost does not alter its previous determination that it is appropriate and necessary to regulate air toxic emissions from coal‐ and oil‐fired electricity generating units. EPA solicited public comment on the proposal.
  • On April 25, EPA issued a Supplemental Finding that it is Appropriate and Necessary to Regulate Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units, 81 Fed. Reg. 24,420, and affirmed that the MATS rule was appropriate and necessary to regulate air toxics after including a consideration of costs.
  • On the same day, April 25, Murray Energy Corporation filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit asking the court to review the supplemental finding. Murray Energy v. EPA, C.A. No. 16-1127. The window to file petitions for review is open until June 24, so other parties most likely will file challenges and the cases will be consolidated into a single action.

The Supreme Court is also considering a petition from a coalition of 20 states, led by Michigan, that argues the MATS rule should have been vacated entirely and that the lower appeals court’s decision to keep it in place while the agency addressed legal flaws was itself illegal. Michigan v. EPA, C.A. No. 15-1152.  In briefs filed earlier this month, the U.S. Department of Justice argued that, amongst other arguments, the state coalition has no standing and can not show any injury resulting from the 2015 decision because the MATS rule imposes obligations on the power sector, not the states.  

Finally, another litigation, ARIPPA v. EPA, C.A. No. 15-1180, which was put on hold while EPA reconsidered the cost issue, was moved back to the active docket on May 11 by the U.S. Court of Appeals for the District of Columbia Circuit.  Petitioners, Utility Air Regulatory Group, and ARIPPA, are challenging EPA’s previous decision to deny administrative reconsideration requests on the MATS rule.

Future posts on the Energy Finance Report will provide updates as to the status of the MATS rule, so please check back.

Methane Emission Standards for New, Reconstructed, and Modified Sources

Methane_Rule.jpgAccording to EPA, methane has a global warming potential more than 25 times greater than carbon dioxide. Thus, while the power sector is reducing its carbon dioxide emissions by shifting from coal to natural gas generation, EPA felt is necessary to limit the impact of emissions of methane and other ozone-causing volatile organic compounds from shale gas production.

EPA published its final rule, Emission Standards for New, Reconstructed, and Modified Sources, limiting emissions of methane and other ozone-causing volatile organic compounds (VOCs) from new and modified oil and gas infrastructure on May 12. Under the President’s Climate Action Plan: Strategy to Reduce Methane Emissions and the Clean Air Act, EPA also finalized rules clarifying air permitting rules as they apply to the oil and natural gas industry, and a rule that will limit emissions while streamlining the permitting process for the oil and natural gas production industry in Indian country. According to the agency, these rules will reduce methane emissions up to 45 percent from 2012 levels by 2025.

In general, the Emissions Standards rule updates the New Source Performance Standards associated with methane and other VOCs and requires oil and gas companies to prevent leaks, capture methane from hydraulic fractured wells, and limit emissions from various types of oil and gas extraction and transmission equipment, including pumps, compressors, and pneumatic controllers. Challenges to the final rule are expected to be filed by industry associations, states, and other stakeholders who have argued that the new requirements are costly and unnecessary.

EPA also released a proposed information collection request seeking a broad range of information on the oil and gas industry. This request is a precursor to the agency’s evaluation of potential regulatory requirements for methane emissions from existing oil and gas sources and, similar to the Clean Power Plan, could be the beginning of a much larger legal battle. 

Future posts on the Energy Finance Report will provide updates as to the status of the methane regulations, so please check back.

Conclusion

With the time left in office for the Obama Administration, EPA is moving toward finalizing additional climate change and air pollution rules that reduce emissions from power plants, refineries, and the transportation sector. Operating, maintenance, and financing costs will undoubtedly increase for the oil and natural gas industries as companies come into compliance with these new emissions-reductions rules and regulations.  There is a significant opportunity for zero-emission sources such as wind, hydro, and solar to step in and fill the gap left when the utility energy sector retires existing fossil-fuel sources and begins planning for future energy needs.

Topics: Renewable Energy, Mercury Air Toxics Standards, Methane Emissions Standards

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