Energy Finance Report

Administrator

Our energy practice is focused on helping investors and companies navigate the dynamic and changing energy marketplace. We work as partners with our clients, providing world class legal support through the lens of our deep understanding of energy finance and the unprecedented change underway in the energy industry to bring real solutions and real value to their investments and businesses. We focus on adding value by developing more efficient investment and transaction process and by collaborating on the legal and financial innovations that will provide our clients the competitive advantage necessary to win in today’s energy market. We also use our extensive networks in the energy and financial industries to help our partners realize new opportunities.

Recent Posts

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

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: Energy Storage, Renewable Energy, FERC, hydropower

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

Advanced Approaches to Stormwater Runoff Management Through Green Infrastructure

Posted by Administrator on 8/4/17 11:24 AM

Green infrastructure refers to, among other things, the utilization of sustainable forestry and agriculture as elements of a cost-effective compliance strategy for meeting the National Pollutant Discharge Elimination System (“NPDES”) permitting requirements, as authorized by the Clean Air Act (“CWA”), and its state counterparts. Natural systems and processes such as constructed wetlands and phytoremediation have long been used as tools for meeting NPDES discharge standards; however, the advent of the Environmental Protection Agency’s (“EPA’s”) more rigorous “Phase II” stormwater management requirements has spurred renewed interest in such systems among a new and more expansive set of permittees.

Stormwater discharges first became subject to NPDES permitting requirements as a result of the 1987 amendments to the CWA. “Phase I” of the program began in 1990, and applied only to large and medium municipal separate storm sewer systems and 11 industrial categories, including construction sites disturbing five acres of land or more.  In March 2003, Phase II of the program began, applying to a much broader set of municipal sewers and construction sites including those disturbing as little as one acre of land.  Phase II also expanded certain exemptions that were originally available under Phase I.

EPA has authorized the NPDES stormwater program to 46 states, with EPA largely relegated to an oversight capacity. Because states with delegated programs may impose stormwater management requirements more stringent than those promulgated by EPA, a number of states, led by California, have established Phase II requirements significantly more rigorous than EPA’s rules. 

For example, California requires Phase II stormwater permits for wide-ranging categories of facilities that meet certain broad criteria, including industrial facilities that fall within almost every conceivable Standard Industrial Classification (“SIC”) code. Requirements typically include the preparation of a Storm Water Pollution Prevention Plan, the implementation of best management practices (including technology-driven environmental cleanup obligations), and training, sampling and reporting obligations.

Most states have elected to impose the Phase II requirements through issuance of general permits that apply to categories of facilities rather than to specific facilities and employ benchmark compliance targets rather than definitive cleanup standards. However, it appears that a number of states have begun moving toward the establishment of specific numeric action levels governing the extent of response measures required in the event of permit exceedances, and some have even begun to incorporate Total Maximum Daily Loads (“TMDLs”) into their permit obligations.  

A decision to include green infrastructure as part of a stormwater discharge compliance program should not be made without first conferring with regulators and conducting a preliminary desktop evaluation to determine whether the permitted facility is well-suited for such an approach. If the answer is in the affirmative, the next step is to prepare a working document identifying the essential project scope and associated deliverables.  This should include, as determined necessary, the performance of an initial pilot study to establish proof of concept and the conduct of a “pre-design” study to evaluate the range of costs and feasibility of the project.

Subject to the outcome of the initial pilot study and the pre-design study, the next step is the preparation of a “pre-development agreement” setting forth in more detail the project work scope and cost projections, including calculations that would allow the project sponsor to quantify the likely avoided operating and/or regulatory costs resulting from incorporating green infrastructure components into the project. Upon completion of the work scope and cost projections, a legally-binding “master development agreement” should be negotiated among interested parties, addressing the financing, design, construction, and operation and maintenance requirements of the proposed project.

At critical junctures during the preparation of the various project documents referenced above, the project sponsor will need to consult with counsel if only for the limited purposes of performing the legal aspects of any necessary project due diligence and regulatory analysis. Finally, it is prudent to involve counsel in any negotiations with relevant government agencies and other stakeholders leading up to the preparation of a binding legal document, particularly in light of the fact that the project will almost certainly diverge from the standard regulatory approaches employed by the regulators.

There are several states currently using green infrastructure as the means to comply with stormwater discharge requirements. For example, pilot projects in the Anacostia River Watershed in Maryland have utilized infiltration and bio-retention best management practices to manage urban runoff.  In Seattle, Washington, streets have been redesigned to include more trees and shrubs, reflecting natural draining patterns.  In Portland, Oregon, stormwater curb extensions were added to residential streets, allowing stormwater to flow into the bioswales to be filtered.  Lastly, Chicago, Illinois has been using several low impact development practices, such as rain gardens, wetland rehabilitation, permeable alleys, and rooftop gardens.

Topics: Green Infrastructure, Stormwater Runoff Management, National Pollutant Discharge Elimination System, Clean Water Act

Considerations for Participants in the Expanding Market for Compensatory Mitigation Credits

Posted by Administrator on 8/1/17 12:36 PM

In a recent blog post, we described the basic statutory and regulatory framework supporting the increasing popularity of mitigation banking.  In this update, we offer some additional observations for property owners and other sponsors who may wish to develop a mitigation bank, and identify some of the risks associated with that undertaking.

As described in our previous post, a mitigation bank is a wetland, stream or other aquatic or habitat resource area that has been restored, established, enhanced (or in certain circumstances) preserved for the purpose of providing compensation for unavoidable impacts to aquatic resources resulting from development.  The person or entity that establishes a mitigation bank and undertakes the restoration activities is sometimes referred to as a “mitigation banker” or “bank sponsor.”  Bank sponsors can generate “compensatory mitigation credits,” which can be sold to developers whose permits under Section 404 of the Clean Water Act (and similar federal and state regulatory authorities) impose mitigation obligations.  We have outlined below the basic steps that a sponsor seeking to establish a mitigation bank would need to follow to generate marketable credits. 

The first step in the process of establishing a mitigation bank is to identify and, if necessary, purchase a suitable project site.  Candidate properties should be limited to those that offer the greatest likelihood that they can be restored or enhanced at a cost that corresponds favorably with the likely value of the credits to be generated.  Factors relevant in assessing the ecological suitability of a potential project site include the soil characteristics of the site, landscape features of the surrounding watershed or habitat area, and reasonably foreseeable effects the project might have on the surrounding ecosystems.

In addition, because regulatory obligations generally require that the mitigation occur within the same watershed or habitat area in which the ecological damage occurred, a prospective sponsor should also consider the amount and nature of development taking place and expected to take place within the subject watershed or habitat area.  This assessment can assist the sponsor in selecting the optimal project site and restoration plan.

Once the sponsor decides to move forward with a restoration project at a particular location, a prospectus and mitigation plan must be submitted to a regulatory body known as the “Interagency Review Team” (“IRT”); this is a group of federal, tribal, state, and local regulatory and resource agency representatives who historically have been headed by the local district engineer for the Army Corps of Engineers.  These initial submissions serve to document the key aspects of the proposed project, and also provide the primary source of information for the public during the public comment period (which begins within 30 days of the IRT’s receipt of the prospectus and continues for an additional 30 days).

The prospectus should provide a summary of information concerning the proposed bank, as well as more specific information pertaining to its establishment and operation, long-term management strategies, and the bank’s proposed service area.  The prospectus should also address the technical feasibility of the restoration project.

The mitigation plan must provide a description of the nature of the project to be undertaken (i.e., restoration, establishment, enhancement, or preservation), documentation of the needs of the local watershed or habitat area, and a description of the factors considered during the site selection process.  The mitigation plan should also identify the number of compensatory mitigation credits to be issued by the bank upon completion of the project.

Following regulatory review of the prospectus, a draft banking instrument must be prepared that conforms with the terms of the prospectus.  It should describe the physical and legal characteristics of the mitigation bank as well as the protocols pursuant to which the bank will be established and operated.  In addition, the banking instrument identifies the number of credits to be issued in connection with the mitigation bank, provides a description of the protocols governing management of the bank, and includes a long-term operation and maintenance plan for the site.

The draft banking instrument is subject to review by the appropriate regulatory authorities (depending on whether the project is a watershed or habitat restoration).  The review process typically includes some evaluation of the economic viability of the proposed project.  Upon completion of the review process, the draft banking instrument is subject to a 30-day comment period, following which the sponsor may be required to make additional revisions to the document.  

Once the sponsor has addressed any remaining concerns regarding the terms of the draft banking instrument, it may submit the final version of the instrument, together with supporting documentation detailing any changes from the draft, to the regulatory authorities for approval.  Only after this documentation has been submitted and approved may the sponsor begin selling credits into the mitigation banking market.

Although the potential financial and ecological benefits of establishing a mitigation bank are well-documented, there is some uncertainty associated with the endeavor.  Like any major construction project, there is always the risk of substantial cost overruns due to delays in the regulatory review process or other unforeseen circumstances.  There can also be uncertainty resulting from variability over time in the market value of the compensatory mitigation credits to be generated. 

Some of the risks inherent in restoration projects can be addressed through a thoughtful and comprehensive due diligence effort at the outset.  For example, because the existence of conflicting property rights (for example, preexisting easements) can pose an obstacle to the timely and cost-effective completion of a restoration project, a thorough title search should be performed during the early stages of the project.  In addition, because of the variability in the value of the compensatory mitigation credits to be generated by the project, early consideration of possible hedging strategies might be prudent.

Topics: Compensatory Mitigation, Mitigation Banking, Compensatory Mitigation Credits

Water Infrastructure: The Current State of Funding and Considerations for Private Investors

Posted by Administrator on 7/6/17 11:00 AM

Almost a decade ago, EPA estimated the needed investment in our domestic water and wastewater infrastructure at approximately $105 billion; today it is estimated at over $600 billion. There is no indication thus far that the new administration is committed to reversing the rapid decay of our water infrastructure, or addressing the massive backlog of needed improvements.

In the face of diminishing government resources, water utilities over the past decade or so have aggressively moved to develop independent revenue streams to shore up their bottom lines. Most successful among these efforts have been the investments by wastewater facilities in new technologies which use sewage sludge bio-solids as a feedstock for the generation of electricity. This development is particularly noteworthy in light of the fact that the water utility sector is among the highest consumers of electricity, accounting for approximately 4% of energy use in the U.S. and as high as 20% in some states, such as California.

Although new technologies hold substantial potential benefits for water utilities both in terms of financial returns and in achieving sustainability goals, they increasingly cannot be undertaken without an initial infusion of private investment. However, this need for private capital has run headlong into long-standing negative public perceptions regarding the “privatization” of water assets. This dynamic became abundantly apparent when the new administration recently floated the idea of selling the Washington Aqueduct as a means of funding other infrastructure projects.

With the new administration’s infrastructure initiative likely to focus on transportation, water utilities almost certainly will confront continuing funding shortfalls as they encounter increasing regulatory compliance and operational challenges. In the face of this enormous and growing demand for capital, why haven’t private investors been willing to move beyond their historical antipathy toward the public water sector and provide the funding necessary to keep it afloat? As one might imagine, the answer to that question is multi-faceted.

Investments in the water sector, no matter how much they might be in demand, historically have not offered the types of returns that are routinely generated by other types of “cleantech” investments. The cumbersome and disparate structure of the water sector, with its multitude of small, municipally-owned systems, is ill-equipped to efficiently and effectively employ large infusions of new capital and to generate returns commensurate with that investment. For those private financiers who are up to the challenge of investing in the water infrastructure sector, we have offered below some considerations that you should enter into your calculus.

Typically the initial step in formulating a water infrastructure investment strategy is to establish a list of potential target jurisdictions, presumably limited to states and cities with legal, political, and economic frameworks favorable to private investment in infrastructure. For example, before deciding to include any particular municipality on your list, take a look at the 30 or so states that have enacted legislation to authorize or facilitate public-private partnerships. You should also look at the history of privatization efforts in your target jurisdictions, including the degree of support for such efforts from local political leaders, water facility managers, labor unions, citizens groups and the general public.

The candidate list can then be winnowed down to conform to the investment strategy that you have adopted. For example, your business model might include a standardized project type such as a 10-200 million gallons per day wastewater treatment plant upgrade with biogas-driven combined heat and power at a defined equity investment range such as $20-100M. Within those constraints, priority locations can then be assessed and selected.

Following the selection of an initial target, the investment team can then begin the process of developing a specific plan to further define the elements of the project and identify the preferred technology and financing model. As part of this process, the development team should also find and reach out to potential stakeholders, such as local governmental representatives and community groups, to seek their input on the conceptual framework for the transaction.

Emerging from this process should be a conceptual plan that addresses the threshold ownership and structural issues (e.g. concession agreements v. equity interests). It may also include a pre-negotiated contractual and financing model to support the project.

Finally, upon completion of the conceptual plan, it is customary to initiate a local political and public education campaign to publicize the benefits of the project and to hopefully generate broad-based community support for the project in advance of any necessary governmental approvals. If the hoped-for support does not come to fruition, most prudent investors will reassess and perhaps re-focus their efforts on another municipality.

Topics: Private Investment, Water Sector, Water Infrastructure, Wastewater Infrastructure, Water Utilities

Biofuel Mandates Escape Current EPA Scrutiny

Posted by Administrator on 6/21/17 2:16 PM

The Renewable Fuel Standard (RFS) is a regulatory program administered by EPA that requires petroleum-based transportation fuel sold in the U.S. to contain a minimum volume of various categories of biofuels. The program’s mandates are subject to a statutory waiver provision that may be exercised by EPA in the event that market conditions present an obstacle to meeting the minimum volumes. With the new administration’s continuing scrutiny of EPA’s numerous regulatory programs, there has been a great deal of uncertainty regarding the likely fate of the RFS Program.

Under the RFS program, biofuel must be blended into transportation fuel in increasing amounts each year, capping out at 36 billion gallons by 2022. Compliance with the blending obligations are imposed on petroleum importers and refiners, known as “obligated parties.” The annual amounts of the various categories of biofuels that must be blended are referred to as Renewable Volume Obligations (RVOs). Obligated parties can comply with the RFS program by either blending the requisite volume of renewable fuel into their transportation fuel or purchasing credits designated as Renewable Identification Numbers (RINs) to meet the RVO.

Although the Clean Air Act sets forth annual volumetric targets for certain biofuels, EPA is required to establish enforceable RVOs through a formal rule-making process. Separate quotas and blending requirements are determined for cellulosic biofuels, biomass-based diesel, advanced biofuels, and total renewable fuels. Refiners and importers must either blend the requisite amount of each of the four categories of biofuels, or acquire the necessary amount of RINs for each of the categories. Parties that purchase or sell RINs are required to enter the transaction information into the EPA Moderated Transaction System.

Initial uncertainty over the fate of the program began in 2015, when EPA exercised its statutory waiver authority for the first time and set an RVO lower than the benchmarks established by Congress. Litigation ensued, and many in the biofuel industry argued that EPA had abused its waiver authority by setting an RVO lower than the statutory minimums. As of the current date, the litigation remains unresolved.

In November of 2016, EPA set an RVO of 19.28 billion gallons of total biofuel for 2017; this was an increase from the 18.11 billion gallon figure adopted for 2016, but still below the statutory standard of 24 billion gallons. However, renewed uncertainty arose in January of 2017, when President Trump ordered a temporary freeze and review of thirty EPA regulations that had been issued between the time of the U.S. election and his inauguration, including the 2017-18 RVOs.  

To the industry’s relief, the regulatory freeze expired without the new administration making changes to the 2017-18 RVOs, and immediately thereafter RIN prices spiked for a period of time. However, overall RIN prices have dropped 19 percent since President Trump’s election, reflecting continued uncertainty about the future of the program.

Though the new administration did not revise the current RVOs, it is entertaining a policy initiative by Carl Icahn (an investor in the petroleum sector who also serves as a special adviser to President Trump) to shift responsibility for meeting RVO requirements away from refiners and importers to blenders and others in the chain of commerce. A ruling by EPA on the Icahn initiative may be several months away. The public comment period on the Icahn-backed measure ended February 22.

Despite uncertainties regarding the future of biofuel mandates in the U.S. and elsewhere, advancements within the industry continue to occur. The liquid biofuels industry now employs more than 1.7 million people globally, and recent technological developments have expanded the range of biofuel applications.

It has been reported that Cool Planet Energy Systems developed a technology that converts farm waste, wood chips, and nut shells into liquid jet fuel. The company has secured investments from three major oil companies, in addition to a $91 million grant from the Department of Agriculture, and is continuing to refine its process with the hopes that it will become a viable supplement or replacement for traditional jet fuel.

The U.S. Navy has also taken an active interest for a number of years in utilizing greater quantities of biofuel in order to reduce its dependency on fossil fuels. During the Obama Administration, the Navy conducted several training exercises in which a large number of the ships and planes participated using a fuel blend that was 10% biofuel. Those efforts appear to be continuing.

More significantly, on June 19, Exxon Mobil Corp. and Synthetic Genomics Inc. announced a possible breakthrough in biofuel technologies. Their scientists reportedly discovered a way to double the fatty lipids in algae, bringing them a step closer to being able to use algae as a biofuel feedstock, a potentially more sustainable alternative to the feedstocks currently utilized.

Topics: Biofuels, Renewable Fuel Standard, Cellulosic biofuel, Biomass-based diesel, Renewable Volume Obligation, Advanced biofuel, Renewable Fuel, Renewable Identification Number

Monetizing Vacant Land Through Mitigation Banking

Posted by Administrator on 6/13/17 3:14 PM

A mitigation bank is a wetland, stream, or other habitat area that has been restored, established, enhanced, or (in certain circumstances) preserved for the purpose of providing compensation for unavoidable impacts to such natural resources. When a corporation or other entity undertakes these activities, it can generate “compensatory mitigation credits” (“CMCs”), which in recent years have significantly increased in value. Corporations and other owners of brownfield or dormant/underutilized properties are increasingly using these lands to create mitigation banks in order to generate CMCs that can be sold into the mitigation market.

Mitigation banking originated under Section 404 of the Clean Water Act and similar state statutes intended to protect wetlands and streams. Developers of projects which involve the discharge of dredged or fill materials into wetlands, streams, or other waters of the United States are required to obtain a permit from the U.S. Army Corps of Engineers (Corps) or an approved state, and must avoid and minimize negative environmental impacts to the extent feasible. When negative impacts are unavoidable, compensatory mitigation is required to offset the impacts on aquatic resources. The Corps or an approved state authority determines the necessary quantity and method of compensatory mitigation, which can be performed by the permittee, a third party under contract to the permittee, or through the purchase of CMCs from a mitigation bank.

Mitigation banking is completed off-site, meaning it is performed within the same watershed as the site of the impacts but not at the same location. Banks are regulated by Interagency Review Teams (IRTs), which are chaired by the district engineer or a designated representative and include federal, tribal, state, and/or resource agency representatives. The person or entity that establishes a mitigation bank and undertakes the restoration activities is sometimes referred to as a “mitigation banker” or “bank sponsor.”

In order to generate CMCs, the mitigation banker must first negotiate a written agreement with the IRT that provides for the long-term funding and management of the bank, as well as the design, construction, monitoring, ecological success, and long-term protection of the bank site. The agreement also identifies the number of credits available for sale and requires the use of ecological assessment techniques to certify that those credits provide the required ecological functions. See EPA Mitigation Banking Factsheet.

Federal policy favors the use of mitigation banks and CMCs to offset the negative environmental impacts of development for a number of reasons. Since mitigation banking is performed prior to development, there is less uncertainty about whether environmental impacts will be effectively offset. In addition, mitigation banking allows for the use of scientific expertise and financial resources that are not always available when mitigation is performed directly by the developer. Mitigation banking also tends to be more cost-effective and to allow for shorter permit processing times.

In 2008, the Corps and EPA adopted regulations that made mitigation banking the preferred method for both wetland restoration and compensation for wetland losses. Due to the success of mitigation banking, the concept was expanded to offset losses of endangered species and associated habitat; known as “conservation banks,” they are under the jurisdiction of the U.S. Fish and Wildlife Service and the National Marine Fisheries Service. Today, there are more than 1,200 mitigation banks in the U.S., and the market value of all CMCs exceeds $100 billion.

Topics: Compensatory Mitigation, Mitigation Banking, Compensatory Mitigation Credits, Wetlands

Converting Environmental Liabilities to Assets: Repurposing Inactive and Abandoned Mine and Mineral Processing Sites

Posted by Administrator on 6/6/17 2:36 PM

Under the Brownfields Law of 2002, EPA and other federal agencies have established a variety of programs focused on promoting and funding the repurposing of abandoned mine lands (AMLs), broadly defined as lands, waters, and watersheds in close proximity to where extraction, beneficiation, or processing of ores and minerals has occurred. Among the most promising of these initiatives is EPA’s Re-Powering America Program, pursuant to which EPA has prioritized the development of renewable energy projects on brownfield properties such as AMLs.  

The Department of Energy’s National Renewable Energy Laboratory (NREL) has significantly contributed to the success of the Re-Powering America Program. As part of its initial characterization of sites on EPA’s brownfields inventory, NREL collects data sufficient to determine the renewable energy potential of each site. To date, NREL has screened over 80,000 sites for their development potential as solar, wind, biomass, and geothermal facilities.

Hard-rock mine sites, in particular, offer a number of distinct opportunities for renewable energy development. For example, they tend to be large in size, and thus can provide sufficient capacity for the installation of a large-scale wind farm or solar array in one location and are often near existing infrastructure, including roads and utilities. In addition, hard-rock mine sites can serve as excellent locations for wind farms because they are often situated in mountainous areas that receive consistent wind flow. 

Development of inactive coal properties can be more challenging, due in part to the remediation and procedural requirements of the Surface Mining Control and Reclamation Act. However, the Act also offers a potential funding source for site redevelopment under its AML Reclamation Fund, a benefit not available with respect to the hard-rock mine sites.

In addition to the foregoing, there is an array of emerging technologies that can enable value extraction and new reclamation approaches based on engineered natural systems or “green infrastructure.” For example, energy recovery from wastewater at mine sites can be a cost-effective option due to the often remote locations of such sites. In addition, residuals from wastewater treatment can be used as a soil amendment to add organic matter and nutrients to the soil to create a fertile soil profile with a reestablished microbial community, invertebrates, and plants. This approach can be used to help meet Clean Water Act stormwater discharge requirements as well as regulatory limitations on direct discharge to surface waters.

The use of green infrastructure can create a revenue generating ecosystem that will help offset the cost of mine remediation. At mine sites with substantial vacant land, sustainable forestry can be used to help manage stormwater as well as generate carbon credits recognized to varying degrees under both the California and Regional Greenhouse Gas Initiative frameworks. Furthermore, engineered wetlands can help address acid mine drainage and other contaminated flows from abandoned mines and potentially serve as a secondary revenue source through the generation of water quality trading credits under the Clean Water Act.

Historically, a significant obstacle to the redevelopment of AML has been the lack of funding available to characterize and remediate these sites. This gap in funding can be reduced by incorporating renewable energy and/or green infrastructure into the mine remediation plan. The installation of a solar array during or following mine reclamation can provide an energy source to power the remediation effort or create a revenue stream to offset the cost of remediation. A similar approach can be utilized through the use of green infrastructure.

In its proposed 2018 budget, the Trump administration has requested $28.0 billion for the Department of Energy “to make key investments to support its missions in nuclear security, basic scientific research, energy innovation and security, and environmental cleanup." Of this total, $6.5 billion is designated specifically for environmental management to address “high-risk contamination facilities that are not in the current project inventory.” However, within this proposed budget, the EPA would receive $5.655 billion in funding, a 30% decrease from the enacted 2017 budget. This reduction in EPA funding may have adverse effects on the Re-Powering America program.

Topics: Environmental Liabilities, Renewable Energy Development, Green Infrastructure, Abandoned Mine Land, Repurposing Mine Land

The Brownfield Gold Rush: Municipalities Give Contaminated Properties New Life- Published by Cleantechnica

Posted by Administrator on 7/26/16 10:05 AM

Solar_Brownfield.jpgInnovative local government leaders throughout the country are taking advantage of state and federal incentives to transform former landfills and contaminated industrial properties and waste sites into energy-producing wind and solar projects. Two examples of municipalities giving such contaminated properties new life are discussed in this article – redeveloping once polluted properties into solar installations in New Bedford, Massachusetts and revitalizing a former Bethlehem Steel plant into renewable energy projects in Lackawanna, New York.

In a recent article published by CleantechnicaJeffrey Karp, Jerry Muys, and Van Hilderbrand demonstrate how corporate property owners can revitalize brownfields into a useful asset and revenue generator.

Topics: Solar Energy, solar brownfield, contaminated property, brownfield

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