Laos dam construction and collapse

A dam under construction in Laos as part of a hydropower scheme has collapsed, causing flooding and damage.

At issue is the Xe-Pian Xe-Namnoy project, a 410-megawatt hydroelectric power project under development for Xe-Pian Xe-Namnoy Power Company (PNPC). PNPC is a joint venture among the government of Laos and construction and power companies from South Korea and Thailand. The project, whose construction costs are estimated at about $1 billion, involves the construction of three primary dams to form reservoirs. Construction of the system was reportedly 90% complete, with commercial operation projected for 2019, and an agreement in place agreement to export 90% of project power to Thailand. The project has been touted for the degree of international investment involved, although some have criticized the project for insufficient local benefits.

From an engineering perspective, the project's primary dams impound water in a large reservoir. The project also includes three auxiliary "saddle dams" near several heads of the reservoir, essentially to prevent the reservoir from spilling down the impoundment's back side as it fills.

A map of the project, found at http://www.pnpclaos.com/index.php/en/project/maps

Project maps posted online by PNPC show saddle dams on three of the main reservoir's western branches.

Another project map found at http://www.pnpclaos.com/index.php/en/project/maps

One of these smaller saddle dams reportedly failed on July 23, 2018, allegedly due to severe rains. Saddle Dam D -- a facility 8 meters wide, 770 meters long and 16 meters high -- was built to support water diversion around the project's reservoir. But the structure reportedly fractured, causing water to spill downstream to the Xe Pian river outside of the project's intended path of water flow. According to the prime minister of Laos, at least 26 people have died and 131 are missing from the resulting flooding, and several villages .

Response and recovery actions are ongoing. The dam collapse highlights the importance of safety in dam construction and reservoir operations, as did the February 2017 failure of the Oroville Dam's spillway in California.

Report on US electric grid physical security

Since a 2013 rifle attack on a critical electric power substation in California, the U.S. electric power sector has generally moved toward greater physical security for critical assets, according to a report published by the Congressional Research Service. But the report says bulk power security "remains a work in progress," and suggests further investment -- and policy reforms -- may follow.

The report published on March 19, 2018 -- NERC Standards for Bulk Power Physical Security: Is the Grid More Secure? -- begins with the premise that securing the electric power grid is among the nation's highest priorities for critical infrastructure protection. It notes that a 2013 rifle attack on an electric transmission substation in California which caused widespread power outages also broadened policy attention from cybersecurity to encompass the physical security of assets critical to the power grid.

In response, Congress enacted legislation to strengthen power grid physical security and to facilitate its recovery from disruption. Section 1104 of the Fixing America’s Surface Transportation (FAST) Act contains provisions to protect or restore the reliability of critical electric infrastructure or defense of critical electric infrastructure during a grid security emergency. The Federal Energy Regulatory Commission (FERC) and the nation's electric reliability organization NERC also took action to develop new reliability standards for the physical security of bulk power critical infrastructure.

But physical security risks may persist. The report references a September 2016 rifle attack on a Garkane Energy Cooperative transformer substation in Utah as illustrating this persistence. The report notes that while it is probably accurate to conclude that the grid is more physically secure than it was in 2013, "it has not necessarily reached the level of physical security needed based on the sector's own assessments of risk.

The report notes Congress's continued concern about the physical security of the electric grid. It identifies possible areas for further policy focus as including "security implementation oversight, cost recovery, hardening vs. resilience, and the quality of threat information."

Meanwhile, cybersecurity has remained a priority. An October 2017 FERC report describing the results of its audits of regulated companies' cybersecurity protection processes and procedures noted that most met the applicable mandatory standards. But earlier this month, NERC fined an anonymous utility $2.7 million for alleged violations of reliability standards in connection with a data security breach, and the U.S. Department of Homeland Security issued warnings about Russian hackers targeting computer systems controlling energy and other critical infrastructure.

Interest in shoring up the security of energy infrastructure and systems -- both from physical attacks as well as cyber threats -- appears poised to drive continued discussions, regulation, and investment.

FERC hydro dam safety post-Oroville

As federal hydropower regulators examine how a California dam's spillway failed, an independent forensic team has released its final report on the Oroville Dam spillway incident -- and regulators have asked all other hydropower licensees to review the report and hold internal discussions on how the findings may apply to their own facilities and overall dam safety program.

Oroville Dam is a 770-foot high earthfill embankment dam on the Feather River in Northern California. Its service spillway was severely damaged during operations on February 7, 2017; water levels continued to rise, eventually overtopping and eroding the emergency spillway, threatening the stability of the structure on February 12, 2017.  Over 180,000 people were evacuated.

Following the incident, an independent forensic team studied the incident. The independent forensic team's report was released on January 5, 2018. It found that the incident "was caused by a long-term systemic failure of the California Department of Water Resources (DWR), regulatory, and general industry practices to recognize and address inherent spillway design and construction weaknesses, poor bedrock quality, and deteriorated service spillway chute conditions."

On January 26, 2018, the Commission published a letter to licensees presenting the Oroville Dam Independent Forensic Team's final report. In that letter, the Commission asked licensees and their Chief Dam Safety Engineers/Coordinators to "read this report, share it with your senior executives as well as all your dam safety staff and discuss how the findings may apply to your own facilities and overall dam safety program.

According to the Commission, that report concludes that flaws in the Oroville Dam Spillway existed since construction that were missed by the owner, regulators, and consultants. In the Commission's words, "It is very clear that just because a project has operated successfully for a long period of time does not guarantee that it will continue to do so." Emphasizing a safety-oriented corporate culture, the Commission also highlighted the report's finding that "compliance with regulatory requirements is not sufficient to manage risk and meet dam owners' legal and ethical responsibilities." The Commission's letter to hydropower licensees and exemptees highlights the importance of communication between dam safety staff and senior executives as part of an Owner's Dam Safety Program, and stated its expectation that regulated dam owners will have internal discussions to ensure facility safety.

California considers transportation electrification

California utility regulators are considering proposals by electric utilities to electrify the transportation sector.  If the three largest electrical corporations' proposals are approved by the California Public Utilities Commission, it could represent an investment of about $1 billion in transportation electrification in California over about 5 years.

The transportation sector is a major consumer of energy and emitter of carbon dioxide.  In California, the transportation sector accounts for 37 percent of statewide greenhouse gas emissions.  Electrifying transportation -- converting vehicles and trips from direct consumption of fossil fuels to EVs or electric vehicles -- can reduce emissions, particularly where the electricity supply is sourced from renewable or low-carbon resources.

To address energy and climate matters, in 2015 the California legislature enacted Senate Bill 350, the Clean Energy and Pollution Reduction Act.  SB 350 codified Governor Edmund G. Brown Jr.'s clean energy and climate change goals, establishing a statewide 2030 greenhouse gas reduction target of 40 percent below 1990 level.  SB 350 calls for pursuing those goals through a variety of measures, including the promotion of "widespread transportation electrification," defined as "the use of electricity from external sources of electrical power, including the electrical grid, for all or part of vehicles, vessels, trains, boats, or other equipment that are mobile sources of air pollution and greenhouse gases and the related programs and charging and propulsion infrastructure investments to enable and encourage this use of electricity." 

The legislation requires the California Public Utilities Commission to direct electrical corporations to file applications for programs and investments to accelerate widespread transportation electrification.  That process is now underway.  On September 14, 2016, the Commission issued an order directing the state's three major investor-owned utilities to prepare and file applications describing their proposed transportation electrification projects and programs.

On January 20, 2017, the three utilities -- Pacific Gas and Electric Company (PG&E), SouthernCalifornia Edison (SCE), and San Diego Gas & Electric (SDG&E) -- filed their applications.  As summarized by the Commission, PG&E, SCE, and SDG&E submitted proposals to invest $1 billion in transportation electrification over an approximate five year period.  Onroad medium and heavy-duty charging infrastructure proposed by SCE accounts for roughly half of this total; residential charging infrastructure proposed by SDG&E and "FleetReady Make Ready Infrastructure" proposed by PG&E round out the largest-ticket items.  Other projects include electrification of cranes and forklifts at ports, terminal yards, and airports.

The cases remain pending before the Commission, with evidentiary hearings held earlier this month.  Other cases before the Commission address proposals by three smaller utilities.

California grid prepares for solar eclipse

As a total solar eclipse approaches for North America, California electricity regulators have launched a voluntary demand response program designed to reduce power consumption during the eclipse while solar panel output is reduced.

The eclipse will occur on August 21, 2017, and is projected to reduce solar photovoltaic production in the California ISO region by 4,194 megawatts.  Taking gross load increases and estimated wind production into account, CAISO has been told to expect a net load increase of 6,008 MW during the eclipse.

According to the nation's electric reliability organization, NERC, the August 21 eclipse "is not expected to impact the reliability of the bulk power system."  But as NERC also noted, "As the number of photovoltaic generators on the power system increases, the risk created by solar eclipses to reliable system operations will increase as well."

Now, the California Public Utilities Commission has launched a "Do Your Thing for the Sun" or "Cal Eclipse" program.  On its website, the Commission asks, "While our utilities and grid operator have all the tools necessary to manage the grid during the eclipse, what if millions of Californians stepped in to allow our hard working sun to take a break, rather than relying on expensive and inefficient natural gas peaking power plants?"

The website asks consumers to "Take the Pledge", emphasizing the value of "joining a movement of Californians who are taking action during the eclipse to give the sun a break by saving energy and reducing GHG emissions." According to a two-page FAQ posted on the website, consumers can reduce electricity consumption by turning off electronics when leaving, and permanently decrease electricity consumption with energy efficiency measures.  Actions suggested on the pledge website include replacing light bulbs with LEDs, reducing lighting use and electronics charging, unplugging unused appliances, and increasing air conditioning temperature setpoints by 2-5 degrees.

According to the Commission's FAQ, "There is no reason to anticipate any eclipse-related electric service outages because of the reduced solar generation."

Vail Resorts announces sustainability, net zero plan

Vail Resorts, Inc. -- the largest ski and mountain resort operator in the world -- has announced a comprehensive sustainability commitment that calls for "zero net emissions by 2030, zero waste to landfill by 2030 and zero net operating impact to forests and habitat."  According to the company, Vail Resorts' "Epic Promise for a Zero Footprint" will give resort guests and employees "the opportunity to enjoy the natural environment and resources without leaving an impact."
 
Vail Resorts' subsidiaries operate 11 mountain resorts and three urban ski areas, including Vail, Beaver Creek, Breckenridge and Keystone in Colorado; Park City in Utah; Heavenly, Northstar and Kirkwood in the Lake Tahoe area of California and Nevada; Whistler Blackcomb in British Columbia, Canada; Perisher in Australia; Stowe in Vermont; Wilmot Mountain in Wisconsin; Afton Alps in Minnesota and Mt. Brighton in Michigan. The company also owns and operates hotels as well as a real estate planning and development subsidiary.

In a July 25, 2017, press release, Vail Resorts announced its "Epic Promise for a Zero Footprint" sustainability commitment.  Pointing to Whistler Blackcomb's environmental commitment as inspiration, Vail Resorts announced its intent "to go beyond setting a partial emissions reduction target by executing on a more expansive and ambitious plan."

With respect to net zero emissions from operations by 2030, the Vail Resorts plan calls for continued reduction of the company's electricity and gas use by improving operating practices and investing $25 million in innovative, energy-saving projects, such as low-energy snowmaking equipment, green building design and construction, and more efficient grooming practices and equipment.  Among other measures, it envisions purchasing 100 percent renewable energy equivalent to Vail Resorts' total electrical energy use and working with utilities and local, regional and national governments to bring more renewable energy to the grids where the company operates its resorts. As an interim goal, the plan states the company's intent to achieve a 50 percent reduction in its net emissions by 2025, based on 2016 levels.

Other 2030 goals set in the Vail Resorts plan include "zero waste to landfill" (by diverting 100 percent of the waste from its operations to more sustainable pathways) and "zero net operating impact to forests and habitat" (by measures including mitigation, tree planting and forest restoration, and minimizing or eliminating the impact of any future resort development). 

NY energy storage bill would launch program

The New York legislature has unanimously passed a bill establishing an energy storage deployment program.  The bill, S. 5190, aims to promote the installation of energy storage systems.  The bill now awaits Governor Andrew Cuomo's signature, before it can take effect.

New York is in the midst of major shifts in its energy policy.  Governor Cuomo's "Reforming the Energy Vision" or REV process aims to build a clean, more resilient, and affordable energy system for all New Yorkers.  As part of that process, last year, the Public Service Commission adopted a Clean Energy Standard which requires 50% of New York’s electricity to be generated by renewable sources by 2030, and provides support for 3 nuclear power plants considered at risk of closing.  Meanwhile, the state is also reforming the way energy service companies, or retail electric suppliers, market their services.

In adopting renewable energy procurement mandates as part of the Clean Energy Standard in 2016, the Commission also considered creating specific mandates for energy storage.  As noted in the order adopting the Clean Energy Standard, "Storage is a critically important component of the energy system that is both distributed and increasingly reliant on intermittent resources. Unlike other resources, the load shifting and fast response capabilities of various forms of storage resources allow them to provide simultaneous value as an energy and reliability resource. Storage can also provide value to the distribution based retail and bulk power markets... In short, it is without question that modern markets must sufficiently and accurately value storage as a vehicle to design and optimize network planning and operations."

But in that order, the Commission concluded that "as a reliability support and system optimizing resource, storage is not properly characterized as a standalone renewable energy resource under the CES. That being said, if the various mechanisms that the Commission is pursuing to ensure storage takes it rightful place as a critical resource for the modern grid prove insufficient, this topic will be revisited."

S. 5190 would change New York's position, by requiring that the Commission establish 2030 targets for the installation of qualified energy storage systems.  It defines a qualified system as technology using mechanical, chemical, or thermal processes to absorb, store, and dispatch energy generated from renewable resources or mechanical processes.  The bill's official justification statement cites the increased use of intermittent renewable energy sources, such as solar and wind, in an effort to combat climate change, and the efficiency of using energy storage systems to solve issues relating to changes in how energy supply and demand align in time.

Three other states -- Massachusetts, California, and Oregon -- have adopted energy storage procurement policies, and the Federal Energy Regulatory Commission is exploring how electric storage resources can be integrated into wholesale and regulated markets.

Oroville Dam evacuation and relicensing

A California dam in the midst of a federal relicensing process has experienced flooding and storm-related damage, prompting the evacuation of over 180,000 people.  Evacuation orders and a reservoir drawdown represent the most rapid responses to the Oroville Dam incident -- but future discussions of engineering, dam safety, and public policy are likely to continue after the emergency has been resolved.

Oroville Dam is the tallest dam in the U.S.:  a 770-foot high earthfill embankment dam on the Feather River in northern California.  The dam was built from 1961-1968 by the California Department of Water Resources, as part of the State Water Project.  The resulting impoundment, Lake Oroville, can store over 3.5 million acre-feet of water, making it California's second largest man-made lake.

The Oroville project is subject to licensing by the Federal Energy Regulatory Commission under the Federal Power Act.  Its first license was issued on February 11, 1957, for a 50-year term which expired on January 31, 2007.  The Department of Water Resources filed an application for a new license for the project, which remains pending in Docket No. P-2100, although a settlement agreement was also filed.  In the meantime, the project continues to operate under a series of annual licenses issued by the Commission.  According to a DWR website, it "anticipates that FERC will issue a new license order in 2017 pending issuance of the aquatic biological opinion from the National Marine Fisheries Service."

According to state documents, California was hit by three major storms during January and February 2017, with major rain and runoff.  As Lake Oroville reached its full capacity, operators opened a spillway to allow excess water through the dam.  But on February 7, the spillway began to erode.  Four days later, operators opened the auxiliary emergency spillway, but eventually determined that this too was "in danger of failing."  Since a failure could cause widespread and severe flooding, officials called for evacuations downstream in the Feather River Valley.  On February 12, Governor Edmund G. Brown Jr. issued an emergency order strengthening the state's response.

Focus for now remains on safely resolving the risks that the Oroville Dam or its spillways might fail in a way that releases damaging waters.  The Commission could investigate what happened under its authority over the project through its existing license.  It could also raise issues relating to the incident in the context of the project's relicensing.  That case has been pending for roughly a decade, with a settlement agreement having been reached years ago.  But it is possible that the 2017 Oroville Dam incident could have consequences in the relicensing context, such as revised spillway designs or operating plans that could be reflected as conditions in a new license.

Substation security and the Garkane shooting

As the U.S. strengthens protections for its electricity grid, much of the discussion focuses on cybersecurity -- but physical security is also important, as shown by an attack on a Utah utility's substation.  On September 25, an unknown gunman fired at least 3 shots into a distribution system substation, damaging a transformer and causing power outages.  The incident may place renewed pressure on utilities to secure their infrastructure against vandalism and terrorism.

As reported by the Deseret News, the damage occurred at a substation owned by Garkane Energy Cooperative.  An assailant reportedly shot the main transformer's oil-cooled radiator system, causing the transformer to overheat and fail.  About 13,000 customers lost power across most of Kane and Garfield counties.  A spokesman for the cooperative said damage to the transformer could reach $1 million; repairs could take 6 to 12 months.  The utility has offered an unusually high reward -- $50,000 -- for information leading to the arrest of the shooter.

This is not the first time someone has used firearms to damage utility infrastructure.  Some incidents, such as the 2012 shotgunning of 167 insulating discs on Vermont's transmission system, may be considered vandalism.  Others, like the 2013 sniper shooting of a PG&E substation in San Jose, California, are considered terrorism.  That attack led the Federal Energy Regulatory Commission to implement new physical security protections for utility infrastructure known as CIP-014, through its Order No. 802.

The Garkane incident remains under investigation.  More broadly, it may strengthen calls for further hardening of the utility system against physical attack.  Meanwhile, efforts continue to strengthen cybersecurity protections for the grid.

BOEM advances California offshore wind leasing

U.S. ocean energy managers are moving closer to leasing sites in federal waters offshore California for wind energy development.  Acting in response to a lease area requested by Trident Winds, LLC, this month the Bureau of Ocean Energy Management (BOEM) issued a Request for Interest in that area to evaluate whether any other developer is interested in competing for a lease.

Trident Winds has initiated development of a commercial scale offshore wind farm off Point Estero, California.  Its Morro Bay or MBO Project would be located in federal waters about 33 nautical miles northwest of Morro Bay; the site features water depths of 2,600 to 3,300 feet.  In light of these site conditions, Trident Winds' proposed project would consist of 100 floating foundations, each supporting a wind turbine generating 7-8 megawatts of energy.  Electricity would be brought ashore via a single transmission cable.

Trident Winds requested a commercial wind lease from BOEM on January 14, 2016, covering a 67,963-acre proposed lease area.  Because BOEM had not previously solicited interest in leasing this area, BOEM treated Trident Winds' request as "unsolicited."  Under BOEM's offshore renewable energy program, when presented with an unsolicited lease request, BOEM first evaluates whether the developer is qualified to hold a lease on the Outer Continental Shelf.  In the case of Trident Winds, BOEM made this determination following consultation with the state of California.

Following this qualification determination, BOEM's next step is to determine whether it is appropriate to issue the company a lease on a non-competitive basis, or whether a competitive process is required.  To inform this competitive interest determination, on August 17, 2016, BOEM published a Potential Commercial Leasing for Wind Power on the Outer Continental Shelf (OCS) Offshore California, Request for Interest in the Federal Register, with a 30-day public comment period.  If BOEM finds competitive interest, it will initiate a competitive leasing process for the California site. If no expressions of interest are received, BOEM will proceed with its noncompetitive leasing process.

At the same time, BOEM is also seeking public comment on the project proposal, its potential environmental consequences, and other uses of the project area such as navigation, fishing, military activities, recreation.   BOEM will also use responses to shape its decisionmaking and to flag potential issues for analysis under the National Environmental Policy Act.

So far, BOEM has awarded 11 commercial wind energy leases for sites off the Atlantic coast, nine of which came from competitive lease sales that generated about $16 million in winning bids.  BOEM has also recently announced proposed lease sales for sites offshore North Carolina and New York.  In the Pacific, BOEM is evaluating 3 unsolicited lease requests offshore Hawaii and has published a Call for Interest in Hawaiian site leasing.

DesertLink transmission project wins rate incentives under Section 219

Federal energy regulators have granted a petition by the developer of a proposed electric transmission project in Nevada for certain transmission rate incentives available under federal law.  On August 19, the Federal Energy Regulatory Commission ruled on DesertLink, LLC's petition for declaratory order, with respect to DesertLink's new Harry Allen to Eldorado 500 kV transmission project.  The order grants DesertLink's requests for transmission rate incentives under section 219 of the Federal Power Act, and illustrates how those incentives operate.

DesertLink, a member of the LS Power Group, is the developer of a transmission project to be located in Nevada, but connected to a substation in the grid controlled by the California Independent System Operator Corporation.  CAISO designated the project for competitive bidding under its 2013-2014 transmission plan, and in January 2016 selected DesertLink as the approved project sponsor under its Order No. 1000-based process for eligible transmission developers to submit bids to develop and construct certain transmission projects.  The project is designed to have an in-service date of May 2020.

Rate incentives can be available to promote capital investments in certain transmission infrastructure.  The Federal Power Act authorizes the Federal Energy Regulatory Commission to regulate the transmission and wholesale sales of electricity in interstate commerce.  Through the Energy Policy Act of 2005, Congress added a new section 219 to the Federal Power Act, directing the Commission to create rules establishing incentive-based rate treatments.  The Commission's Order No. 679 sets forth the processes by which a public utility may seek transmission rate incentives under section 219, and the Commission has issued a Transmission Incentives Policy Statement offering guidance on how it evaluates applications for transmission rate incentives.

Section 219 and Order No. 679 require an applicant for rate incentives to show that “the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.”  Order No. 679 established a rebuttable presumption that this standard is met if:

(1) the transmission project results from a fair and open regional planning process that considers and evaluates the project for reliability and/or congestion and is found to be acceptable to the Commission; or (2) a project has received construction approval from an appropriate state commission or state siting authority.

Order No. 679 also requires an applicant to demonstrate that there is a nexus between the incentive being sought and the investment being made.  The Commission clarified in Order No. 679-A that this "nexus test" is met when an applicant demonstrates, on a project-specific basis, that the total package of incentives requested is “tailored to address the demonstrable risks or challenges faced by the applicant.”

In DesertLink's case, on May 11, 2016, the applicant applied for transmission rate incentives, including (1) deferred recovery of all prudently incurred precommercial costs through the creation of a regulatory asset (regulatory asset incentive); (2) full recovery of 100 percent of prudently-incurred costs, including pre-commercial expenses and construction costs, if the Project is abandoned for reasons beyond DesertLink’s control (abandonment incentive); (3) use of a hypothetical capital structure consisting of 50 percent debt and 50 percent equity until the Project achieves commercial operation (hypothetical capital structure incentive); and (4) a 50-basis point adder to DesertLink’s Return on Equity (ROE) for participating in a Regional Transmission Organization (RTO), namely, CAISO (RTO participation incentive).

Last week, the Commission granted DesertLink's petition.  First, the Commission found that DesertLink is entitled to the rebuttable presumption that the Project will ensure reliability or reduce the cost of delivered power by reducing transmission congestion, because the CAISO transmission planning process found annual production cost benefits of $9.4 million in 2019 to $8.4 million in 2024 and beyond, and annual capacity benefits of $19.7 million in 2020 to $8.8 million in 2025 and beyond.

Next, the Commission found that DesertLink had demonstrated that its total package of requested incentives is tailored to address the demonstrable risks or challenges faced by DesertLink.  The Commission found that the regulatory asset treatment of pre-commercial costs appropriately addresses the risks and challenges of the Project, because it provides DesertLink with added upfront regulatory certainty, reduces interest expenses, and assists in the construction of the Project.  On the abandonment incentive, the Commission found that recovery of abandonment costs was an effective means to encourage transmission development by reducing the risk of non-recovery of costs.  Regarding a hypothetical capital structure, the Commission noted that its use "will aid DesertLink in raising capital during the construction phase of the Project, and will assist DesertLink in maintaining low debt costs while its actual debt-to-equity ratio varies."  The Commission also found DesertLink would qualify for the RTO participation incentive, based on its commitment to become a member of CAISO and to transfer operational control of the project to CAISO after placing it in service.

The Commission's determination takes the form of a declaratory order granting authorization for the rate incentives, but it does not directly authorize DesertLink to include the incentives in its filed rates.  As the Commission noted, "While our determination on DesertLink's Petition establishes whether it qualifies for the requested transmission rate incentives, if DesertLink seeks to put these incentives into effect, it must submit a subsequent filing under section 205 of the FPA."  In such a case, the applicant will need to make a variety of showings before including certain incentives in its rate base, including the justness and reasonableness of costs relating to pre-commercial, formation, and plant abandonment.  Nevertheless, securing the declaratory order gives DesertLink greater certainty about its qualification for these key incentives for electric transmission development.

California floating offshore wind project proposed

The U.S. Bureau of Ocean Energy Management is moving toward the prospect of leasing sites for commercial wind energy development in federal waters offshore California.  According to a March 21 release by BOEM, a January 2016 request by Trident Winds, LLC for a lease will now trigger further steps in BOEM's leasing process.

Trident Winds filed its unsolicited lease request on January 14, 2016.  That request proposed a project to be located about 33 nautical miles northwest of Morro Bay.  The lease area proposed covers almost 68,000 acres in water depths of 2,600‐3,300 feet.  The project would generate up to 800 megawatts of power using about 100 floating foundations, each supporting a turbine that could produce up to 8 MW.  The project could be expanded to generate 1,000 megawatts at a later date, if additional transmission capacity and market off-take can be obtained.

On March 21, 2016, BOEM confirmed that Trident Winds is legally, technically, and financially qualified to hold an offshore wind energy lease in federal waters.

Under the agency's leasing process, its next step will be to publish a notice in the Federal Register to determine if there is competitive interest in the area requested. That Notice will also solicit comments and information on site conditions, commercial, military or other uses of the area and potential impacts of the proposed Trident Winds project.  BOEM expects to issue that Notice this summer.

Based on the information and expressions of interest received during the comment period on the Notice, BOEM will determine whether there is competitive interest in the area. If BOEM determines there is competitive interest, it will initiate its competitive leasing process. If no expressions of interest are received, BOEM will proceed with its noncompetitive leasing process.

So far, BOEM has awarded eleven commercial wind energy leases in federal waters off the Atlantic coast, nine of which were issued as a result of competitive lease sales.

Mojave Water Agency conduit hydropower project qualifies

A California wholesale water provider has received a written determination from federal regulators that its proposed hydroelectric power project qualifies for easier regulatory treatment under federal law.  The project entails replacing a pressure reducing valve on an existing water supply pipeline with a hydropower turbine and generator, to create renewable electric energy.  Crucially, its qualification as a conduit hydropower project under a 2013 federal law enables its construction without a license under the Federal Power Act.

Under the Federal Power Act, most hydropower projects must be licensed by the Federal Energy Regulatory Commission.  But the Hydropower Regulatory Efficiency Act of 2013 amended the Federal Power Act to ease the regulatory burden on certain projects described as "conduit hydropower" -- those generating electricity using only the hydroelectric potential of a non-federally owned conduit, such as a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption, and is not primarily for the generation of electricity.  The 2013 reform law exempted qualifying conduit hydropower facilities from needing licensure, and created an expedited process for soliciting public comment and determining whether the exemption applies.

This reform has led to a resurgence of interest in developing in-conduit hydroelectric projects.  For projects meeting the qualifying criteria, the FERC can act swiftly in issuing a determination that no licensure is required.  In some cases, this determination can come less than 60 days after an applicant files its notice of intent.

FERC's first conduit hydro docket in fiscal year 2016, CD16-1, illustrates this pace.  In that docket, the Mojave Water Agency was able to secure a written determination that the project it proposed meets the qualifying criteria under section 30(a) of the Federal Power Act, and thus is not required to be licensed under Part I of the FPA.

Among other operations, the Mojave Water Agency stores and distributes water in California's High Desert region.  An existing 48-inch pipeline conveys raw water sourced from the State Water Project to the Mojave River Basin for groundwater recharge.  Currently, pressure is reduced through a sleeve valve before discharging the SWP water to the Mojave River Basin by gravity flow.  But under the proposed Deep Creek Hydroelectric project, a hydroelectric turbine will perform the pressure reducing function while powering a generator capable of producing renewable electric energy.  According to the Mojave Water Agency, the hydroelectric station capacity will be 800 kW, with annual estimated power generation of 5,424 MWh.

On October 13, 2015, the MWA applied to the FERC for a determination that the Deep Creek project is a Qualifying Conduit Hydropower Facility, meeting the requirements of section 30(a) of the Federal Power Act (FPA), as amended by section 4 of the Hydropower Regulatory Efficiency Act of 2013 (HREA).

On October 15, 2015, Commission staff issued a public notice that preliminarily determined that the project met the statutory criteria for a qualifying conduit hydropower facility, and thus was not required to be licensed under Part I of the FPA. The notice established a 45-day period for entities to contest whether the project met the criteria. No comments or interventions were filed in response to the notice.

As a result, on December 3 the FERC issued a letter constituting a written determination that the Deep Creek Hydroelectric Project meets the qualifying criteria under FPA section 30(a), and is not required to be licensed under Part I of the FPA.

Other proposed conduit projects have benefited from this quick timeline and relatively streamlined process.  Qualifying conduit hydropower facilities remain subject to other applicable federal, state, and local laws and regulations.

Merced River hydro relicensing Environmental Impact Statement released

Staff of the Federal Energy Regulatory Commission have released a final Environmental Impact Statement (EIS) evaluating proposals to relicense two hydroelectric power projects located on the Merced River in California.

The two projects are Merced Irrigation District’s existing 101.25 megawatt Merced River Project No. 2179-043, and Pacific Gas and Electric Company’s (PG&E) existing 3.4-MW Merced Falls Project No. 2467-020.  Prepared as part of the relicensing process for those projects, the Merced River EIS contains FERC staff evaluations of the applicants’ proposals and the alternatives for relicensing the Merced River and Merced Falls Hydroelectric Projects.  The staff’s recommendation is to relicense the project as proposed, with certain modifications, and additional measures recommended by the agencies.

The Federal Energy Regulatory Commission is authorized by the Federal Power Act to issue licenses for up to 50 years for the construction and operation of nonfederal hydroelectric development subject to its jurisdiction, on condition:

That the project adopted…shall be such as in the judgment of the Commission will be best adapted to a comprehensive plan for improving or developing a waterway or waterways for the use or benefit of interstate or foreign commerce, for the improvement and utilization of water-power development, for the adequate protection, mitigation, and enhancement of fish and wildlife (including related spawning grounds and habitat), and for other beneficial public uses, including irrigation, flood control, water supply, and recreational and other purposes referred to in section 4(e)…

The Commission may also require such other conditions not inconsistent with the FPA as may be found necessary to provide for the various public interests to be served by the project.  To assist in this evaluation, and as required by the National Environmental Policy Act, FERC staff prepares the EIS.  It is designed to record the view of governmental agencies, non-governmental organizations, affected Indian tribes, the public, the license applicants, and FERC staff.

In the Merced River cases, the licensees used FERC's Integrated Licensing Process (ILP) and filed relicensing applications in February 2012.  FERC elected to process the applications for the two projects together "because they: (1) are located contiguously on the Merced River; (2) the Merced Falls Project’s operation depends entirely on flows released by the upstream Merced River Project; and (3) downstream of the Merced River Project, the environmental effects of both projects are interrelated."

Each applicant proposed some modified environmental measures in its license application, but no new capacity and no new construction at the project.  In the Merced projects' 840-page final EIS, Commission staff noted that the "primary issues associated with relicensing the projects are flow regimes in project-affected reaches for aquatic resources, project effects on physical habitat for aquatic resources, protection of wildlife resources, recreation enhancements, and protection of cultural resources." After consideration, Commission staff recommended the staff alternative, which consists of measures included in Merced ID’s and PG&E’s proposals, as well as some of the mandatory conditions and recommendations made by other state and federal agencies and non-governmental organizations, plus additional measures developed by FERC staff:

We chose the staff alternative as the preferred alternative because: (1) the projects would provide a dependable source of electrical energy for the region; (2) the generation comes from a renewable resource that does not contribute to atmospheric pollution, including greenhouse gases; and (3) the recommended environmental measures proposed by Merced ID and PG&E, as modified by staff, would adequately protect and enhance environmental resources affected by the projects. The overall benefits of the staff alternatives would be worth the cost of the environmental measures.

Ultimately, the Merced River hydropower relicensing project EIS concludes that "issuing new licenses for the Merced River and Merced Falls Projects, with the environmental measures we recommend, would not be major federal actions significantly affecting the quality of the human environment."

Report: solar panels add home appraisal value

"How will putting rooftop solar panels on my home affect its value?" is a common question among those considering residential-sited solar energy projects. 

It will help, according to a report recently released by the Lawrence Berkeley National Laboratory, finding solar photovoltaic systems add value to homes in a variety of markets under traditional appraisal methodology as well as statistical analysis.

A residential rooftop solar project in Massachusetts.

Intuition and previous studies have shown a "price premium" effect for solar photovoltaic systems in some markets.  Where a price premium applies, a home with a solar PV system can command a higher price than a comparable home without one.

A 2013 study of California using statistical analysis found "clear support that a premium exists in the marketplace; thus, PV systems have value, and their contribution to home values must be assessed."  That study found a strong correlation between premiums and PV system size, and a weak negative correlation with PV system age.  Essentially, "larger systems garner larger premiums and older systems garner smaller premiums," with each 1-kilowatt increase in size estimated as commanding a $5,911 higher premium, while each year of system age yields a $2,411 lower premium.  

A similar 2014 study of eight states found "PV consistently adds value across a variety of states, housing and PV markets, and home types."  Notably, these studies relied heavily on hedonic or regression pricing models to account for characteristics specific to each property (home type, site, neighborhood, market).  While such large-scale statistical analysis is commonly performed in economics, home buying more commonly relies on the appraisal process to support both price formation and financing.  Few previous studies were written by experienced real estate appraisers using paired-sales techniques or other standard appraisal methods.

The Lawrence Berkeley National Laboratory has released a report designed to bridge this gap, featuring a comparison of statistically derived PV premiums and analysis performed by experienced home appraisers.  That report, "Appraising into the Sun: Six-State Solar Home Paired-Sales Analysis", examined 43 pairs of comparable homes that sold with and without PV across seven areas in six state (California, Oregon, Florida, Maryland, North Carolina, and Pennsylvania).  It compared traditional real estate appraisal analysis of these homes to contributory-value estimates based on gross cost, net cost, and income. Overall, it found that under either statistical or appraisal based analysis, PV systems added premiums of $2.68/W to $4.31/W across states, averaging $3.78/W or about $14,000 for an "average-size" system sold in 2011 (3.8 kW).

The study did identify some difficulty in conducting comparable-sales analysis on homes with solar panels.  (It also includes a section titled "Warning to Users of this Study", noting the analysis was limited to specific times and places, only considered host-owned systems with crystalline-silicon panels, and does not address potential sales price implications related to the location of the PV systems.)  However, it found that appraised premiums are in agreement with the hedonic modeling results as well.  Practically speaking, this means cost- and income-based statistical estimates of PV premiums could be reliable when paired-sales analysis is impossible.

Further information about the Lawrence Berkeley National Laboratory report on appraisal value of residential solar PV systems can be found in a November 12, 2015 presentation hosted on its website.

Apple makes California solar deal

Electronics manufacturer Apple has announced an $848 million deal to buy electricity from a solar energy project to be developed in California. Project developer First Solar has described the power purchase agreement as "the largest agreement in the industry to provide clean energy to a commercial end user."

Solar photovoltaic panels in the Utah desert.

Earlier this week, Apple announced the deal with First Solar, Inc., to buy power from First Solar's California Flats Solar Project in Monterey County, California.  Under a 25-year power purchase agreement or PPA, Apple will buy the equivalent of 130 megawatts of the solar project's output. 

First Solar is a vertically-integrated solar company, manufacturing solar photovoltaic panels, developing utility-scale photovoltaic power plants, and providing solar project support services.  First Solar boasts involvement with over 10 gigawatts of installed solar photovoltaic capacity worldwide.  Its resume includes the 550-megawatt Topaz Solar project in California and the 290-megawatt Agua Caliente project, which was once the world's largest operating solar energy project.

First Solar's California Flats Solar Project will occupy a 2,900-acre site on the Jack Ranch in Cholame, California.  Owned by Hearst Corporation, the project site was formerly a dryland farm, and occupies about 3% of the Jack Ranch property.  First Solar expects to begin construction later this year, and to complete the project by the end of 2016.

With a total project capacity of 280 megawatts, Apple's 130-megawatt commitment covers about 46% of the project's output.  The project's remaining 150 megawatts will be sold to utility Pacific Gas & Electric under a separate long-term PPA.

Apple has developed other renewable energy projects, including fuel cells and solar panels at its Maiden, North Carolina data center.  Other high-tech companies have also made significant investments in renewable energy, including Google's commitment of over $1.5 billion to solar and wind projects through power purchase agreements and direct investments.

Topaz Solar becomes largest solar power project

A recent expansion has made a California solar energy project the world’s largest solar facility. Built in three phases, MidAmerican Renewables LLC’s Topaz Solar project in San Luis Obispo County now sports 550 MW total generating capacity.

A small distributed solar photovoltaic installation in Arches National Park, Utah -- much smaller than the Topaz Solar project.

Iowa-based MidAmerican Renewables LLC is a subsidiary of Berkshire Hathaway Energy formed to handle its expansion into the unregulated renewables market.  Its subsidiaries MidAmerican Solar, MidAmerican Wind, MidAmerican Geothermal and MidAmerican Hydro each focus on particular types of renewable energy generating technology.  In all, MidAmerican controls over 3,000 MW of renewable generating capacity in the U.S.

MidAmerican acquired the Topaz Solar project from First Solar in January 2012, after First Solar had acquired previous project developer OptiSolar, Inc.  Project construction began in November 2011, and proceeded in three phases.  Earlier phases came online in February 2013 and in January 2014, for a total of 300 MW of capacity.  With the recent expansion, the 550-megawatt project includes over 8 million photovoltaic modules, installed on 4,700 acres of the Carrizo Plain in the southern California desert.

The power produced by the project is sold to utility Pacific Gas and Electric Company under a 25-year power purchase agreement.  Topaz Solar won the long-term contract rights through its response to a 2007 solicitation by PG&E for renewable power.

According to the Federal Energy Regulatory Commission, the Topaz Solar project is now the world's largest solar energy plant.

Distributed generation is growing

Customer-sited generation is growing in the U.S.  A look at some of the distributed generation projects that came online in September 2014 shows that universities and institutions are developing projects powered by natural gas, solar photovoltaics, and oil, thanks to policies such as remote net metering and support for microgrid development.

At the University of California at Santa Cruz, Santa Cruz Cogeneration Associates has brought online a new 4.4 megawatt natural gas-fired cogeneration plant. The power generated is used on-site at the UC Santa Cruz campus.   Meanwhile the new unit will generate more than twice as much useful heat as the existing cogeneration unit, with a capacity of 1,391 tons (16,693 kBtu/h) of heating.

At the University of California at Riverside, Solar Star California XXIX LLC’s 3 megawatt UC Riverside Solar project is now online.  All of the power generated is used on-site at the UC Riverside campus, with the project's peak load representing about 30% of the campus's base load.  The University partnered with SunPower Corporation to install the 10.92-acre solar farm on campus open space.

Farther east, Cornell University’s 2 MW Snyder Road Solar Farm project came online. The power generated is used on-site at the Cornell University campus.  Cornell’s first solar photovoltaic project includes a 2MW tilt rack-mounted array on eleven acres of Cornell property in the Town of Lansing.  The Snyder Road Solar Farm is expected to produce 2.5 million kilowatt-hours annually, covering about 1 percent of Cornell’s total electricity use, and is expected to reduce the university’s annual greenhouse emissions by 625 metric tons per year.

Santa Fe Community College’s 1.5 MW Santa Fe Community College Solar project in Santa Fe County, New Mexico is online. The project is sited on 5.4 acres on campus, and consists of 4,620 SunPower 327-Watt photovoltaic modules mounted on fixed racking.  The power generated is used on-site at the Santa Fe Community College campus, generating approximately 43% of the college’s electricity demands, and saving the college more than $200,000 annually.  

Connecticut Municipal Electric Energy Cooperative’s 10 MW oil-fired Matlack Road Microgrid project in New London County, CT is online.  CMEEC supplies power and related electric services to municipal utilities and other wholesale customers that, in turn, provide electricity to roughly 70,000 residential, commercial/industrial and small business customers across the state.  The $9 million Matlack Road Microgrid project serves as emergency backup power for the Backus Hospital campus and adjacent critical facilities including schools, emergency shelters, fire station, supermarket / pharmacy, public water supply, gas station and a shopping center in the event of a sustained power outage.

Businesses and institutions choose distributed generation for a variety of reasons, but most hope for reduced costs and improved reliability compared to traditional utility service.  Will distributed generation continue to grow in the U.S.?  How will utilities -- and policymakers -- adapt as customers continue to adopt consumer-sited generation?

USDA awards $68 million for energy projects

The U.S. Department of Agriculture has announced $68 million in grants and loan guarantees for renewable energy and energy efficiency projects.  The latest round of awards under the agency's Rural Development arm's Rural Energy for America Program will support 540 projects at farm and rural business sites across the country.

Since its creation in the 2008 Farm Bill, REAP has supported more than 8,800 renewable energy and energy efficiency projects nationwide with over $276 million in grants and $268 million in loan guarantees to agricultural producers and rural small business owners.  Eligible agricultural producers and rural small businesses may use REAP funds to make energy efficiency improvements or install renewable energy systems including solar, wind, biomass and anaerobic digesters, small hydroelectric, ocean energy, hydrogen, and geothermal projects.  (For looks at previous REAP winners, check out these posts from 2011 and 2013.)

In this year's REAP funding round, USDA awarded about $68 million in investment support.  Of this, $12,376,548 will come in the form of grants, while $56,449,244 will come as loan guarantees.  While most grants are under $100,000 per project (with some below $10,000), there were some larger grant awards: for example, a biomass anaerobic digester in California won $290,000, an off-grid solar project in Hawaii won $123,338, and a direct use geothermal heat pump in Oklahoma won $133,250. Of the loan guarantees, $55.3 million will go to support 22 solar photovoltaic projects in North Carolina, mostly ranging between 2 megawatts and 5 megawatts per project. 

In each case, funding is contingent upon the recipients meeting the terms of the loan or grant agreement. USDA's hope is that these grants and loan guarantees will enable American agricultural producers and rural small business owners to reduce their energy costs.

REAP was reauthorized by the 2014 Farm Bill, so expect USDA Rural Development to solicit more REAP projects later this year.  While not all sites may qualify, USDA's definition of eligibility is more broad than many assume.  The Preti Flaherty team helps our clients understand how to benefit from REAP funding and other incentive programs for renewable energy and energy efficiency.  Contact Todd Griset to learn more.

Federal grants support microgrids

The U.S. Department of Energy has awarded over $8 million in funding for 7 microgrid projects.  Will microgrids play an increasing role in the U.S. electricity industry?

Solar photovoltaic panels can serve as distributed generation for microgrids.

Microgrids -- localized grids capable of operating as energy islands using distributed generation, energy storage, and distribution wires, as well as able to connect to the broader utility grid -- can offer participants and society at large significant value.  These benefits can include increased reliability against storm damage and infrastructure damage, reduced emissions of carbon and other pollutants, and reduced costs.

The Energy Department runs a portfolio of microgrid activities ranging from direct research and development to building community support.  Most recently, the Department announced over $8 million in grant funding to support 7 microgrid projects.  The Department selected these projects based on their ability to develop advanced microgrid controllers and system designs for microgrids less than 10 megawatts:

• ALSTOM Grid, Inc.: about $1.2 million to research and design community microgrid systems for the Philadelphia Industrial Development Corporation and the Philadelphia Water Department, using portions of the former Philadelphia Navy Yard. 
• Burr Energy, LLC: about $1.2 million to design and build a resilient microgrid to allow the Olney, Maryland Town Center to operate for weeks in the event of a regional outage, and a second microgrid for multi-use commercial development in Maryland. 
• Commonwealth Edison Company (ComEd): about $1.2 million to develop and test a commercial-grade microgrid controller capable of controlling a system of two or more interconnected microgrids, serving civic infrastructure including police and fire department headquarters, transportation and healthcare facilities, and private residences. 
• Electric Power Research Institute (EPRI): about $1.2 million to develop a commercially-viable standardized microgrid controller that can allow a community to provide continuous power for critical loads. 
• General Electric Company (GE): about $1.2 million to develop an enhanced microgrid control system in Potsdam, New York, by adding new capabilities, such as frequency regulation. 
• TDX Power, Inc.: about $1.2 million to engineer, design, simulate, and build a microgrid control system on remote Saint Paul Island, an island located in the Bering Sea off mainland Alaska. 
• The University of California, Irvine (UCI): about $1.2 million for the Advanced Power and Energy Program at UCI to develop and test a generic microgrid controller intended to be readily adapted to manage a range of microgrid systems, and supporting the development of open source industry standards.

Each project also includes an awardee cost share ranging from 20 percent to about 50 percent.  Will the DOE funds lead to better and more widely adopted microgrids?