Kitty Hawk NC offshore wind lease signed

Tuesday, October 17, 2017

U.S. ocean energy managers have leased a 122,405-acre site offshore North Carolina to a company for offshore wind development.  The U.S. Bureau of Ocean Energy Management's lease to Avangrid Renewables, LLC will enable the company to study the Kitty Hawk Wind Energy Area -- and possibly to propose developing an offshore wind project on the site.

On November 10, 2017, BOEM signed a lease agreement through which Avangrid Renewables, LLC will lease the Kitty Hawk Wind Energy Area offshore North Carolina.  The lease area is located about 24 nautical miles from shore.  Avangrid Renewables -- a subsidiary of AVANGRID, Inc. --  won the right to lease the site through a 17-round competitive lease sale or auction held on March 16, 2017, the first federal offshore wind lease sale under the Trump administration

The Kitty Hawk Wind Energy Area lease does not allow construction or operation of an offshore wind project on the site, but gives the company the exclusive right to submit to BOEM for approval a Site Assessment Plan (SAP) and Construction and Operations Plan (COP) for the project.  The lease bears a 1-year preliminary term, a 5-year site assessment term, and a 25-year operations term.  Annual rents payable to the federal government start at $367,215, or $3 per acre.  The lease also provides formulas setting an operating fee at about 2% of the power production value.

Avangrid Renewables' lease will take effect November 1, 2017. In a statement, company CEO and President Laura Beane said, "Executing this lease with the U.S. Bureau of Ocean Energy Management (BOEM) not only begins the formal process of studying these 122,000 acres in more detail, it means building long-term local and regional partnerships as we explore the opportunity to develop reliable, homegrown, clean energy using just the ocean breezes as fuel."

FERC staff report on cyber security, CIP reliability standards

Friday, October 13, 2017


Federal Energy Regulatory Commission staff have released a report on cyber security, including recommendations to help users, owners, and operators of the bulk-power system assess their risk and compliance position.

Federal law establishes a framework for regulating the reliability of the nation's major electricity grid, also known as the bulk electric system.  Acting under Section 215 of the Federal Power Act, the  Federal Energy Regulatory Commission has approved a set of Critical Infrastructure Protection or CIP Reliability Standards implemented by the North American Electric Reliability Corporation (NERC) and its regional entities.  The CIP reliability standards are designed to mitigate the cybersecurity risks to bulk electric system facilities, systems, and equipment.

Over the past two years, staff from FERC’s Office of Electric Reliability and Office of Enforcement and from NERC conducted a series of non-public audits of entities on the compliance registry.   The audits focused on compliance with version 5 of NERC’s Critical Infrastructure Protection (CIP) standards and also and identified possible areas for improvement that are not specifically addressed by the CIP reliability standards.

According to the report, "for the first series of completed non-public audits, most of the cyber security protection processes and procedures adopted by the audited entities met the mandatory requirements of the CIP Reliability Standards. Staff also found instances of potential compliance infractions."

The report presents 21 lessons learned, including the value of coordination and communication among regulated entities, improvements in physical security, and considering disconnecting unnecessary network access for remote assets.

Cybersecurity remains a hot topic in the energy sector.

Bloom petitions for fuel cell QF status

Thursday, October 12, 2017

Bloom Energy Corporation, maker of fuel cell-based "Energy Servers," has petitioned the Federal Energy Regulatory Commission for a declaratory order that its facilities meet the Commission’s standards for cogeneration units and thus that those 5 megawatts or smaller are "Qualifying Facilities" under federal law.

According to Bloom, its Energy Server Facilities employ solid oxide fuel cells that convert chemical energy directly into electricity using fuel and oxygen without combustion.  In Bloom's petition, the company says "each Bloom Server Facility uses innovative technology to generate electricity from hydrogen, relying on internalized chemical processes as part of its cogeneration function."  The petition describes a two-step electricity generation process: first, "hydrogen H2 is generated from methane CH4 (i.e., pipeline natural gas) through steam reformation. Second, the hydrogen H2 is reacted with oxygen to produce electricity."  According to the petition, "Bloom's Facilities utilize the heat and steam that are incidental to the chemical reaction to perform a secondary use of converting methane into hydrogen through steam reformation." 

Under the federal Public Utility Regulatory Policies Act of 1978 (or PURPA), generators meeting certain standards may be certified by the Commission as Qualifying Facilities.  The Commission defines a cogeneration facility as a generating facility that sequentially produces electricity and another form of useful thermal energy (such as heat or steam) in a way that is more efficient than the separate production of both forms of energy.  Cogeneration facilities meeting prescribed output and efficiency standards can be certified as qualifying facilities under PURPA, which guarantees QFs various rights.  Historically, cogeneration facilities have typically burned or combusted their fuel, as opposed to the fuel cell technology developed by Bloom.

Bloom argues that its Facilities are Qualifying Facilities, each meeting the standards for topping-cycle cogeneration facilities, because they produce electricity and in that process create heat and steam that is used to create hydrogen, all with output and operating efficiencies that meet the Commission's standards for Qualifying Facilities. It also notes that its facilities further the purposes of PURPA including the development of alternatives to traditional utility-owned energy resources.

If the Commission grants Bloom's petition, its facilities 5 megawatts and smaller could be certified as QFs. The Commission has docketed Bloom's petition as EL18-10, and has posted a notice and an opportunity for public comment through 5:00 pm Eastern time on November 9, 2017.

Massachusetts energy storage, net metering, and capacity market inquiry

Wednesday, October 11, 2017

Massachusetts utility regulators have opened an inquiry to investigate the eligibility of energy storage systems paired with net metering facilities to net meter and the qualification and bidding of certain net metering facilities in the Forward Capacity Market administered by ISO New England Inc.

The existing Massachusetts statutes and regulations allow customers to "net meter," or to generate credits for excess electricity generated by an eligible net metering facility.  Massachusetts allows a customer may install any type of generating facility, regardless of fuel source, as long as the facility is 60 kilowatts or less; if they generate electricity with renewable fuels (i.e., wind, solar photovoltaics, and anaerobic digestion), facilities can be up to two megawatts, or ten megawatts in the case of certain public facilities.

But the Massachusetts net metering statutes and regulations do not explicitly address how energy storage resources fit into the net metering program.  Several recent cases before the Department of Public Utilities have raised questions about the intersection of energy storage and net metering, as well as about what utilities should do to obtain payments for capacity products associated with solar net metering facilities.

On October 3, 2017, the Massachusetts Department of Public Utilities issued an Order Opening Inquiry into these issues.  Regarding the eligibility of energy storage systems to net meter, the Department posed a series of questions on which it requested initial written comments no later than 5:00 p.m. on November 17, 2017, with written reply comments not later than 5:00 p.m. on December 8, 2017. Questions include whether net metering facilities paired with energy storage systems be eligible to net meter.  The order expresses concerns about avoiding "gaming and manipulation of the net metering rules and regulations," and the Department's expectation that a net metering facility paired with an energy storage system would need to be configured such that the energy torage system is charged only from the net metering facility and cannot export power to the electric grid.

The Department also requested comment by February 1, 2018, on questions relating to the participation of net metering systems in the ISO-NE Forward Capacity Market or FCM.

FERC grid reliability and resilience pricing questions

Tuesday, October 10, 2017

U.S. energy regulators have asked for public comment on a rule proposed by the Secretary of Energy that would require organized grid operators to pay certain electric generators for their grid reliability and resilience benefits.

On September 28, 2017, Secretary of Energy Rick Perry directed the Federal Energy Regulatory Commission to consider a proposed rule on an expedited basis.  The proposed rule defines an "eligible grid reliability and resiliency resource" based on criteria including the ability to provide essential energy and ancillary reliability services and to have a 90-day fuel supply on site enabling it to operate during an emergency, extreme weather conditions, or a natural or man-made disaster.  It would requires independent system operators and regional transmission organizations to establish a tariff that provides a " just and reasonable rate" for the purchase of electric energy from such resources including recovery of costs and a return on equity

On October 2, the Commission issued a Notice Inviting Comments, asking interested persons to submit comments regarding the proposal on or before October 23, 2017.  Two days later, Commission staff followed up with a series of questions for public comment.  Questions in that document cover topics including the need for reform, eligibility, implementation, and rates, as well as impacts on consumers.

Some questions posed by the Commission staff in its October 4, 2017 document are general, such as, "What is resilience, how is it measured, and how is it different from reliability? What levels of resilience and reliability are appropriate?"  Others ask for whether commenters agree with references in the proposed rule to the 2014 "Polar Vortex" and "other extreme weather events, specifically hurricanes Irma, Harvey, Maria, and superstorm Sandy," as well as "the retirement of coal and nuclear resources and a concern from Congress about the potential further loss of valuable generation resources" as justifying the need for action.

As previously noticed by the Commission, initial comments on the proposed Grid Reliability and Resilience Pricing Rule in Docket No. RM18-1-000 are due on or before October 23, 2017 and reply comments due on or before November 7, 2017.

MWRA applies to surrender conduit exemption

Monday, October 9, 2017

The Massachusetts Water Resources Agency has petitioned federal hydropower regulators to surrender its exemption for the Aqueduct Transfer Station Small Conduit Project, a conduit hydropower facility which has not generated power since 1995.

MWRA is a Massachusetts public authority established by an act of the state legislature in 1984 to provide wholesale water and sewer services to 2.5 million people and more than 5,500 large industrial users in 61 metropolitan Boston communities.

In 1987, the Federal Energy Regulatory Commission issued MWRA an exemption from licensing under the Federal Power Act for the Aqueduct Transfer Station Small Conduit Project.  As described in the Commission's order granting exemption from licensing, the project involves a 750-kilowatt turbine-generator fed by a conduit connecting two aqueducts.

But as described in MWRA's petition to surrender its exemption for the Aqueduct Transfer Station project, the aqueduct providing water to the turbine has only been used intermittently since 1996, and the project has not operated since 1995.  According to that petition, "It is not economical to maintain the hydropower facilities for such occasional use.  Therefore, MWRA is hereby proposing to decommission the hydroelectric Project and surrender the Exemption."  Specifically, MWRA proposes to decommission the project "by maintaining the valves to the turbine in a shut off and closed position and by locking out the electrical breaker from the generator and physically disconnecting the leads from the generator.  MWRA has no plans to remove the turbine and generating unit."

On October 4, the Commission issued a notice that MWRA's application had been filed with the Commission, setting a 30-day deadline for filing comments, motions to intervene, protests, and recommendations.

TransCanada says it won't develop Energy East

Canadian pipeline operator TransCanada Corporation has announced a decision not to proceed with its Energy East oil pipeline and a related natural gas pipeline.

In 2014, TransCanada affiliates applied to the National Energy Board of Canada for approvals relating to two proposed pipeline projects to transport "about 1.1 million barrels of oil per day from Alberta and Saskatchewan to the refineries of Eastern Canada and a marine terminal in New Brunswick" and to ensure natural gas supply to utilities in Ontario and Quebec. The Energy East and Eastern Mainline projects entailed about 4,500 kilometers of pipeline, with a proposed cost of C$15.75 billion.

But the Energy East project was controversial, drawing criticism from environmentalists, indigenous community leaders, and some municipalities.  At the same time, growth in oil production from the oil sands has slowed in light of economic and environmental factors.  Meanwhile, another pipeline proposed by TransCanada -- Keystone XL -- is moving forward following President Trump's approval of that project.

On September 8, 2017, the National Energy Board suspended its review of the projects at TransCanada's request, several weeks after the board decided to include direct and indirect greenhouse gas emissions in its list of issues and environmental assessment factors to be considered.  At that time, the Board held that it "will not issue further decisions or take further process steps relating to the review of the Projects until 8 October 2017."

On October 5, TransCanada announced that after "careful review of changed circumstances," it will no longer be proceeding with these projects

According to TransCanada, the projects have an approximate carrying value of $1.3 billion, and the company expects an estimated $1 billion after-tax non-cash charge will be recorded in 2017-Q4.  The press release notes, "In light of the project’s inability to reach a regulatory decision, no recoveries of costs from third parties are expected."