Hurricanes, PREPA, and Puerto Rico electric grid

Friday, September 22, 2017

Hurricane Maria has hit Puerto Rico, damaging the island's electric grid and causing systemic power outages.  The storm made landfall on September 20 as a Category 4 hurricane with winds at 155 miles per hour.  Hurricane Maria's damage to power plants and transmission and distribution comes on top of damage from Hurricane Irma earlier this month -- and comes at a time when the government-owned utility company responsible for the island's electricity is functionally bankrupt.

In remarks, President Trump described his view of the damage:
Puerto Rico was absolutely obliterated... Their electrical grid is destroyed. It wasn't in good shape to start off with, but their electrical grid is totally destroyed and so many other things.
Electricity generation, transmission, and distribution in Puerto Rico is handled by a government-owned corporation, Puerto Rico Electric Power Authority (PREPA, known in Spanish as Autoridad de Energia El├ęctrica or AEE).  It generates power at a portfolio of plants, mostly fueled by diesel or heavy fuel oil.

But PREPA has significant debts -- approximately $9 billion as of earlier this year.  Years of discussions with creditors have apparently failed to provide relief.  On July 2, 2017, said PREPA had filed in the United States District Court of Puerto Rico for protection under a workout process similar to bankruptcy, available under a 2016 federal law designed to bail out Puerto Rico. 

While PREPA remains operational, its financial woes cannot help its ability to respond to Hurricane Maria.

FERC approves reliability standards, proposes further revisions

Wednesday, September 20, 2017

At its first open meeting following restoration of its quorum, today the Federal Energy Regulatory Commission approved two final rules and issued a Notice of Proposed Rulemaking addressing mandatory standards intended to support the resilience and reliability of the nation’s bulk electric system.

One final rule, adopted by Order No. 836, approves revised reliability standards that clarify and consolidate existing requirements related to frequency control.  Through Order No. 836, the Commission approved Reliability Standards for Balancing Authority Control (BAL-005-1) and Facility Interconnection Requirements (FAC-001-3). According to the Commission, the revised standards clarify and consolidate existing requirements related to frequency control, and will support more accurate and comprehensive calculation of Reporting Area Control Error.

The second final rule, adopted by Order No. 837, approves a revised reliability standard on Remedial Action Schemes (PRC-012-2) to ensure that remedial action schemes -- how the grid detects predetermined system conditions and takes corrective actions as needed -- do not introduce unintentional or unacceptable reliability risks to the bulk electric system. The rule establishes a process for reviewing new or modified remedial action schemes before they are implmeneted.  It requires periodic evaluations, tests and operational analyses of each remedial action scheme and an annual update of an area-wide database of remedial action schemes.

The final rules will take effect 60 days after their publication in the Federal Register.

In a similar vein, the Commission also issued a Notice of Proposed Rulemaking proposing to adopt four additional revised Emergency Preparedness and Operations reliability standards.  The proposed standards cover Event Reporting (EOP-004-4), System Restoration from Blackstart Resources (EOP-005-3), System Restoration Coordination (EOP-006-3) and Loss of Control Center Functionality (EOP-008-2). According to the Commission, its proposed standards will enhance event reporting, delineate roles and responsibilities for system restoration from blackstart resources, clarify system restoration processes, and refine the required elements of an operating plan used to continue reliable operation of the grid if primary control functionality is lost.

Comments on the NOPR will be due 60 days after its publication in the Federal Register.

RGGI states propose tighter carbon budget

Friday, September 15, 2017

The nine states participating in the Regional Greenhouse Gas Initiative have announced consensus on proposed revisions to that program that would provide a further 30% reduction in the regional limit on emissions by 2030, relative to 2020 levels.  The proposed regional program changes are now available for stakeholder comment, after which each participating state will follow its own specific statutory and regulatory processes to propose updates to their own carbon dioxide budget trading programs.

Nine Northeast and Mid-Atlantic states -- Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont -- currently participate in RGGI, the first mandatory market-based regulatory program in the U.S. to reduce greenhouse gas emissions.  RGGI is composed of individual CO2 budget trading programs in each state, based on each state’s independent legal authority.  The program imposes an annual aggregate cap on greenhouse emissions from covered sources like fossil-fueled power plants in participating states.  For 2017, the cap is 84.3 million short tons (62.5 million short tons adjusted for banked allowances); it declines 2.5 percent each year until 2020.  Since 2008, participating states have reduced power sector carbon emissions by nearly 50 percent, while generating more than $2.7 billion in allowance auction proceeds for reinvestment in programs to benefit consumers.

RGGI participating states periodically conduct a "program review".  Following their 2012 Program Review, the RGGI states implemented a new 2014 RGGI cap of 91 million short tons -- 45 % below the prior 2014 cap of 165 million short tons. At that time, the participating states decided to commence the next program review no later than 2016.

RGGI's 2016 Program Review is ongoing.  According to an August 23, 2017 announcement, the participating states have reached consensus on proposed changes to the program design.  Proposed changes include a regional cap of 75,147,784 tons in 2021, which will decline by 2.275 million tons per year thereafter, resulting in a total 30% reduction in the regional cap from 2020 to 2030.  The proposed changes also include modifications to the existing Cost Containment Reserve and implementation of a new Emissions Containment Reserve which would add some flexibility to the cap size.

On behalf of participating states, RGGI, Inc. has announced a meeting on September 25 to gather stakeholder input.  According to the announcement, after reviewing stakeholder comments, conducting additional economic analysis, and updating materials, each participating state is expected to execute its own statutory and regulatory process to update its own carbon budget trading program.

Maine's energy legislation carryovers from 2017

Wednesday, September 13, 2017

When the First Regular Session of the 128th Maine State Legislature adjourned earlier this year, its committees reserved a list of bills for further debate in 2018.  A list of these carryover bills published by the legislative information office includes 16 bills carried over by the Joint Standing Committee on Energy, Utilities, and Technology.  While new legislation may be proposed in the legislature's second session, the committee's work in 2018 will include action on these carried-over bills.

Here's an excerpt from the list of bills carried over, focused on the Energy, Utilities, and Technology committee:
Based on these bill titles, the committee will be faced with continuing discussion over broadband; regulation and incentives for renewable energy resources including solar, hydroelectricity and biomass; economic development and reduction of electricity rates.

Energy East pipeline case suspended

Monday, September 11, 2017

The developed of a proposed C$15.75 billion Canadian oil pipeline has asked Canadian regulators to temporarily suspend their review of the project, following the regulator's decision to consider the project's indirect greenhouse gas emissions and other factors as part of its environmental review.

At issue are the proposed Energy East Pipeline and the related Eastern Maineline Project, proposed by affiliates of TransCanada Corp. 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.  In 2014, the developed applied to Canada's National Energy Board for approvals required for the 4,500-kilometer project's development.

That case remains pending, but a recent decision about the scope of environmental review has prompted the developer to ask for a temporary pause of the case. On August 23, 2017, the National Energy Board released its final decision establishing a List of Issues and Environmental Assessment Factors to be considered in its review of the projects.  The factors set for consideration include greenhouse gas emissions.  While the Board's environmental factors typically include only direct greenhouse gas emissions -- those emitted by the project itself -- including indirect emissions -- in this case the Board decided to include indirect greenhouse gas emissions as well:
Given increasing public interest in GHG emissions, together with increasing governmental actions and commitments (including the federal government’s stated interest in assessing upstream GHG emissions associated with major pipelines), the Board is of the view that it should also consider indirect GHG emissions in its NEB Act public interest determination for each of the Projects.
On September 7, the applicants filed a letter requesting a 30-day suspension of the Board's review process to give applicants time to "review the Decision, the resulting implications to the Projects, and the respective Project applications."  The next day, the Board issued a ruling that it "will not issue further decisions or take further process steps relating to the review of the Projects until 8 October 2017."

The case remains suspended until that time. 

PEI submarine transmission line energized

Friday, September 1, 2017

On August 29, 2017, a Canadian utility energized a new $142.5 million (CAD) undersea electric transmission system connecting Canada's Prince Edward Island to mainland New Brunswick. 

The Northumberland Strait Submarine Transmission System includes two 180-megawatt underwater cables, running 17 kilometers from Cape Tormentine, New Brunswick, to Borden-Carleton, Prince Edward Island.  They replace aging cables with a more limited transfer capability.  The project also includes new overhead transmission lines on land and an expanded substation. The cost was split by the federal Government of Canada (contributing up to $68.9 million from the Green Infrastructure Fund) and the Province of Prince Edward Island (contributing up to $73.6 million). 

The new submarine cables supply approximately 75% of the Island's electricity.  The cables are buried under the seabed in separate trenches. The project including the use of a marine excavator called a "Starfish" as well as a trenching remotely operated vehicle with a saw cutter.

They replace cables installed in 1977, when the island's electricity load was 95 megawatts.  In addition to the old cables' age, they were also insufficient -- PEI's load has grown to 262 megawatts by 2015.  While the island does have significant wind energy supply, utility Maritime Electric noted the need for firm power to back up wind's intermittent supply.  A press release announcing the Canadian government's 2015 decision to support the project describes it as the most significant on Prince Edward Island since the Confederation Bridge. 

Interest in submarine transmission cables is growing.  Improved marine technology, the difficulty of siting major linear infrastructure on land, and the growth of offshore wind and other remote renewable resources are all driving this trend, as is the need to provide reliable, affordable, clean power to consumers in island communities.

Energy Department funds for new hydropower at existing dams

Thursday, August 31, 2017

The U.S. Department of Energy has $6.6 million available for the latest round of funding under a program supporting projects adding hydroelectric power generating capabilities to existing dams and impoundments.  Applications for this new round of funding under section 242 of the Energy Policy Act of 2005 are due September 6, 2017.

In 2005, Congress enacted the Energy Policy Act of 2005.  Among its many features, the law established a program to support the expansion of hydropower energy development at existing dams and impoundments through an incentive payment procedure.  Section 242 of EPAct 2005 directs the Secretary of Energy to provide incentive payments to the owner or authorized operator of qualified hydroelectric facilities for electric energy generated and sold from a qualified hydroelectric facility for a 10-year period.

The program's focus is on the addition of generation facilities to existing dams or conduits.  The Energy Department's guidance for its 2017 implementation of the section 242 hydropower incentive program defines "qualified hydroelectric facility" as:
a turbine or other generating device (including conventional or new and innovative technologies capable of continuous operation) owned or solely operated by a non-Federal entity that: (1) began producing hydroelectric energy for sale on or after October 1, 2005; (2) is added to an existing dam completed before August 8, 2005 ( “added” means new hydropower generation where none existed before, or where an existing facility had been offline because of disrepair or dismantling for at least five consecutive years prior to October 1, 2005 before new construction); and (3) the majority of which was developed through new construction incorporating new equipment, refurbished equipment, or both.
According to DOE's notice of the availability of the guidance and application for this round of the incentive program, the agency is accepting applications for full calendar year 2016 production, from qualified hydroelectric facility which began operations starting October 1, 2005, through September 30, 2015.