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.

RC Byrd hydro project licensed at Army Corps locks and dam

Wednesday, August 30, 2017

Federal hydropower regulators have issued an original license to an Ohio city to construct, operate, and maintain a 50-megawatt hydroelectric project at an existing U.S. Army Corps of Engineers lock and dam site.  If developed as licensed, the City of Wadsworth, Ohio's Robert C. Byrd Hydroelectric Project will join other projects focused on adding hydroelectric generation to existing dams.

The Army Corps owns 21 locks and dams on the Ohio River, which it operates for commercial and recreational navigation.  These facilities include the RC Byrd Locks and Dam, originally built in the 1930s and renovated within the past 25 years.

On March 28, 2011, the City of Wadsworth, Ohio, applied to the Federal Energy Regulatory Commission for a license to construct, operate, and maintain the Robert C. Byrd Hydroelectric Project No. 12796.  As proposed by the city, the project would include new intake and tailrace structures along with a powerhouse holding two turbine generator units with a total installed capacity of 50 megwatts, but not the existing Army Corps dam.

On August 30, 2017, the Federal Energy Regulatory Commission issued its Order Issuing Original License for the RC Byrd Project.  The license, which authorizes the installation of 50 MW of new, renewable energy generation capacity, requires a number of measures to protect environmental resources at the project, including measures proposed by the licensee as well as additional terms and conditions developed by Commission staff and other agencies. 

According to the licensing order, the project will generate approximately 266,000 megawatt-hours per year, with a levelized annual cost of constructing and operating the project of about $40,586,280, or $152.58/MWh.  While the Commission found this to be more expensive than the cost of alternative power in the first year of licensure, the Commission also noted "that hydroelectric projects offer unique operational benefits to the electric utility system."  These ancillary service benefits "include the ability to help maintain the stability of a power system, such as by quickly adjusting power output to respond to rapid changes in system load; and to respond rapidly to a major utility system or regional blackout by providing a source of power to help restart the fossil-fuel generating stations and put them back on line."

Consistent with the Commission's general policy regarding license term for projects located on a federal dam, the Commission issued the RC Byrd Project license for a term of 50 years, the maximum allowable under the Federal Power Act.

If developed as licensed, the RC Byrd Project would be part of a trend toward adding hydroelectric generating facilities to existing dams owned by the Army Corps or other dam owners.  Congress and the Commission, as well as state agencies, have expressed support for adding hydropower to existing dams and lock structures.

Forest City Dam petition for declaratory order

Friday, August 25, 2017

The owner of a dam and reservoir spanning the East Branch of the St. Croix River on the international boundary between the United States and Canada has applied to federal regulators for a ruling that the project will no longer be required to be licensed as a hydropower project if it transfers the dam to a Maine state agency.

At issue is the Forest City Project. The water storage project currently operates under a license issued by the Federal Energy Regulatory Commission to Woodland Pulp, LLC.on November 23, 2015.  But on December 23, 2016, Forest City Project licensee Woodland Pulp LLC applied to the Commission to surrender its license and decommission the project by removing gates.  In its surrender application, the licensee noted that operating costs for the project as licensed would significantly exceed the downstream hydroelectric generation benefits, particularly given "significant new restrictions on operations" with unknown extra costs.  That surrender and decommissioning proceeding remains pending before the Federal Energy Regulatory Commission.

In the meantime, on July 24, 2017, Maine Governor Paul LePage signed into law a legislative resolve authorizing Maine Department of Inland Fisheries and Wildlife to assume ownership of the Forest City Dam pursuant to two conditions: (1) the Commission finds that the Forest City Project will not require a license from the Commission if Maine DIFW owns the U.S. portion of the dam; and (2) Maine DIFW executes an agreement with Woodland Pulp that provides that Woodland Pulp and its successors will operate and maintain the Forest City Dam consistent with the manner in which the dam was operated in most recent 12 months, at the direction of the State, and at no cost to the State, for a period of 15 years. The state agency and the licensee executed an operation and management agreement on July 27, 2017.

That same day, the licensee petitioned the Federal Energy Regulatory Commission for a declaratory order declaring that if Woodland Pulp transfers ownership of the U.S. portion of the project to the Maine DIFW, DIFW will not require a license from the Commission to continue to operate and maintain the Forest City Dam. As noted in the petition:
Woodland Pulp cannot continue to operate the Forest City Dam if it is subject to the FERC license. Although FERC has suggested that Woodland Pulp could avoid FERC jurisdiction by simply locking the gates in place, such a solution would be irresponsible because of flood, stream flow safety, and dam stability reasons. Thus, the only two possible ways for Woodland Pulp to avoid FERC jurisdiction, based on FERC’s rulings during the past 20+ years of litigation over this issue, is (1) to remove the dam gates so that the dam is not operated to produce downstream power generation benefits (as proposed in Woodland Pulp’s December 23, 2016 Surrender Application), or (2) to transfer the dam to another owner that will not operate the dam as part of a consolidated hydropower generation system. 
The petition suggests that transferring the dam would avoid the need to remove the dam's gates -- and thus transferring would enable the maintenance of East Grand Lake, the Forest City Dam's impoundment -- a key feature for a number of commenters in the case.

The Federal Energy Regulatory Commission has issued a notice of the petition for declaratory order and set deadlines for comments, protests, and motions to intervene.