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.

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.

US LNG exports increasing, proposed

Tuesday, August 22, 2017

The developer of a proposed Louisiana liquefied natural gas (LNG) export project has asked U.S. regulators for approval to begin a "pre-filing review" of its project.  Part of a boom of interest in LNG exports, the Fourchon LNG pre-filing request highlights the regulatory process -- and broader policy considerations -- associated with increased exports of natural gas from the U.S.

Energy World (USA) Incorporated subsidiary Fourchon LNG LLC proposes to site, construct, own, and operate a LNG liquefaction facility with a peak capacity of approximately five million metric tons of LNG per annum (MTPA) and a ship berth on Belle Pass in Louisiana.  According to the company's filing, the project would be developed in phases.  The first phase will have a capacity of 2 MTPA, to be followed by subsequent phases and additional LNG trains to reach a total capacity of 5 MTPA. The project, which will utilize domestic sources of natural gas, will receive, liquefy, store, and deliver LNG to LNG carriers (LNGCs) for export in overseas markets and domestic markets.  According to the developer, the first 0.5 MTPA of LNG will be made on a preferred, but non-exclusive basis for domestic LNG uses, including for LNG-fueled marine vessels; other potential customers include Jamaica and the wider Caribbean, as well as gas-fired power plants in the Asia-Pacific.

The Federal Energy Regulatory Commission is responsible for authorizing the siting and construction of onshore and near-shore LNG import or export facilities under Section 3 of the Natural Gas Act.   On August 3, 2017, the company applied to the Federal Energy Regulatory Commission for approval under Section 157.21 of the Commission's regulations to initiate pre-filing review of its proposed project.

LNG shipments from the U.S. have recently started and are increasing sharply.  Since the first shipment of U.S. LNG from the lower 48 states in February 2016, exports have continued.  The ability to produce and export natural gas is seen by some as a major asset for the U.S. economy -- Energy Secretary Rick Perry has said he expects the U.S. to become the world’s third-largest LNG supplier by 2020.  The increase in business opportunity related to LNG exports is driving a parallel increase in regulatory activity: according to the Federal Energy Regulatory Commission, as of August 14, 2017 eleven applications for export terminals were pending before the Commission, with three more sites in pre-filing, plus additional proposed terminals in Canada and the Gulf of Mexico.  While not all projects have been approved -- for example in 2016  FERC denied approvals requested for the Jordan Cove export project in Oregon -- FERC says it currently regulates twenty-four operational LNG facilities. In addition to FERC siting approval, most LNG exports are subject to further approvals by the Secretary of Energy.

Meanwhile, a group of industrial electricity customers has sent Energy Secretary Perry an open letter expressing alarm "at the volume of LNG exports that have been approved for periods of 20-30 years, especially to non-free trade agreement (NFTA) countries" and at the economic impact of those exports.

NMFS issues final Atlantic sturgeon rule

Monday, August 21, 2017

U.S. fisheries regulators have issued a final rule designating nearly 4,000 river miles in Atlantic watersheds as critical habitat for endangered and threatened Atlantic sturgeon.  The rule increases regulatory complexity and compliance obligations for some hydropower and nuclear power licensees, among others.

The National Marine Fisheries Service, also known as NOAA Fisheries, is an office of the National Oceanic and Atmospheric Administration within the Department of Commerce.  Under the Endangered Species Act of 1973, the Secretary of the Interior and the Secretary of Commerce share, among other things, the responsibility to determine species of fauna and flora to be endangered species and threatened species.  Under a memorandum of understanding with the U.S. Fish and Wildlife Service, NMFS has jurisdiction to list marine fish species.

Once a species is listed as threatened or endangered under the Endangered Species Act, a variety of protections attach to that species.  For example, under Section 7 of the federal Endangered Species Act, federal agencies must generally ensure that any actions they authorize, fund, or carry out are not likely to jeopardize the continued existence of a listed species, or destroy or adversely modify its designated critical habitat.

Critical habitat is defined in section 3 of the Endangered Species Act as (1) the specific areas within the geographical area occupied by the species, at the time it is listed, on which are found those physical or biological features (a) essential to the conservation of the species and (b) which may require special management considerations or protection; and (2) specific areas outside the geographical area occupied by the species at the time it is listed, upon a determination by the Secretary that such areas are essential for the conservation of the species.
While a critical habitat designation does not directly impact activity on private land that does not involve a federal agency, it does add to the procedures and considerations that any federal agency must undertake if asked to weigh in on an activity affecting critical habitat.  For example, if a hydropower project seeking licensing from the Federal Energy Regulatory Commission (or a nuclear project regulated by the Nuclear Regulatory Commission) includes critical habitat for a threatened or endangered species, the Commission and other federal agencies involved in the licensing must take special actions to protect that critical habitat.

With respect to the five threatened and endangered Atlantic sturgeon distinct population segments, NMFS concluded that specific areas meet the definition of critical habitat for the Gulf of Maine, New York Bight, Chesapeake Bay, Carolina, and South Atlantic DPSs of Atlantic sturgeon, that a critical habitat designation is prudent, and that critical habitat is determinable.  The designations include about 152 miles of aquatic habitat within the Penobscot, Kennebec, Androscoggin, Piscataqua, Cocheco, Salmon Falls, and Merrimack Rivers for the Gulf of Maine DPS; about 340 miles of aquatic habitat within the Connecticut, Housatonic, Hudson, and Delaware Rivers for the New York Bight DPS; about 480 miles of aquatic habitat within the Potomac, Rappahannock, York, Pamunkey, Mattaponi, James, Nanticoke Rivers and Marshyhope Creek for the Chesapeake Bay DPS; about 1,205 miles of aquatic habitat within the Roanoke, Tar-Pamlico, Neuse, Cape Fear, Northeast Cape Fear, Waccamaw, Pee Dee, Black, Santee, North Santee, South Santee, and Cooper Rivers and Bull Creek for the Carolina DPS; and about 1,791 miles of aquatic habitat within the Edisto, Combahee-Salkehatchie, Savannah, Ogeechee, Altamaha, Ocmulgee, Oconee, Satilla, and St. Marys Rivers for the South Atlantic DPS of Atlantic sturgeon.

According to NMFS, it does not believe this rule will have a "significant adverse effect on the supply, distribution, or use of energy."  At the same time, it notes that FERC hydropower licensing and Nuclear Regulatory Commission "have the potential to adversely affect sturgeon as well as its critical habitat".

The final rule will take effect on September 18, 2017.

Report links US nuclear industry to national security

Friday, August 18, 2017

The U.S. nuclear energy enterprise is a key national security enabler, according to a report released this week by a new non-profit.  The Energy Futures Initiative's report describes the domestic nuclear energy industry as playing important roles in both electricity supply and "maintaining a robust supply chain (equipment, services, and skilled personnel) that is necessary for U.S. leadership in global nuclear nonproliferation policy."

According to its website, Energy Futures Initiative, Inc. (EFI) is "a new not-for-profit dedicated to driving innovation in energy technology, policy and business models."  EFI's principals include fomer U.S. Secretary of Energy Dr. Ernest Moniz.

EFI's August 2017 report, "The U.S. Nuclear Energy Enterprise: A Key National Security Enabler," analyzes the domestic nuclear energy sector's role in meeting national security imperatives, including:
  • maintaining U.S. leadership in ensuring nuclear non-proliferation;
  • supporting the U.S. nuclear Navy; and
  • supporting the global strategic stability and deterrence value of nuclear weapons.
It notes that in addition to supplying electricity, nuclear power provides values including climate change risk mitigation, fuel price risk management, and national security -- some of which are not addressed in electricity rate-making policy.  The report notes:
The analysis suggests that the imperatives of global climate change, collective energy security, balance of trade and U.S. national security require a viable domestic commercial nuclear power industry, including a robust supply chain of technology, services and human resources. Recent events and future trends point in the opposite direction: commercial reactors are shutting down, new builds are struggling, the supply chain is at risk, and it is likely that the educational pipeline will negatively respond to these challenges.
To ensure that the federal government addresses the relationship between a robust nuclear energy enterprise and goals including nonproliferation, Navy fleet modernization, and "the global strategic stability and deterrence value of nuclear weapons," the report suggests steps the U.S. could take.  These include making "maximum flexible use of its existing resources and capabilities, including credit support, tax incentives and federal siting and/or purchase power agreements, to bolster support for current new builds and to encourage additional new builds," as well as directing the Federal Energy Regulatory Commission to "place greater emphasis on the national security importance of nuclear power and its associated supply chain."  It also suggests that Congress allocate $2 billion per year for the next five years to fund research and development into new reactor designs.

Will Utah counties fund thorium reactor?

Thursday, August 17, 2017

Could a coalition of rural counties in Utah and a startup company develop a thorium-fueled nuclear reactor for electric power and other purposes?

According to its website, the Seven County Infrastructure Coalition is currently comprised of seven counties in eastern Utah: Carbon, Daggett, Duchesne, Emery, San Juan, Sevier, and Uintah.  The website describes the Coalition’s main roles and mission as "to identify revenue-producing infrastructure assets that will benefit the region" and "to plan infrastructure corridors, procure funding, permit, design, secure rights-of-way and own such facilities," with operation and maintenance possibly outsourced to third parties.

Apparently under consideration by the Coalition are energy projects, including a "thorium energy" project and a "hydrogen plant" project.  For example, the "Procurement" section of the Coalition's website includes a Request for Qualifications for Project Analyst for Potential Thorium Energy and Hydrogen Plant Projects, as well as a Request for Qualifications Project Financial Analyst on Potential Thorium Energy Project.

Under the Project Analyst RFQ, which closed August 1, 2017,
The Coalition seeks an individual or team to act as a Project Analyst to advise it and its member counties on two proposed projects, how to evaluate emerging technologies, and the respective project teams. One project is a thorium energy facility for producing electricity, etc. as proposed by Alpha Tech Research Corporation. The second project consists of hydrogen plants to be used as fueling stations for hydrogen/electric semi-trucks as proposed by Nikola Motor Company, LLC.
Responsibilities defined in this original RFQ would include evaluation of the thorium energy and hydrogen plant projects, including an evaluation of "the feasibility and viability of projects in general, as well as the proposed projects, and determine how the Coalition and its members may use their assets to best benefit the public."

According to its website, Alpha Tech Research Corp.'s motto is "Changing the face of nuclear power with clean, safe, molten salt reactor technology."  But little other public information is easy to find on the company.

Thorium is a radioactive element that can be used in a nuclear reactor as a fuel for power production.  It is distinct from the uranium-based fuel used in traditional nuclear power plants.  Some limited research and development was conducted on thorium-based reactors in the twentieth century, but recent projects and all commercial reactors rely the uranium fuel cycle.  Proponents of thorium reactors suggest abundant fuel supplies and reduced weapons proliferation risk compared to uranium, combined with other advantages of nuclear power such as reliable baseload generation with zero carbon emissions.  Some point to Utah's mineral richness as a cost-effective source for lithium, beryllium, and other materials that could be useful in molten salt reactor resign. But crucially the technology, regulation, and business structures necessary to support a thorium reactor may not yet exist.

Fifteen days after the Project Analyst RFQ closed, the Coalition issued another request for qualifications "to seek an individual or team to act as a Project Analyst to advise it and its member counties on a proposed project related to thorium energy. In addition, the Coalition seeks guidance on how to evaluate emerging technologies, and companies or groups proposing projects to the Coalition. The thorium energy facility for producing electricity, etc. is proposed by Alpha Tech Research Corporation." Proposals under this subsequent RFQ are due by 2:00 PM on October 2, 2017.  According to the Salt Lake Tribune, a coalition representative reported, "The coalition’s initial request for qualifications drew no adequate responses by its Aug. 1 deadline."  (Query why not.)

It's unclear how far the Utah counties' efforts can go.  The coalition's stated criteria for evaluating potential projects include requiring appropriate project benefits (such as facilitating needs in rural Utah that would otherwise go unaddressed), as well as avoidance of any "fatal flaws" (such as "obvious non-Coalition sponsor that should take the lead", project success unlikely" and "low perceived benefit compared to cost.")  The coalition is presumably at the stage where it is seeking expert advice to help it evaluate the thorium energy project under these criteria.

In its materials, the coalition emphasizes its expectation to rely on public-private partnerships, in part to allocate project risk to private entities with special expertise in taking those risks.  But developing the first commercial thorium reactor inherently involves a variety of risks -- including developing a technology that works, securing all necessary regulatory approvals, and having business or financial arrangements in place that make the project a success.  These risks could pan out in the counties' favor -- but might not.  A coalition of South Carolina utilities developing what would have been the nation's first new commercial nuclear reactor recently announced a decision to suspend that project partway through construction, following years of delay, billions of dollars in cost overruns.  While a thorium reactor might avoid some of these challenges, others are likely systemic to the state of the nuclear power industry from a technological, regulatory, and business perspective, and would be hard for the counties to avoid. The counties may also have more proximate opportunities to achieve similar goals, including by facilitating or developing renewable energy infrastructure.

At the same time, the coalition deserves credit for thinking proactively and considering its options.  Whether the coalition continues to pursue thorium energy, or focuses on less speculative projects, the coalition's fundamental mission remains "to improve the quality of life through cooperative regional planning, increased economic opportunity, and sustainable implementation."  With the right balance of risk and reward, its evaluation of proposed projects could advance that mission.

Vermont village considers conduit hydro

Wednesday, August 16, 2017

A Vermont municipality has proposed installing hydroelectric generating facilities along a potable water pipeline -- and under streamlined federal procedures, regulators have made a preliminary determination that the Village of Waterbury's proposed project does not need to be licensed or exempted from licensing.

Most new hydropower projects in the U.S. cannot be developed without approvals from the Federal Energy Regulatory Commission, but the Hydropower Regulatory Efficiency Act of 2013 streamlined the process for certain "qualifying conduit hydropower facilities."  If a facility meets defined criteria and goes through an expedited regulatory process, it can be developed and maintained without requiring a license or exemption issued by the Commission.  Criteria for qualifying include:
  1. The facility must generate electric power using only the hydroelectric potential of a non-federally owned conduit. 
  2. The facility has an installed capacity that does not exceed 5 megawatts.
  3. The facility was not licensed or exempted from the licensing requirements of Part I of the FPA on or before August 9, 2013.
For this purpose, a conduit is any 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 primary purpose of the conduit is thus critical to qualification: the conduit cannot be primarily for power production, but must be primarily for water distribution.

If a developer proposes to develop a qualifying conduit hydropower facility, federal law generally requires that developer to file a Notice of Intent with the Commission.  Commission staff will make an initial determination (either to reject the notice of intent or to determine the facility meets the qualifying criteria) within 15 days.  If that initial determination is that the facility meets the qualifying criteria, the Commission will issue a public notice providing the public with 30 days to file motions to intervene and 45 days to provide comments contesting the qualification.

A docket pending before the Commission illustrates its process for evaluating conduit project notices.  On August 4, 2017, the Village of Waterbury filed a notice of intent to construct a qualifying conduit hydropower facility.  According to its filing, it proposes to install a 4-kilowatt turbine-generator in a pressure relief valve vault connected to the village's drinking water system.  The project's estimated annual power generation is 35,600 kWh/year at 100% capacity.

Less than one week after the village filed its notice of intent, on August 10 the Commission issued its Notice of Preliminary Determination of a Qualifying Conduit Hydropower Facility and Soliciting Comments and Motions to Intervene.  According to that notice, Commission staff preliminarily determined that the proposal satisfies the requirements for a qualifying conduit hydropower facility, which is not required to be licensed or exempted from licensing.  In particular, staff noted that the proposed project would utilize an existing potable water pipeline, whose primary purpose would continue to be conveying drinking water to the Village of Waterbury.

Like the Village of Waterbury, water districts and other owners of water pipelines are considering whether developing an in-conduit hydropower project makes sense for their needs.  Where an existing system uses pressure relief valves, replacing a PRV with a turbine-generator can add value.  In the Waterbury case, the Village appears poised to "net meter" the project's output against its own load under Vermont utility tariffs.  Combining incentives -- in this case, the streamlined federal permitting process for conduit hydro plus the state net metering program -- may further enhance the value proposition.

AMC's Zealand Falls Hydroelectric Project

Monday, August 14, 2017

Miles from the nearest road in the woods of the White Mountain National Forest in New Hampshire sits a backcountry hydropower project.  Owned by the Appalachian Mountain Club, the Zealand Falls Hydroelectric Project No. 14657 is licensed to generate 2.5 kilowatts of power, using Whitewall Brook on federal land within the White Mountain National Forest.  The project provides power to licensee Appalachian Mountain Club's Zealand Falls Hut, a year-round backcountry facility constructed in 1932 which provides overnight lodging for about 6,000 hikers and skiers.  Visitors can learn about the hut's power systems first-hand, with additional information coming from public records.
While the Zealand Falls Hut is not connected to the utility grid, it uses on-site distributed generation (including solar, wind, and the licensed micro-hydro system) to charge batteries and to power a well water pump, refrigerator, freezer, lights, radio, fire system, and other electrical equipment.

According to the AMC's December 29, 2014 application to the Federal Energy Regulatory Commission for a hydropower license, the Zealand Falls hydro unit was originally installed in 1981 with funds from a U.S. Department of Energy demonstration grant.  The application describes its original project objective as "to provide an alternative energy source for the AMC's Zealand Falls Hut that would a) enhance public awareness of renewable energy sources; b) conserve fossil fuel by decreasing propane consumption; and c) reduce the reliance on helicopters that are used to airlift propane tanks in and out of this backcountry hut used by the public."  In 2011, the AMC replaced the hydroelectric generator and some other systems, with the effect of reducing water diversion.

Under section 23(b)(1) of the Federal Power Act, a non-federal hydroelectric project must be licensed (unless it has a still-valid pre-1920 federal permit) if it:
(a) is located on a navigable water of the United States;
(b) occupies lands or reservations of the United States;
(c) utilizes surplus water or waterpower from a government dam; or
(d) is located on a stream over which Congress has Commerce clause jurisdiction, is constructed or modified on or after August 26, 1935, and affects the interests of interstate or foreign commerce.

The White Mountain National Forest is a federal "reservation" managed by the U.S. Forest Service. On December 29, 2014, AMC filed its application to operate and maintain its existing off-grid micro-hydro project.  The Commission granted AMC's application by order dated August 12, 2015.
According to the order issuing license, the Zealand Falls Project features a natural bedrock pool from which a 3-inch-diameter intake pipe diverts water through a settling tank and penstock feeding a single turbine-generator unit with an installed capacity of 2.5 kW.  Water is returned to Whitewall Brook below the turbine, about 1300 feet below the diversion.  The project is licensed to operate in a run-of-river mode during the ice-free period (typically May to October).

According to the order, the levelized annual cost of operating the Zealand Falls Project as licensed is "about $585.78, or $579.98/MWh."  Based on an estimated annual generation of 1,010 kilowatt-hours, the Commission found "the project would produce power valued at $117.00."  This is several times higher than the cost of power delivered by the utility grid, and almost 3 times higher than the cost of producing alternative energy from a propane-fueled generator with a current average cost of propane fuel of $2.65 per gallon."  At the same time, the order notes that the project may achieve public interest values beyond project economics.

Deepwater Wind proposes offshore wind, battery storage for MA RFP

Friday, August 4, 2017

Massachusetts energy regulators are reviewing bids to supply clean energy from new sources -- including a combined offshore wind and energy storage project proposed by developer Deepwater Wind.

Rhode Island-based Deepwater Wind is the developer of America's first commercial offshore wind project, the 30 MW Block Island Wind Farm which began commercial operations in December 2016. Other projects in early-stage development by the company include the 90 MW South Fork Wind Farm serving Long Island and the 120 MW Skipjack Wind Farm serving Maryland.

Earlier this year, prompted by 2016 state legislation, the Massachusetts electric distribution companies, in coordination with the Massachusetts Department of Energy Resources, issued a Request for Proposals for Long-term Contracts for Clean Energy Projects pursuant to Section 83D.  Through the RFP, the Massachusetts utilities solicited proposals for clean energy generation in an amount roughly equal to 9,450,000 MWh.

According to Deepwater Wind, it responded to the Massachusetts clean energy RFP by proposing the Revolution Wind farm, paired with a battery storage system.  The company's prime proposal features 144 MW of wind generation, coupled with a 40 MWh battery system, which it says will "help to defer the need to construct costly new peaking generating facilities and controversial transmission lines."  The project would be sited on the Outer Continental Shelf off Massachusetts, about 30 miles from the mainland and about 12 miles off Martha's Vineyard, under a lease from the federal government.  It would be adjacent to Deepwater Wind’s South Fork Wind Farm.  Emphasizing flexibility and scalability, as well as the ability to complete construction in one season, alternative bids submitted by the company envisioned a larger 288 MW version of Revolution Wind and a smaller 96 MW version.

Deepwater Wind says it also intends to submit an offshore wind proposal under a separate solicitation process under way in under Section 83C of Massachusetts law, with bids due by December 2018.

SC utilities to suspend nuclear construction

Wednesday, August 2, 2017

Two South Carolina utilities have announced their decisions to cease work on two new nuclear units under construction at the V.C. Summer Nuclear Station in Jenkinsville, South Carolina.

The project to develop Units 2 and 3 at the V.C. Summer plant was led by contractor Westinghouse Electric Co. LLC, but has experienced years of delay and billions of dollars in cost overruns.  Westinghouse filed for Chapter 11 bankruptcy protection in March 2017, placing the project's future in question.

On July 31, 2017, South Carolina Electric & Gas Company (SCE& G), principal subsidiary of SCANA Corporation (SCANA) and owner of 55% of the plant under construction, announced that it will cease construction at the V.C. Summer site "and will promptly file a petition with the Public Service Commission of South Carolina seeking approval of its abandonment plan." According to a press release, "SCE&G concluded that it would not be in the best interest of its customers and other stakeholder s to continue construction of the project."  Factors cited in SCE&G's press release include "the additional costs to complete the Units, the uncertainty regarding the availability of production tax credits for the project, the amount of anticipated guaranty settlement payments from Toshiba Corporation (Toshiba), and other matters associated with continuing construction , including the decision of the co-owner of the project , the South Carolina Public Service Authority (Santee Cooper), the state owned electric utility, to suspend construction of the project."

Project co-owner Santee Cooper also issued a press release on July 31 announcing its decision to suspend construction of the units.  Santee Cooper cited "a comprehensive analysis of detailed schedule and cost data, from both project contractor Westinghouse Electric Co. and subcontractor Fluor Corp., first revealed after Westinghouse, filed for bankruptcy in March."  According to Santee Cooper, to date it has spent about $4.7 billion in construction and interest costs, but its analysis shows the project would not be finished until 2024 (four years later than Westinghouse's latest estimate) for a total cost to Santee Cooper's customers of $11.4 billion.

The V.C. Sumner project was one of two new nuclear projects under commercial development in the U.S.  The other project, at Plant Vogtle, was also being developed by Westinghouse.  Its fate remains uncertain.

Hatteras Island power outage and response

Tuesday, August 1, 2017

North Carolina's Hatteras Island experienced a power outage last week when construction activity damaged two underground transmission cables serving the island.  While the damage is repaired, residents face mandatory power conservation rules and visitors have been evacuated.

Hatteras Island is a barrier island located in North Carolina's Outer Banks.  While the island is relatively far offshore, it is connected to the northern Outer Banks islands by the Bonner Bridge.  Hatteras Island's roughly 4,000 residents and tens of thousands more seasonal visitors are supplied electricity by Cape Hatteras Electric Cooperative, a member-owned, not-for-profit electric distribution cooperative.

According to the cooperative, on July 27 a contractor building a replacement for the Bonner Bridge "accidentally drove a steel casing through the cooperative’s transmission cables" at the south side of the bridge.  The cooperative says it is taking steps toward both temporary and permanent solutions. For now, it is using a permanent diesel generator in the village of Buxton as well as temporary backup diesels to provide power to the island and is "working to expand the temporary generation service on Hatteras Island in order to accommodate a staged reentry of visitors." Meanwhile, the cooperative is working to splice the damaged underground cable and to build a new overhead transmission line, so permanent transmission service can be restored.

Calling the incident an "unprecedented complete loss of power delivery to Hatteras Island," Dare County issued a mandatory evacuation order for all visitors to Hatteras Island effective July 29, citing "life safety issues from the loss of reliable electrical power on Hatteras Island and growing uncertainty as to when repairs to the main transmission line will be completed to enable restoration of full power to the island."  Estimates suggested over 10,000 visitors have been kept off Hatteras Island as a result of the evacuation order, with proper credentials required for reentry.

According to the county's website, a complete repair might take from one to two weeks.  The county notes that the on-island diesel generators "will only be able to run if load is at minimal levels and everyone is conserving." The county cites mandatory power and water conservation measures in effect, including a requirement to disconnect system circuit breakers for air conditioning systems and hot tub heaters.

California grid prepares for solar eclipse

Monday, July 31, 2017

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

Thursday, July 27, 2017

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). 

FERC issues license for Monongahela Locks and Dam 4 project

Wednesday, July 26, 2017

U.S. hydropower regulators have issued an original license for a proposed 12-megawatt hydropower project, to be located at the U.S. Army Corps of Engineers’ Monongahela Locks and Dam 4 facility on the Monongahela River, in Pennsylvania.

On February 27, 2014, FFP New Hydro, LLC subsidiary Solia 4 Hydroelectric, LLC filed, pursuant to Part I of the Federal Power Act, an application for a license to construct, operate, and maintain the Monongahela Locks and Dam 4 Hydroelectric Project No. 13767.  The company is affiliated with US Renewables Group.

The project would be located at one of the nine existing lock and dam sites on the Monongahela River, which the Army Corps operates for commercial and recreational navigation.  If developed, new facilities for the project would include an intake channel, spill gates, a powerhouse housing two equally sized Kaplan turbine-generator units with a combined capacity of 12 MW, a tailrace channel, a substation, a transmission line, and an access road.  The project will operate in a run-of-release mode, using flows made available by the Corps that would normally be released through the Corps’ spillway gates

Under the Federal Power Act, the Federal Energy Regulatory Commission is charged with regulating and reviewing applications for most non-federal hydropower projects.  Because the project uses the water power or surplus water of a government dam, occupies federal land, and is located on the Monongahela River, which is a navigable waterway of the United States, the Commission concluded that the project is required to be licensed pursuant to section 23(b)(1) of the Federal Power Act.

On July 21, 2017, the Commission issued its Order Issuing Original License for the Monongahela Locks and Dam 4 project.  The license authorizes the installation of 12 MW of new, renewable energy capacity, while requiring a number of measures to protect water quality, fish, wildlife, recreation, and cultural resources at the project.  It bears a 50-year term, the maximum allowable for an original license under Section 6 of the Federal Power Act.

According to the order, as licensed with mandatory conditions and staff-recommended measures, the levelized annual cost of constructing and operating the project will be about $3,563,340, or $72.88/MWh.  Its expected average annual generation will be 48,894 MW. 

The Commission noted that the project as licensed is best adapted to a comprehensive plan for improving or developing the Monongahela River, "because: (1) issuance of an original license will serve to provide a beneficial and dependable source of electric energy; (2) the required environmental measures will protect and enhance fish and wildlife resources, water quality, recreation resources, and historic properties; and (3) the 12 MW of electric capacity will come from a renewable resource that does not contribute to atmospheric pollution."

Commercial building efficiency opportunities

Thursday, July 20, 2017

A report prepared for the U.S. Department of Energy by the Pacific Northwest National Laboratory found that the nation's commercial building sector has significant potential to save energy by improving control measures and eliminating common HVAC faults.

The May 2017 report, "Impacts of Commercial Building Controls on Energy Savings and Peak Load Reduction", notes that commercial buildings in the U.S. consume approximately 18 quadrillion British thermal units (quads) of primary energy annually.  While previous studies have suggested significant potential for energy savings by deploying sensors and controls, the lab says its report is the first to provide a comprehensive estimate of the national energy savings potential available by fixing building operational problems with efficiency measures.

Overall, after considering a variety of commercial building types and hypothetical sensitivity cases, the report estimated the annual building energy savings from energy efficiency measures to be 29%, and the "best estimate" of total primary energy savings to be 2.74 quads.  According to the lab's model, three building types -- secondary schools, standalone retail, and retail dealership -- each achieved more than 40% savings nationally.

Overall, the report concludes "that commercial building controls improvements are strategically important to meet and sustain reductions in national energy consumption."