Crypto miner seeks to export US electricity for Canadian servers

In what has been called "a maiden effort by an energy-hungry cryptocurrency-mining industry to import electricity from the United States to Canada to meet its significant power demands", a Canadian company has applied to the U.S. Department of Energy for authority to export power from the U.S. into Canada to power blockchain-related computer servers -- but a nonprofit advocacy group has warned that federal approval of this "first-ever application to export power by a cryptocurrency miner" may result in a rush of similar applications.

Under U.S. federal law, the Department of Energy regulates exports of electricity from the United States to a foreign country, which require authorization under section 202(e) of the Federal Power Act. On May 21, 2020, DMG Blockchain Solutions Inc. filed an application with the U.S. Department of Energy, seeking authority under the Federal Power Act to transmit electric energy from the United States to Canada for a term of five years.

According to the website dmgblockchain.com, "DMG is a diversified cryptocurrency and blockchain platform company that is focused on the two primary opportunities in the sector – mining public blockchains and applying permissioned blockchain technology. DMG focuses on mining bitcoin, providing hosting services for industrial mining clients, earning revenues from block rewards and transaction fees, developing data analytics and forensic software products, working with auditors, law firms, and law enforcement to provide technical expertise, DMG’s permissioned blockchain technology is focused on developing enterprise software for the supply chain management of controlled products."

DMG's application to the Department of Energy describes the company as "a consumer of power, whose primary business is to host servers whose primary function is to ensure the security of public blockchains as well as other high-performance computing applications." DMG's application notes, "This business requires large amounts of power, which DMG is currently consuming approximately 15 megawatts on a steady load basis and has plans to grow to up to 60 megawatts in the next year with potentially larger amounts in the future as DMG may add new facilities." The application requests DOE export authorization over any of a long list of cross-border transmission facilities with Presidential Permits, in states including Maine, Vermont, New York, Pennsylvania, Michigan, Minnesota, North Dakota, Montana, and Washington.

But at least one entity has weighed in to urge the Department of Energy to proceed with caution, as it considers this request to export electricity to power foreign blockchain servers and computers. A Motion to Intervene and Comment filed with the Department of Energy on June 25, 2020, by watchdog organization Public Citizen, Inc. frames that organization's concern:

Despite cryptocurrency mining’s status as a relatively immature industry, its alarming power consumption footprint raises concerns about its sustainability and suitability in localized power markets, resulting in moratoria on new cryptocurrency mining operations issued by select U.S. utility districts and government agencies.

Citing language in Section 202(e) of the Federal Power Act requiring applications to export electricity to neither “impair the sufficiency of electric supply within the United States” nor “impede the coordination in the public interest of facilities subject to the jurisdiction of the Commission", Public Citizen commented:

Cryptocurrency mining is extraordinarily energy-intensive and can lead to major strains on local U.S. power supplies. At the same time, the process of mining is designed in a manner that wastes the overwhelming majority of the energy it consumes. U.S. cryptocurrency miners are struggling to meet their own power demands. This appears to be the first-ever application to export power by a cryptocurrency miner, and approval may result in a rush of similar applications.

Public Citizen's comments assert that this "maiden effort by an energy-hungry cryptocurrency-mining industry to import electricity from the United States to Canada to meet its significant power demands... raises serious, potentially fatal concerns under section 202(e)." Public Citizen concludes that the Department should proceed with extreme caution and "likely should deny the application or, if granting it, place conditions on it."

The pending export authorization proceeding before the U.S. Department of Energy is OE Docket No. EA-482, DMG Blockchain Solutions Inc. Application To Export Electric Energy.

PNGTS applies for Westbrook XPress Phase I pipeline project

An interstate natural gas pipeline system bringing gas from eastern Canada into Maine has asked U.S. regulators for approvals necessary for a project that would marginally increase the system's capacity to bring gas to Maine and the New England market.

At issue is Portland Natural Gas Transmission System (PNGTS), a pipeline that spans New England from the Canadian border to pipeline connections in New Hampshire, Maine, and Massachusetts. Its facilities include 142 miles of wholly-owned mainline from an interconnection with Trans-Québec & Maritimes Pipeline Inc. at the U.S./Canada border to Westbrook, Maine plus two laterals, as well as 101 miles of mainline from Westbrook to Dracut, Massachusets, which PNGTS owns jointly with another interstate pipeline, Maritimes & Northeast Pipeline, L.L.C. PNGTS operates pursuant to a number of federal approvals, including a certificate issued by the Federal Energy Regulatory Commission and a Presidential Permit authorizing its facilities for importing gas from (or exporting gas to) Canada.

On December 21, PNGTS applied to the Commission for authorization for Phase I its "Westbrook Xpress Project," which would increase the certificated capacity on the northern portion of its system from Pittsburg, New Hampshire, to Westbrook, Maine, by 42.482 million cubic feet per day (MMcf/d), effective November 1, 2019. The pipeline's application includes both public materials and materials that are protected against public disclosure as "controlled unclassified information", including privileged information and "critical energy infrastructure information."

In the public materials, PNGTS describes continued increased demand for natural gas: "Growing demand for natural gas for space heating, industrial processes and electric generation is driving a commensurate demand for incremental pipeline deliverability from abundant North American supply basins." PNGTS says its Westbrook XPress project "will provide access to, and allow for the transportation of, natural gas supplies from key North American supply basins such as Marcellus, Utica, and others" via Canadian pipelines. The company describes its Westbrook Xpress project is "a solution to meet this growing demand in areas of North America that have some of the highest residential gas prices in the winter." It envisions two distinct phases of the project: Phase I with an incremental 42.482 million cubic feet per day of certificated capacity, with an anticipated Phase II to bring an incremental 62.989 million cubic feet per day of capacity.

The Commission has docketed PNGTS's application for Phase I of the Westbrook XPress project as Docket No. CP19-32, and has issued public notice of the opportunity to intervene or comment through 5:00 pm Eastern Time on January 29, 2019.

Canada's Supreme Court rules for Quebec utility over energy contract

Canada's highest court has ruled that Quebec's provincial utility Hydro-Quebec cannot be required to renegotiate a long-term contract to buy power from a Labrador hydroelectric plant at below-market rates, even though the deal has yielded about 14 times more profit for Hydro-Quebec than for the Labrador generator.

At issue is the Churchill Falls hydroelectric plant on the upper Churchill River in Labrador, and a 1969 agreement between Hydro-Quebec and Churchill Falls (Labrador) Corporation Limited -- a company jointly owned by Newfoundland and Labrador Hydro and Hydro-Quebec. The Churchill Falls plant can generate 5,428 megawatts of power, and is one of the world's largest hydroelectric power stations.

According to former Premier of Newfoundland and Labrador Brian Tobin, during pre-construction negotiations, Hydro-Quebec told Churchill Falls that it would not allow the Labrador generator to "wheel" project power through the Hydro-Quebec grid, nor to build its own power line through Quebec to reach U.S. markets. As a result, under the terms of the 1969 agreement, Hydro-Quebec agreed to buy most of the project's power at the fixed price of $2.50 per megawatt-hour, to guarantee construction cost overruns, and to build transmission lines connecting the generators to markets, enabling the Labrador generator to sell power and to use debt financing to construct the plant. The original contract was set to expire in 2016, but included a renewal clause allowing Hydro-Quebec to extend the contract for an additional 25 years at a fixed price of $2 per megawatt-hour through 2041.

After the contract was signed, changes in the electricity market -- including oil price shocks in the 1970s, a decline in public confidence in nuclear power after a 1979 accident, and the U.S. Federal Energy Regulatory Commission's 1996 decision to require open access to transmission systems -- meant the contract's purchase price is now well below market prices. Because Hydro-Quebec sells electricity from the plant to third parties at market prices, Hydro-Quebec reaps substantial profits from the deal. For example, Hydro-Quebec reports that the average retail price for residential customers in St. John's, Newfoundland in 2018 is $120.30 per megawatt-hour. Canada's National Energy Board says the 2017 average wholesale prices for electricity imports were over $24 per megawatt-hour, with exports priced even higher at $38.58 per megawatt-hour -- over 19 times higher than the price Hydro-Quebec now pays Churchill Falls during the extended contract term. According to CBC, the contract has yielded about $28 billion in profits to Quebec, but just $2 billion for Newfoundland and Labrador.

Citing legal theories including a general duty of good faith, Nalcor Energy subsidiary Churchill Falls asked Canadian courts to order that the contract be renegotiated and the benefits be reallocated. After lower courts sided with Hydro-Quebec, the generator appealed to the Supreme Court of Canada.

On November 2, the Supreme Court of Canada rendered its judgment in the matter of Churchill Falls (Labrador) v. Hydro-Quebec. The high court found, by a 7 to 1 decision, for Hydro-Quebec, noting that the parties "bound themselves knowing full well what they were doing" and that Hydro-Quebec could insist on adhering to the contract despite the "unforeseen" increase in the power's market value.

The one dissenting judge characterized the contract as "relational" in nature, and thus said that both parties are subject to a duty of cooperation which Hydro-Quebec breached by failing to renegotiate and to more fully share the benefits of higher-than-expected market prices. He said that because "a profit imbalance of this nature and magnitude is beyond what the parties intended when they concluded the agreement", the parties had an implied obligation to cooperate in establishing a mechanism for the allocation of "extraordinary profits."

Maine Gov. LePage's 2018 State of the State and energy policy

Maine Governor Paul R. LePage delivered his final State of the State address this evening. Here's a recap of some of his remarks on energy policy in previous speeches of that sort.

• In 2012, Governor LePage described Maine’s high energy costs as "one of the largest inhibitors, if not the biggest obstacle to job creation." He advocated an energy policy encompassing "all forms of energy."
• Energy did not appear in his 2013 speech, according to a transcript provided by the Portland Press Herald.
• In 2014, Governor LePage noted that "heating and electricity costs remain a major obstacle," with homeowners spending nearly double the national average on heating, and high electricity costs posting challenges to attracting business. He described efforts to expand natural gas pipeline capacity from Pennsylvania, and to connect to clean energy resources in Quebec.
• In 2015, Governor LePage used his speech to argue for lower electricity rates and home heating costs, as well as changes to Maine’s renewable energy policies.
• In 2016, Governor LePage released his speech in the form of a letter to the state legislature. As in previous speeches, his 2016 letter mentioned energy issues as a focus for -- or obstacle to -- economic development. Arguing that Maine's electricity prices are not competitive, he criticized legislative mandates supporting "long-term contracts for above-market rates." He also called for expansion of linear infrastructure like natural gas pipelines into New England and electric transmission lines to hydropower resources in Canada.
• Last year, he returned to delivering the speech to the legislature orally. His 2017 address included a section on energy matters, in which he criticized the Public Utilities Commission's decision to amend its rules governing net energy billing. He called upon lawmakers to agree to lower energy costs, to lower carbon dioxide levels in the most cost-effective manner, and to reduce our demand for oil.

Addendum as of 9 PM: WMTW has posted a transcript of Governor LePage's 2018 State of the State speech on its website, as prepared. That draft covers topics including "skyrocketing property taxes," Medicaid expansion, and fiscal responsibility. It calls for increased investment in Maine and workforce development. It proposes bonds focused on commercializing technologies, as well as on research and development, saying, "We must invest in commercialization as we do in research." However the prepared remarks did not mention energy, nor does it directly reference energy policy.

Nevertheless, the Bangor Daily News reports that his remarks as delivered did address energy, calling for lower energy prices.

NH SEC denies Northern Pass certificate

The New Hampshire Site Evaluation Committee has unanimously voted to deny an application to develop a major new electric transmission line across that state, according to an article in the Union Leader. According to that article, the Committee felt the Northern Pass Transmission developer had not satisfied its burden under state law to show that the line's development would not “unduly interfere with the orderly development of the region.”

Northern Pass Transmission, LLC has proposed a 192-mile transmission line project capable of bringing 1,090 megawatts of power into New England. The project includes a new direct current (DC) transmission line from the Canadian border to a new converter terminal to be built in Franklin, New Hampshire, as well as a new AC transmission line connecting to the existing grid at a substation in Deerfield.

To develop the project, the developer needs approval from the New Hampshire Site Evaluation Committee in the form of a Certificate of Site and Facility. Northern Pass applied to the SEC for a certificate in 2015; the case before the Committee has been ongoing since then, with extensive testimony and hearings held last month.

Successful project development involves not just securing all required permits, but also finding or creating suitable commercial arrangements. While the project's siting application was pending, the project won some commercial success last week, when a group of Massachusetts utilities seeking to jointly procure clean electricity selected a Northern Pass-affiliated proposal to supply about 9,450,000 megawatt-hours per year from Canada. After reviewing over 40 bids, the bid committee selected the "Northern Pass Transmission, Hydro" option for negotiation of a final long-term power sales agreement under the state's Section 83D clean energy contracting program.

Today's decision by the New Hampshire Site Evaluation Committee relates directly to siting, not to commercial matters. The developer may be able to challenge the Committee's permitting decision. In the meantime, could the SEC decision affect the Northern Pass project's commercial fate? According to the Massachusetts 83D website, "If the bid selected to advance to contract negotiation at this stage does not successfully negotiate contracts, it may result in other bid(s) being selected to advance to contract negotiations." If the lack of SEC approval (for now) means Northern Pass does not successfully negotiate contracts with the Massachusetts utilities, it could open the door for other 83D bidders to move forward.

Energy East pipeline case suspended

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

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.

Vail Resorts announces sustainability, net zero plan

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

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

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

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

Atlantic Ocean oil development in Canada, U.S.

Canadian oil company Husky Energy has announced a decision to develop its West White Rose Project offshore Newfoundland and Labrador.  Meanwhile the U.S. National Marine Fisheries Service has proposed authorizing the take of marine mammals incidental to geophysical surveys in the Atlantic Ocean relating to hydrocarbon development.

Husky Energy is a Canada-based publicly traded energy company.  It is the operator of the White Rose field, discovered in 1984 about 350 kilometres east of St. John’s, Newfoundland and Labrador, in water depths of about 120 meters.  Commercial oil production from the main White Rose field began in 2005; since then, over 275 million barrels of oil has been produced.  Husky holds working interests in the main field as well as satellite fields.

The oil and gas industry is the largest contributor to Newfoundland and Labrador's gross domestic production.  Husky's May 28, 2017 announcement relates to its West White Rose development.  Husky says it and project partners Suncor Energy and Nalcor Energy – Oil and Gas will use a fixed wellhead platform, tied back to the SeaRose floating production, storage and offloading (FPSO) vessel. According to Husky, the tie-back to the SeaRose FPSO vessel "will enable the Company to maximize resource recovery," with "incremental operating costs are expected to be less than $3 per barrel over the first 10 years."  Husky expects a net project cost of $2.2 billion to first oil in 2022, and a gross peak production rate of approximately 75,000 barrels per day (bbls/day) in 2025. 

Meanwhile, U.S. regulators have proposed removing one obstacle to oil and gas prospecting in the Atlantic Ocean.  The U.S. National Marine Fisheries Service has published notice of five proposed authorizations for harassment or take of marine mammals incidental to geophysical surveys in the Atlantic Ocean.  The federal Marine Mammal Protection Act allows the Secretary of Commerce to permit the incidental, but not intentional, harassment or taking of small numbers of marine mammals by U.S. citizens who engage in a specified activity.  In 2014-2015, NMFS "received five separate requests for authorization for take of marine mammals incidental to geophysical surveys in support of hydrocarbon exploration in the Atlantic Ocean."  The applicants proposed "to conduct two-dimensional (2D) marine seismic surveys using airgun arrays" within the U.S. Exclusive Economic Zone "(i.e., to 200 nautical miles (nmi)) from Delaware to approximately Cape Canaveral, Florida and corresponding with BOEM’s Mid- and South Atlantic OCS planning areas, as well as additional waters out to 350 nmi from shore."

NMFS's proposal to issue the incidental take or harassment permits now faces public comment, before a final agency decision.

Fate of U.S.-Canada dam license in question

The holder of the U.S. federal hydropower license for a dam spanning the international border with Canada border has petitioned for approval to surrender that license, citing economic considerations.

At issue is the Forest City Project, located on the East Branch of the St. Croix River which forms the international boundary between the United States and Canada.  The Project operates under conditions set by the International Joint Commission (IJC) in accordance with the Boundary Waters Treaty of 1909, as well as a license issued by the U.S. Federal Energy Regulatory Commission.  The project currently operates under a license issued on November 23, 2015.  That 30-year license expires on October 31, 2045.

Licensed by the Commission as Project No. 2660, the project includes the U.S. portions of a 540-foot-long, 12-foot-high earth dam, an impoundment spanning several lakes, and appurtenant facilities. There are no generating facilities located at the project; rather, the Forest City Project operates as part of a headwater storage system along with two other projects licensed to Woodland Pulp -- West Branch Project No. 2618 and Vanceboro Project No. 2492.  Two hydroelectric generation projects are located downstream on the St. Croix River from these storage facilities, the unlicensed Grand Falls and Woodland hydroelectric projects.

On December 23, 2016, Forest City Project licensee Woodland Pulp LLC applied to the Commission to surrender its license.  A cover letter attached to that application states, "Woodland Pulp has determined that the high cost of operating the Project pursuant to the new FERC license renders the Project uneconomical." In the surrender application itself, the company cited license provisions including new operating restrictions on reservoir pool elevation, a reservation of the Commission’s authority to require additional fishways if so prescribed by the Secretary of the Interior, and a requirement to develop a Historic Properties Management Plan (HPMP), as adding risk or cost.  As noted in the surrender application, "After a comprehensive review of the conditions in the License, the minimal contribution to downstream power generation, and the significant added cost and increased complexity of the License, coupled with the loss of flexibility required to comply with the License, Woodland Pulp has concluded that it is not economic for the company to continue to operate the project.

As described by the Commission in an April 6, 2017 public notice of the surrender application, the licensee proposes to remove the gates on the west side of the spillway.  According to the licensee, removing these gates will return water flow to natural flow conditions, and the Forest City Dam will no longer act as the water control structure for East Grand Lake, nor will it use, obstruct, or divert international boundary waters.

The Commission has docketed the surrender application as P-2660-028, and set deadlines for comments, protests, and interventions in the case.

US, Canada grid security and resilience strategy

The governments of the United States and Canada have released a joint strategy for ensuring the security and resilience of their electric grid.  In recognition of the interconnected nature of the North American electric grid, the document, "Joint United States-Canada Electric Grid Security and Resilience Strategy," describes the nations' shared goals and objectives.  An action plan released alongside the strategy presents U.S. steps and milestones toward achieving the strategy's desired outcomes.

The joint strategy centers on a vision of "a secure and resilient electric grid that is able to withstand hazards and recover efficiently from disruptions."  Recognizing that this grid is made up of a variety of interconnected entities -- including federal, territorial, municipal, co-operative, and investor-owned and operated utilities -- the strategy identifies three overarching goals:

• Protect Today’s Electric Grid and Enhance Preparedness: A secure and resilient electric grid that protects system assets and critical functions and is able to withstand and recover rapidly from disruptions is a priority for the governments of both the United States and Canada.
• Manage Contingencies and Enhance Response and Recovery Efforts: The Strategy sets out a shared approach for enhancing continuity and response capabilities, supporting mutual aid arrangements such as cyber mutual assistance across a diverse set of stakeholders, understanding interdependencies, and expanding available tools for recovery and rebuilding. 
• Build a More Secure and Resilient Future Electric Grid: The United States and Canada are working to build a more secure and resilient electric grid that is responsive to a variety of threats, hazards, and vulnerabilities, including increased threats from climate change. To achieve this, the electric grid will need to be more flexible and agile, with an architecture into which new technologies may be readily incorporated.

Beyond the joint strategy, each participating country has also developed its own individual action plan describing steps and milestones toward the strategic goals.  The U.S. National Electric Grid Security and Resilience Action Plan was released concurrently with the Strategy.

The action plan is generally non-binding on the U.S., and it is unclear whether the incoming Trump administration would adopt the plan, as opposed to revising or scrapping it.  Nevertheless the joint U.S.-Canada grid security and resilience strategy and the U.S. action plan may inform future efforts to strengthen the North American electric grid against risk and disturbance.

Nova Scotia tidal turbine installed

A Canadian tidal power developer has installed a turbine at a test site in the Bay of Fundy. Cape Sharp Tidal's project off Nova Scotia could demonstrate the feasibility of larger-scale marine hydrokinetic power plants connected to the mainland electricity grid.

Cape Sharp Tidal is a joint venture between Canadian utility Emera Inc. and marine turbine manufacturer OpenHydro.  Its project entails a grid-connected 4-megawatt array consisting of two tidal turbines.  The project is located at the Fundy Ocean Research Center for Energy (FORCE) site.  Headquartered near Parrsboro, Nova Scotia, FORCE is Canada's leading research center for in-stream tidal energy, with demonstration berths, a grid interconnection capable of accepting tidal power, and environmental monitoring capabilities.

This week Cape Sharp Tidal deployed the project's first turbine-generator, a 2-megawatt OpenHydro unit.  In subsequent work, crews interconnected the turbine cable tail to the FORCE site's main interconnection cable, an existing 16MW subsea export cable connected to an onshore substation.

Previous efforts to develop hydrokinetic tidal energy projects in the Bay of Fundy have met with difficulty.  While the bay offers large and powerful tides, weather and sea conditions can prove challenging, as can obtaining environmental and regulatory approvals.  A test tidal turbine deployed in 2009 was quickly destroyed; the turbine installed this week was originally slated for installation earlier but was delayed due to concerns over impacts to fisheries and the environment.  This week's installation represents a concrete step forward for Canadian tidal power.

Cape Sharp Tidal intends to install and connect a second turbine at the FORCE site in 2017.  According to the developer, its future plans -- subject to regulatory and business approvals -- could include a commercial-scale project of up to 300 megawatts capacity within 15 years.

Northern Pass Transmission public utility status

New Hampshire utility regulators have issued an order conditionally authorizing Northern Pass Transmission LLC to operate as a public utility, with respect to its proposed 192-mile, high-voltage electric transmission line from Canada into New Hampshire.  The New Hampshire Public Utilities Commission's Order No. 25,953 approves a settlement agreement between the transmission line developer and Commission staff.  Among its conditions are requirements that NPT obtain all necessary permits, contribute $20 million over 10 years to support energy efficiency and clean energy initiatives, and hold New Hampshire electric ratepayers harmless from costs associated with the possible regional allocation of costs for a portion of the Northern Pass transmission line.

Proposed by two companies affiliated under the Eversource family -- Northern Pass Transmission LLC and Public Service Company of New Hampshire d/b/a Eversource Energy -- the Northern Pass line would include new direct current transmission lines and an AC-DC converter station.  A variety of federal and state approvals are required for the line's development, including certification of site and facility by the state Site Evaluation Commission, plus several approvals from the Public Utilities Commission.

NPT secured one of those approvals this month, in the form of Public Utilities Commission Order No. 25,953, which conditionally authorizes NPT to operate as a public utilities in municipalities along its route.  In the Order, the Commission found "that NPT has the necessary technical, managerial, and financial expertise to operate as a public utility."

The Commission next found that the terms and conditions of a settlement agreement between Commission staff and NPT "ensure that granting NPT authority to commence business as a public utility is for the public good."

• First, the Commission noted public benefit, in the form of transparency, from the fact that the settlement recites a list of applicable statutes and rules.
• Second, the settlement called for a $20 million public interest payment, to be paid in installments of $2 million per year over the first 10 years of the operation of the Northern Pass Project; the Commission noted that this payment "will benefit customers by allowing the Commission to direct the use of this payment to energy efficiency programs and clean energy projects under its supervision."
• Third, the Commission noted that its grant of public utility status is conditioned on NPT procuring all necessary approvals for the Northern Pass Project, including obtaining a certificate of site and facility from the SEC.
• Finally, the Commission noted a provision in the settlement that "NPT must hold New Hampshire electric ratepayers harmless from costs associated with the possible regional allocation of costs for a portion of the Northern Pass transmission line."  The Commission expressed a belief "that the rate treatment provision applicable to the DC portion of the line could constitute a significant benefit to ratepayers in the event the ISO-NE designates this portion as eligible for regional cost recovery.

On this basis, the Commission approved the settlement agreement in its entirety, adopted its conditions, and found that commencement of business as public utility subject to those terms and conditions will be for the public good.

Meanwhile, NPT continues to pursue other approvals, such as PUC approval for crossings of public waters, and the SEC certificate of site and facility itself.

Canada NEB starts Energy East pipeline review

Canada's National Energy Board has ruled that the applications are complete for the Energy East Pipeline Project and a related gas project.  This determination starts the NEB's review process, under which the Board must issue its recommendations to the Minister of Natural Resources within 21 months.

The National Energy Board is an independent federal regulator of several parts of Canada's energy industry, including the regulation of pipelines, energy development and trade in the Canadian public interest.

As envisioned by proponents TransCanada and Energy East Pipeline Ltd., Energy East would be a 4,500-kilometer pipeline that will transport approximately 1.1 million barrels of crude oil per day from Alberta and Saskatchewan to the refineries of Eastern Canada and a marine terminal in New Brunswick.  Some existing natural gas pipeline would be converted to oil transportation pipeline, while other facilities would be newly built.  The project is motivated in part by a relative surplus of Western Canadian crude production, with relatively few ways to ship that crude to refineries or ports.

The related Eastern Mainline Project entails about 279 kilometers of new gas pipeline and related components, designed to let TransCanada continue to supply gas after the proposed transfer of certain Canadian Mainline facilities to Energy East Pipeline Ltd. for conversion to crude oil service.

On June 16, 2016, the National Energy Board announced its determination that due to the interconnections between the applications, the Energy East and Eastern Mainline projects are more effectively assessed within a single hearing process, with one record, reviewed by one Panel of Board Members.   It also deemed the applications complete to proceed to assessment and a public hearing, starting the 21-month review process.

The Panel must submit a report to the Minister of Natural Resources recommending whether or not the projects should proceed, or on what conditions. This report is due no later than March 16, 2018.  According to the NEB, the process will include hearings, panel sessions, and assessments of the upstream greenhouse gas emissions associated with the project.

Vanceboro Dam Storage Project relicensed

The Federal Energy Regulatory Commission has issued a new license to Woodland Pulp LLC to continue operating and maintaining the Vanceboro Dam Storage Project.  Located on the East Branch of the St. Croix River along the Canadian border in Washington County, Maine, the FERC-licensed project operates as a water storage facility that provides flood storage and flow releases for downstream hydroelectric generation.

The 469-foot-long, 16-foot-high Vanceboro Dam and 178,000 acre-foot project impoundment span the U.S.-Canada border.  The project is subject to the Boundary Waters Treaty of 1909 which established the International Joint Commission (IJC), a bi-national agency with the mission of preventing and resolving disputes between the United States and Canada over boundary waters.

The Vanceboro project is part of the larger St. Croix River headwater storage system.  This system also includes the Forest City Project, located about 24 miles upstream on the East Branch of the St. Croix, as well as the West Branch Project.  Water flows into the Vanceboro project’s impoundment from the Forest City Project. The project operates in a store-and-release mode whereby water is stored during periods of high flow to reduce downstream flooding, and then released during periods of lower flow to increase generation at the downstream hydroelectric projects.   Generation associated with these projects occurs at the unlicensed Grand Falls and Woodland hydroelectric projects located downstream on the St. Croix River.  Collectively, these storage projects provide flood storage and helps to regulate and augment flows, resulting in increased generation at Woodland Pulp’s downstream hydroelectric projects.

The Federal Energy Regulatory Commission issued an original license for the United States portion of the Vanceboro project on April 4, 1966.  The project is docketed as No. 2492.  That original license expired February 29, 2016, so two years earlier the licensee filed an application to the Commission for a new license to continue operating and maintaining the project.  In the interim, Woodland Pulp operated the project under an annual license pending resolution of its FERC relicensing process. 

On March 22, 2016, the FERC released an order issuing a new license for the Vanceboro Project. The new license authorizes no new capacity, and requires what the Commission characterized as "a moderate amount of new environmental mitigation measures."  These include a mandatory prescription issued under section 18 of the Federal Power Act, relating to new upstream fish passage facilities for American eel, river herring, and landlocked Atlantic salmon.

Given the fact that the Vanceboro Project is operated in coordination with the recently-relicensed West Branch Project No. 2618 and Forest City Project No. 2660 which each received 30-year license terms within the past 5 months, the Commission similarly relicensed the Vanceboro project for a 30-year license term to allow coordination of all three projects during any future relicensing.

Based on the large number of FERC-licensed hydropower projects whose licenses will expire in the near future, regulators expect to see an uptick in relicensing activity for hydroelectric projects and dams.

Utah oil sands mine slowed

A Canadian company developing an oil sands mining and extraction project in Utah has announced a decision to "reduce the pace of field construction in order to maintain working capital flexibility," based on low oil prices.

Oil sands, also known as bituminous sands or "tar sands", are loose sand or partially consolidated sandstone saturated with a viscous form of petroleum called bitumen.  US Oil Sands Inc. is a Calgary-based company that describes itself as "focused on oil sands exploration and production in Utah."  Its wholly owned United States subsidiary US Oil Sands (Utah) Inc. has bitumen leases covering 32,005 acres of land in Utah’s Uinta Basin.

US Oil Sands' PR Spring Project area consists of 5,930 contiguous acres near the East Tavaputs Plateau in Utah.  According to the company, construction of Phase 1 of the PR Spring Project is approximately 85% complete with costs coming in below budget.  If completed, it would be the first U.S. oil sands mine to enter commercial production.

While the company has not yet entered production, US Oil Sands has described a proprietary extraction process using a citrus-based bio-solvent to extract bitumen from oil sands without the need for tailings ponds.  The company pitched this technique as different from traditional Canadian oil sands production in Alberta, where wastewater management is a controversial environmental challenge.  But the Utah proposal has drawn concern over impacts to groundwater flowing under the Book Cliffs

But the company said it conducted a detailed review of the project "in light of continued low oil prices and the closure of two key contractors’ Utah-based operations."  Specifically, the press release stated, "The low price environment has impacted the Project as two of the Company’s key contractors have closed their operations in Utah and have caused delays to the Project."  Indeed, spot prices for West Texas Intermediate have ranged near $30 per barrel in recent days, with U.S. crude futures falling below $30 earlier this year for the first time since 2003.  The press release also mentions that $10 million in previously-announced royalty financing had not closed, causing the company to explore other options including equity financing.

According to the press release, project work on the PR Spring Phase 1 project will continue at a reduced level, with an expected focus on "critical path items and areas that will lead to the most efficient restart of full construction operations in the future. In spite of delays and increased costs that will occur with restart of full construction operations, the Company is still targeting completion within the original US$60 million approved budget."

How will US Oil Sands survive the low oil price environment?  How will economic, environmental, or other factors affect the fate of Utah oil sands mining?

Energy in Maine's 2016 State of the State

Maine Governor Paul LePage has released his 2016 State of the State remarks in the form of a letter to the state legislature.  Among his top priorities detailed in the letter is addressing the high cost of electricity in the manufacturing and industrial sectors.  The eight-page letter also focuses on themes including welfare reform, lowering the income tax, reducing student debt and attracting youth, and fighting the drug crisis.

Energy issues appear in Governor LePage's letter as a focus for -- or obstacle to -- economic development.  In the letter, he repeats his position that "Maine's electricity prices are not competitive."  The letter criticizes legislative mandates supporting "long-term contracts for above-market rates" as adding $38 million in ratepayer costs.

The letter also addresses Maine's renewable energy policy, calling for support for Maine's biomass energy industry while criticizing the economics of wind and solar energy projects:

Socialists love to subsidize new wind and solar energy projects because they think it will save the earth, but that kind of expensive and inefficient energy benefits only a few wealthy investors, and our electrical generation is already one of the cleanest in the country. Instead, let's support the existing Maine-based biomass infrastructure that is already in place to take advantage of our plentiful natural resource: wood.

Indeed, references to socialism and socialists appear twelve times throughout Governor LePage's 2016 State of the State letter.  (A reference to Senator Bernie Sanders' candidacy for President?)

In his letter, Governor LePage also called for expansion of linear infrastructure like natural gas pipelines into New England and electric transmission lines to hydropower resources in Canada:

Meanwhile, my Administration continues to make progress working with other New England states to expand hydropower and natural gas into our region. Right now there is construction underway to expand our pipelines into New England, and clean and affordable hydropower is right next door in Quebec. It's time to switch off expensive energy. We must plug into the affordable reserves of nearby natural gas and hydropower. We must be willing to transmit hydropower to the states south of us.

These themes of energy infrastructure investment echo those playing out elsewhere in the Northeast U.S., as states explore expanded connections to natural gas from the Marcellus shale and Canadian hydropower.

Northern Pass files with NH SEC

The developer of the Northern Pass Transmission Project, a proposed high-voltage transmission line from Canada into New Hampshire, filed a formal application to New Hampshire regulators this week.

First proposed in 2009, the Northern Pass project would include about 190 miles of new direct current transmission lines and an AC-DC converter station.  Collectively, the project would be capable of importing over 1,000 megawatts of power from Canada into the New England electric grid.  Its formal sponsors are two companies affiliated under the Eversource family: Northern Pass Transmission LLC and Public Service Company of New Hampshire d/b/a Eversource Energy.

Early versions of proposal drew criticism and controversy over issues including siting, visual impacts, the potential use of eminent domain, and impacts to domestic renewable energy production.  After a series of public information meetings and other dialogue, Eversource released a revised route and plan in August 2015.

On October 19, Eversource announced that it had filed a formal application to the New Hampshire Site Evaluation Committee.  The Northern Pass Transmission application to the SEC is available on the project's website.  It describes a project cost estimate of $1.6 billion, and a capacity of 1,090 megawatts. 

The SEC was established by the state legislature for the review, approval, monitoring and enforcement of compliance in the planning, siting, construction and operation of energy facilities.  It includes members from the Public Utilities Commission, cabinet level commissioners, and two members of the public.  The SEC has jurisdiction to review applications for siting and construction of large-scale energy facilities and to issue a Certificate of Site and Facility enabling a project's development.  The process before the SEC is likely to play out through 2016.

Transmission line for Canadian imports advances

A proposed high-voltage direct current transmission line designed to import Canadian power into the New England grid has received a favorable environmental recommendation from the U.S. Department of Energy. 

The New England Clean Power Link is a high-voltage, direct-current transmission project proposed by TDI New England, a subsidiary of private transmission developer Transmission Developers Inc. and ultimately part of the Blackstone Group.

Designed to feed the New England market with up to 1,000 megawatts of electricity, the proposed $1.2 billion New England Clean Power Link project would feature two parallel cables approximately 5” in diameter, operating at a voltage of approximately 300 to 320 kV.  These HVDC lines would run about 154 miles.  Originating at a DC converter station in Quebec, the U.S. portion of the line would start at the international border in Alburgh, Vermont.  It would run beneath the bottom sediments of Lake Champlain for about 98 miles, then turn east and run over land (but underground, mostly under roadway rights-of-way and railway beds) to a terminal converter station in Ludlow, Vermont, where the power could flow onto the New England grid.

Federal law requires most infrastructure development for international trade in energy to apply for and receive a Presidential Permit before the project may be built.  TDI New England applied for the presidential permit in May 2014, and applied to the state of Vermont for permits in December 2014.

As part of the Presidential Permit process, the federal National Environmental Policy Act or NEPA requires the U.S. Department of Energy to evaluate the potential environmental impacts in the United Statesof the proposed action and the range of reasonable alternatives.  In this case, the proposed federal action is the issuance of a Presidential permit to the applicant, Champlain VT, LLC, doing business as TDI - New England, to construct, operate, maintain, and connect a new electric transmission line across the U.S.-Canada border in northern Vermont.

On June 3, the Department of Energy released its final draft Environmental Impact Statement or EIS for the New England Clean Power Link.  In that document, the Department found relatively minimal and short-term adverse environmental impacts from project construction, operation and maintenance. 

Once notice of the draft EIS is published in the Federal Register, the public will have 60 days to comment on its analysis.  The Department will also hold public informational meetings in Vermont regarding the project.  According to the EIS, TDI New England expects permitting will continue through mid-2016, with construction and in-service dates as early as 2018 and 2019 respectively.

Meanwhile, TDI is simultaneously pursuing other HVDC transmission lines from Canada into the Northeastern US, most notably the Champlain-Hudson Power Express -- another HVDC line beneath Lake Champlain but continuing on overland and under the Hudson River to a converter station in New York City.   The Champlain-Hudson Power Express won a Presidential Permit in 2014.

US Presidential Permits for cross-border infrastructure

As the U.S.'s international trade in energy grows, so too has interest in the process for securing a federally required approval known as a Presidential Permit.

A marker shows the route of a natural gas pipeline in Utah.

The construction, operation, and maintenance of infrastructure that crosses the U.S.'s border with Mexico or Canada -- think pipelines, transmission lines, and bridges -- generally requires prior authorization by the federal government in the form of a Presidential Permit.  How you obtain a Presidential Permit depends on the type of facilities in question, as permits may be issued by several federal agencies under different legal authorities.

Presidential permits for oil, petroleum products, and other liquids pipelines have been issued by the U.S. State Department since since the promulgation of Executive Order 11423 in 1968.  Executive Order 11423 provided that, except with respect to cross-border permits for electric energy facilities, natural gas facilities, and submarine facilities:

The Secretary of State is hereby designated and empowered to receive all applications for permits for the construction, connection, operation, or maintenance, at the borders of the United States, of: (i) pipelines, conveyor belts, and similar facilities for the exportation or importation of petroleum, petroleum products, coal, minerals, or other products to or from a foreign country; (ii) facilities for the exportation or importation of water or sewage to or from a foreign country; (iii) monorails, aerial cable cars, aerial tramways and similar facilities for the transportation of persons or things, or both, to or from a foreign country; and (iv) bridges, to the extent that congressional authorization is not required.

The State Department's Bureau of Energy Resources Office of Energy Diplomacy receives and processes permit applications for liquid product pipelines, including water and petroleum products.  The standard by which the Secretary of State reviews applications for presidential permits is prescribed by an executive order issued in 2004.  Executive Order 13337 directs the Secretary of State to authorize those border crossing facilities that the Secretary has determined would “serve the national interest."

By contrast, cross-border natural gas pipelines are regulated by the Federal Energy Regulatory Commission, while electric transmission infrastructure is regulated by the Department of Energy.  Section 3 of the Natural Gas Act requires any person desiring to export any natural gas from the United States to a foreign country or to import any natural gas from a foreign country to the United States to obtain an order from the Federal Power Commission authorizing it to do so.   Section 202(e) of the Federal Power Act requires any person desiring to transmit any electric energy from the United States to a foreign country to obtain an order from the Federal Power Commission authorizing it to do so.

Executive Order 10485 designated the FERC's predecessor agency, the Federal Power Commission, to receive applications for natural gas and electricity facilities.  When the Department of Energy Organization Act of 1977 eliminated the Federal Power Commission, it shifted most of the FPC's responsibilities to the FERC, but Section 402(f) of that act specifically reserved import/export permitting functions for the Department of Energy.  For facilities governed by the Department of Energy, the Presidential Permit process is governed by Part 205 of the Department's rules.  In 2006, the Department delegated its authority to issue Presidential Permits for natural gas pipeline border crossings to FERC, via DOE Delegation Order No. 00-004.00A.

Infrastructure projects subject to the Presidential Permit process range widely in type, scope, and controversy, from the proposed Keystone XL oil pipeline from Canada to the proposed Champlain Hudson Express high-voltage direct current electric transmission line.