FERC proposes revoking hydro license for noncompliance

Wednesday, February 28, 2018

U.S. hydropower regulators have proposed revoking a Michigan hydroelectric project's license under the Federal Power Act, following findings of violations of numerous license provisions, agency regulations and orders.

At issue is the Edenville Hydroelectric Project, No. 10808, located on the Tittabawassee and Tobacco Rivers by Wixom Lake in Michigan. The Federal Energy Regulatory Commission initially issued a license for the 4.8-megawatt Edenville project in 1998. That license was eventually transferred to a company named Boyce Hydro Power, LLC.

According to public records in the Commission docket for the license, "Boyce Hydro has a long history of non-compliance" with license terms and conditions and with related provisions in the Federal Power Act and Commission regulations and orders. Orders in the docket recite history including a 2017 Compliance Order finding noncompliance with respect to the adequacy of the project's spillway capacity and other matters. As noted in the docket, "The Commission’s primary concern has been the licensee’s longstanding failure to address the project’s inadequate spillway capacity, which currently is designed to pass only approximately 50 percent of the PMF. Failure of the Edenville dam could result in the loss of human life and the destruction of property and infrastructure."

The Commission has tools that it can use to compel compliance with its laws and regulations. For example, on November 20, 2017, Commission staff issued an order requiring the licensee to cease generating at the Edenville Project.

Beyond ordering the project to stop generating power, the Commission can revoke a license. Section 31(b) of the Federal Power Act allows the Commission to issue an order revoking a license, after providing notice and an opportunity for an evidentiary hearing, if it finds that a licensee knowingly violated a final compliance order and was given a reasonable time to comply with that order before the revocation proceeding was commenced. 

On February 15, 2018, the Commission issued an Order Proposing Revocation of License in the Edenville project's docket. In that order, the Commission noted that the licensee "has failed for many years to comply with significant license and safety requirements, notwithstanding having been given opportunities to come into compliance... The licensee failed to meet nearly all the obligations in the compliance order, even after Commission staff granted multiple extensions."

The Commission noted that public safety "would not be affected by revoking the license." It noted that if the Commission were to revoke the license, its jurisdiction would end, and authority over the site will pass to the State of Michigan’s dam regulatory authorities.

The Commission also noted that revocation of the project license "does not mandate removal or any modification of the dam," citing both its broad authority under the Federal Power Act and its general policy not to condition the effectiveness of a license revocation on a licensee that has shown its unwillingness to comply with other Commission orders.

The Commission set a 30-day deadline within which the licensee may request an evidentiary hearing before an Administrative Law Judge, after which the Commission will decide the matter.

Archimedes screw small hydro in CT

Monday, February 26, 2018

Combining old and new, a recently built hydropower project in Connecticut is demonstrating the capability of a modern turbine design based on ancient screw-like technology -- while using commercial and regulatory structures including a virtual net metering power purchase agreement and green bond financing.

At issue is the Hanover Pond Dam Hydroelectric Project, developed by New England Hydropower Company, LLC. Originally described in a 2013 application to the Federal Energy Regulatory Commission for a preliminary permit and the Commission's subsequent order issuing preliminary permit, the project is located on the Quinnipiac River in Meriden, Connecticut. The run-of-the-river project uses the water power potential of the pre-existing Hanover Pond dam, plus new facilities including a 46.5-foot-long, 11.65-foot-diameter 220-kilowatt Archimedes screw turbine-generator unit. While screws have been used to pump water for over 2,000 years, some modern developers of small hydropower projects are turning to screw turbines in the hopes that they can produce power in a cost-effective and environmentally acceptable manner.

Financed with a combination of public and private capital, including the first official "Green Bond" issued by the Connecticut Green Bank, the Hanover Pond Dam project has been described as the first commercial Archimedes screw design placed into service in the U.S., although similar technology has been deployed at other sites around the world.

On May 19, 2016, the Commission issued an order granting the project an exemption from licensing under the Federal Power Act. The Hanover Pond project was built and placed into service last year. On February 23, 2017, the project gave notice that it would commence commercial generation later that spring, and entered commercial operation in April 2017. The project sells its estimated 920,000 kilowatt-hours of annual power production to the host municipality under a 20-year power purchase agreement designed to fit within Connecticut's virtual net metering regulations.

Operational considerations matter too. According to an article posted by the local Record Journal, earlier this month "a malfunction with the Archimedes screw caused a loud noise and smoke, damaging the hydroelectric dam’s generator." A subsequent incident report filed by the company has not been made public, but an accompanying public cover letter references a "February 5, 2018 sluice gate malfunction."

The Hanover Pond Dam project illustrates some of tensions facing small hydropower projects today, and the challenge of packaging a site with appropriate technologies, commercial arrangements and regulatory structure. Society already has a number of existing dam sites which could be redeveloped to generate hydroelectricity. Technologies -- whether new or ancient -- can harness the power of water moving through or around those dams. Commercial arrangements and regulatory structures -- like green banks and green bonds, power purchase agreements, and virtual net metering regulations -- can make or break a project. At the same time, hydropower operators must remain focused on practical concerns for safe and reliable operation.When it all comes together, it can be win for the community and for the developer.

FERC distributed energy resource technical report

Wednesday, February 21, 2018

A technical report by U.S. electricity regulatory staff assesses the potential reliability issues and likely benefits to the bulk power system resulting from an increased penetration of distributed energy resources. According to the report, increasing penetration of distributed energy resources may bring several associated reliability benefits to the bulk power system -- or could cause reliability concerns, if the resources are not properly accounted for.

Distributed energy resources, or DERs, have no single definition -- but they are generally conceived of as small, geographically dispersed electric resources, installed and operated on the distribution system at voltage levels below the typical bulk power system levels of 100kV. Historically, the term focused on generation like rooftop solar panels or on-site combined heat and power plants, but its meaning has broadened to include energy efficiency, microgrids, and even new technologies like energy storage. Distributed energy resources can be cost-effective alternatives to traditional utility infrastructure and business models.

Distributed energy resources installations have increased significantly in some regions of the United States in recent years thanks to factors including technology advances and state energy policies. In 2016, when distributed energy resources of all types accounted for about two percent of the nation's installed generation capacity, distributed solar photovoltaic (PV) installations alone represented over 12 percent of new capacity additions.  At the same time, regulators and industry participants are working to integrate these resources into the grid from engineering, reliability, and system planning perspectives.

In February 2018, staff of the Federal Energy Regulatory Commission published a report, "Distributed Energy Resources: Technical Considerations for the Bulk Power System." This report filed in Docket No. AD18-10-000 considers how the increasing penetration and integration of distributed energy resources in specific regions may affect bulk power system reliability. It summarizes technical assessments performed by Commission staff using industry power system models and commercially available power system simulation software "to identify the potential reliability issues and likely benefits to the bulk power system" from increasing distributed energy resource penetration. The study notes that its modeling of distributed energy resource capacity was "based on current trends for technology types, operational capabilities, and deployment distributions."

According to the report, greater penetration of distributed energy resources could have associated reliability benefits for the bulk power system. For example, by providing power close to the customer distributed resources can serve to reduce grid losses and reduce system peak load, or can serve as non-transmission alternatives that displace the need for more expensive wires upgrades.

At the same time, the report warns that "increasing DER capacity, if not properly accounted for, could cause reliability concerns for the bulk power system." It calls for improving and refining the data that is available for distributed energy resources for incorporation into planning and operating models, noting, "Collecting and using the most current and accurate data is key to getting a complete picture of how DERs affect the bulk power system."

The report identified key bulk power system reliability topics to explore in light of the growing adoption of distributed energy resources in the U.S., including:
  • The impact of the current common industry modeling practice of netting DERs with load, which may mask the effects of DER operation;
  • DER capabilities for voltage and frequency ride through during contingencies;
  • The potential for improved voltages due to the unloading of the bulk power system associated with the location of DERs at or near customer loads;
  • Potential effects upon system -wide transmission line flows and generation dispatch due to changing load patterns;
  • The sensitivity of voltage or power needs to different types of DER applications (i.e., providing energy, capacity, or ancillary services);
  • The need to develop planning processes that capture more detailed models of DERs and allow for modeling of the interface between the transmission and distribution systems to enable information exchange and more accurate calculations of the DER impact on the bulk power system; and
  • The advantages and disadvantages of allowing DERs to participate directly in the organized wholesale electric markets.
The report also calls for continued examination of other issues, such as "sensitivities with higher DER penetration levels, changes in siting patterns, and potential impacts to the system’s response to events, disruptions and outages, including frequency events." It concludes, "Efforts such as these could help track and assess the impact of changing conditions on the bulk power system to identify emerging trends and address potential future reliability challenges."

FERC Order 841 and electric storage markets

Monday, February 19, 2018

U.S. energy regulators have issued a final rule designed to help electric storage resources participate in the capacity, energy and ancillary services markets operated by regional grid operators. The Federal Energy Regulatory Commission said its Order No. 841 would remove barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators.

Electricity storage technologies have been around for some time, and some technologies like pumped hydropower storage have been deployed on a significant scale -- but new electric technologies are developing on top of these traditional technologies. New England's regional grid operator recently cited fast-responding energy storage devices as among the new technologies entering its markets. Many states have recognized the opportunities created by storage, and are enacting incentives to support its development and integration into microgrids. At the same time, regulators are grappling with how to fit energy storage resources into existing markets and incentive programs, like retail net metering.

The Federal Energy Regulatory Commission has considered electric storage for some time, including stakeholder workshops, data requests, and technical conferences. The Commission expressed concerns that barriers to electric storage resources participation in organized wholesale markets could lead to unjust and unreasonable wholesale electricity rates. In November 2016, the Commission proposed a rule to facilitate electric storage resources' participation in organized wholesale markets. In January 2017, the Commission issued a policy statement addressing how electric storage resources may provide services at a mix of cost-based and market-based rates.

In issuing Order No. 841 on February 15, 2018, the Commission adopted a final rule requiring each RTO and ISO to revise its tariff to establish a "participation model" for electric storage resources. As envisioned by the Commission, these participation models will consist of market rules that facilitate electric storage resources' participation in organized wholesale markets, while recognizing storage resources' physical and operational characteristics.

The new rule provides that each RTO and ISO must adopt its own participation model for electric storage resources, within certain guidelines. First, the participation model must ensure that storage resources using it are eligible to provide all capacity, energy, and ancillary services they are technically capable of providing. Second, the participation model must ensure that participating storage resources can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer, consistent with rules that govern the conditions under which a resource can set the wholesale price. Third, the participation model must account for the physical and operational characteristics of electric storage resources through bidding parameters or other means Fourth, it must a minimum size requirement for participation in the RTO and ISO markets that does not exceed 100 kW.

The rule also requires that the sale of electric energy from the RTO or ISO market to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price.

In an accompanying statement, Commissioner LaFleur described electric storage as "like a 'Swiss army knife' that can serve customers in multiple ways," including including providing energy, particularly in conjunction with variable renewable generation (example: Deepwater Wind has proposed offshore wind plus storage in response to the pending Massachusetts offshore wind solicitation) as well as providing frequency regulation and other ancillary services, and helping defer distribution and transmission needs. Commissioner Powelson noted its consistency with the Commission's "longstanding commitment to fostering innovation and competition by reducing and eliminating barriers to entry." Commissioner Glick said Order No. 841 "will facilitate the development of a class of technologies—ranging from batteries to pumped hydro—that has the potential to play a leading role in the transition to the electricity system of the future, but that has heretofore been hindered by market rules that were designed primarily to accommodate more conventional means of electric generation."

Once it takes effect, the final rule gives RTOs and ISOs 270 days to develop and file their proposed rule changes, and a year for their implementation.

Maine considers hybrid, EV fees for highway fund

Saturday, February 17, 2018

A Maine legislative committee is considering a proposed law that would add a surcharge on the annual registration of hybrid and battery-electric motor vehicles, to raise money for the state's highway fund -- but as with previous efforts to raise fees on hybrid and electric vehicles, the 2018 proposal is facing opposition from some quarters as contrary to state policy.

At issue is a bill named, "An Act To Ensure Equity in the Funding of Maine's Transportation Infrastructure by Imposing an Annual Fee on Hybrid and Electric Vehicles." Also known as LD 1806, the bill would impose surcharges, dedicated to the Highway Fund, on the annual registration of a hybrid and battery-electric motor vehicles. It defines hybrid motor vehicle as an automobile or pickup truck powered by a combination of a fuel combustion engine and electric motor, and would impose a $150 annual fee on hybrids. It defines battery-electric motor vehicle as "an automobile or pickup truck the primary motive power of which is an electric motor," other than a low-speed vehicle, and would impose a $250 annual fee on battery-electric motor vehicles.

According to an analysis posted on Autoblog.com, if LD 1806 is enacted, the amount Maine electric vehicle (EV) and hybrid drivers would pay in lieu of gas taxes "would be tops in the nation."

Rather than imposing new fees on hybrids and electric vehicles, previous legislatures had extended tax exemptions to hybrid and clean fuel vehicles. State law supports the deployment and integration into the electric system of advanced electric storage and peak-reduction technologies, including plug-in electric and hybrid electric vehicles.

According to Maine's 2015 Comprehensive Energy Plan, at that time alternative vehicles remained a relatively small percentage of Maine’s vehicle fleet, but "the state should consider partnerships with large fleet owners to transition to alternative vehicles including natural gas, propane, and electricity."

But with the state highway fund facing a significant deficit relative to its budget in 2017, last year the legislature considered several bills that proposed raising fees on hybrid and electric vehicles to fund roads. One bill, LD 1226, An Act To Keep Maine's Transportation Infrastructure Safe by Providing More Sources of Revenue for the Highway Fund, would have imposed an annual registration fee of $250 on hybrid vehicles and $350 on electric vehicles, rather than the typical $35 annual fee for passenger vehicles.

Last year the legislature did not enact LD 1226, but it did carry over a similar bill for further action in 2018. LD 1149, An Act To Provide Revenue To Fix and Rebuild Maine's Infrastructure, would impose a $200 surcharge, dedicated to the Highway Fund, on the registration of hybrid motor vehicles, battery-electric motor vehicles and hydrogen fuel cell motor vehicles. LD 1149 was carried over by the legislature for further action this year and could be taken up again, although the more recently printed LD 1806 covers similar ground.

The committee heard testimony on LD 1806 on February 13, 2018, much of which was critical of imposing new fees. According to the committee calendar, a work session on the bill is scheduled for February 22.

US intelligence threat assessment on cyber, energy, infrastructure risks

Friday, February 16, 2018

The U.S. intelligence community has released an unclassified report presenting its assessment of the global context and how threats could affect U.S. actions. The latest Worldwide Threat Assessment finds increasing risk of cyber attacks and threats to U.S. infrastructure, as well as impacts from climate change.

The 28-page report released February 13, 2018, Statement for the Record: Worldwide Threat Assessment of the US Intelligence Community, describes a variety of global and regional threats.

While a disclaimer notes that the order of topics addressed does not necessarily imply the relative importance or magnitude of threats covered in the report, the first category of global threat addressed is cyber threats. According to the assessment, "The potential for surprise in the cyber realm will increase in the next year and beyond as billions more digital devices are connected — with relatively little built-in security — and both nation states and malign actors become more emboldened and better equipped in the use of increasingly widespread cyber toolkits. The risk is growing that some adversaries will conduct cyber attacks — such as data deletion or localized and temporary disruptions of critical infrastructure — against the United States in a crisis short of war. "

Illustrating this threat, the report notes that state-sponsored cyber attacks against Ukraine and Saudi Arabia in 2016 and 2017 targeted multiple sectors across critical infrastructure, government, and commercial networks, including disruption of Ukrainian energy-distribution networks. The report projects that in the next year, "Russian intelligence and security services will continue to probe US and allied critical infrastructures."

The report also notes the complex global foreign intelligence threat environment facing the U.S. in 2018. While it identifies penetrating the US national decisionmaking apparatus and intelligence community as primary objectives for numerous foreign intelligence entities, the report notes that "the targeting of national security information and proprietary information from US companies and research institutions involved with defense, energy, finance, dual-use technology, and other areas will remain a persistent threat to US interests."

The report cites U.S. Energy Information Administration forecasts that 2018 West Texas Intermediate and Brent prices will average $58 and $62 per barrel, respectively, compared to $98 and $109 in 2013. Noting that oil prices have remained low since 2013, the report observes that oil-exporting countries continue to suffer from low prices, and that "their economic woes are likely to continue, with broader negative implications. Subdued economic growth, combined with sharp increases in North American oil and gas production, probably will continue putting downward pressure on global energy prices, harming oil-exporting economies." The report describes impacts of low oil prices on countries including Venezuela, Saudi Arabia and other Persian Gulf oil exporters, Angola, Nigeria, Russia.

The report also notes the existence and impacts of climate change. It observes, "Challenges from urbanization and migration will persist, while the effects of air pollution, inadequate water, and climate change on human health and livelihood will become more noticeable. Domestic policy responses to such issues will become more difficult — especially for democracies — as publics become less trusting of authoritative information sources."

According to the assessment, "The impacts of the long-term trends toward a warming climate, more air pollution, biodiversity loss, and water scarcity are likely to fuel economic and social discontent — and possibly upheaval — through 2018." It notes that the "past 115 years have been the warmest period in the history of modern civilization , and the past few years have been the warmest years on record." It cites extreme weather events in a warmer world as having the potential for greater impacts in the future, as well as increased challenges to government prompted by environmental concerns or water scarcity. The report also notes that nearly half the world's international river basins are exposed to gaps in the agreements governing water supply and dam development, exacerbating this concern.

ISO-NE 2018 Regional Electricity Outlook

Thursday, February 15, 2018

Regional electricity grid operator ISO New England, Inc. has released its 2018 Regional Electricity Outlook. According to the report, "the biggest challenge to the reliability of the grid is the lack of fuel infrastructure to supply the fleet of natural-gas-fired generators, further emission restrictions on oil-fired generation, and the reality that older oil and nuclear generators are becoming less economically competitive and may retire before the region has added sufficient new energy sources to replace them."

The report cites competitive forces has having "unleashed new approaches for producing electricity in a cleaner way and integrating technology that enables different types of resources to participate in the wholesale markets." It notes new resource types entering the wholesale market, including demand resources, and fast-responding energy storage devices.

With respect to energy supply, the 2018 outlook notes that the amount of wind and solar power in New England continues to grow "and is making a difference in how the ISO operates the power system and designs the wholesale markets." In 2017, the amount of new wind power seeking interconnection in New England surpassed proposed new natural-gas-fired generation for the first time, including significant amounts in Maine and offshore of Massachusetts.

On the demand side, it notes that significant investments in solar resources and energy-efficiency measures have moderated demand for wholesale electricity, but that electrifying the transportation and heating sectors to reduce their carbon emissions could lead to increased demand.

ISO-NE has previously identified the risk that power plants will run out of fuel as the foremost challenge to a reliable power grid in New England. Last month, ISO-NE released an operational fuel security study analyzing fuel security risks facing region's power plants under a wide range of hypothetical future scenarios. That report concluded that maintaining the electric grid's reliability "is likely to become more challenging, especially if current power system trends continue."

The 2018 Regional Electricity Outlook notes that while ISO-NE plays a role in addressing regional fuel-delivery constraints, "it will be up to market participants and state officials to take actions to secure forward fuel arrangements or bolster supply- or demand-side infrastructure." The report identifies potentially appropriate investments as including "enhancements to natural gas infrastructure or the supply chains for liquefied natural gas and oil; relaxation of rules to allow easier permitting and operation of dual-fuel resources; investments in even more renewable energy and any transmission needed to deliver it; or further measures to significantly reduce demand on the power system or the gas system," or some combination of these.

While reliability is core to the grid operator's priorities, the report acknowledges that New England's policymakers, businesses and citizens also value economic and environmental goals. The report specifically highlighted what it called "the reliability, economic, and environmental consequences of our situation: that regional action to resolve fuel-security risks will involve costly infrastructure investments and perhaps the retention of certain critical energy resources, but inaction will also come with a bill for high energy prices when energy supply is constrained—as well as the potential for greater risks to power system reliability and higher emissions."

FERC performance report and budget request

A U.S. energy regulatory agency has published a report detailing its fiscal year 2017 performance and requesting an appropriation of $369,9000,000 in funds from Congress for fiscal year 2019, to be offset by fees on regulated industries.

The Federal Energy Regulatory Commission or FERC is an independent regulatory agency, housed within the U.S. Department of Energy. The Commission has statutory jurisdiction over many aspects of the nation's wholesale electricity, natural gas, hydropower, and oil pipeline sectors. 

FERC's FY 2019 Congressional Performance Budget Request / FY 2017 Annual Performance Report describes the Commission's mission assisting consumers in obtaining reliable, efficient, and sustainable energy services at a reasonable cost through appropriate regulatory and market means. It recites the Commission's 3 goals: ensuring just and reasonable rates, terms and conditions; promoting safe, reliable, secure and efficient infrastructure; and mission support through organizational excellence.

The Commission recovers the full cost of its operations through annual charges and filing fees assessed on the industries it regulates as authorized by the Federal Power Act (FPA) and the Omnibus Budget Reconciliation Act of 1986, which requires it to “assess and collect fees and annual charges in any fiscal year in amounts equal to all of the costs incurred . . . in that fiscal year.” This revenue offsets the Commission's appropriation, resulting in a net appropriation of zero.

The report projects a FY 2019 appropriation of $369,900,000 "for necessary expenses of the Federal Energy Regulatory Commission to carry out the provisions of the Department of Energy Organization Act." This represents an increase of $2,300,000, or about 0.6%, over the Commission's FY 2018 budget request. The report describes its activity as requiring 1,465 full-time equivalents (FTEs) to execute its mission in FY 2019.

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

Tuesday, February 13, 2018

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.
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.

FERC hydro dam safety post-Oroville

As federal hydropower regulators examine how a California dam's spillway failed, an independent forensic team has released its final report on the Oroville Dam spillway incident -- and regulators have asked all other hydropower licensees to review the report and hold internal discussions on how the findings may apply to their own facilities and overall dam safety program.

Oroville Dam is a 770-foot high earthfill embankment dam on the Feather River in Northern California. Its service spillway was severely damaged during operations on February 7, 2017; water levels continued to rise, eventually overtopping and eroding the emergency spillway, threatening the stability of the structure on February 12, 2017.  Over 180,000 people were evacuated.

Following the incident, an independent forensic team studied the incident. The independent forensic team's report was released on January 5, 2018. It found that the incident "was caused by a long-term systemic failure of the California Department of Water Resources (DWR), regulatory, and general industry practices to recognize and address inherent spillway design and construction weaknesses, poor bedrock quality, and deteriorated service spillway chute conditions."

On January 26, 2018, the Commission published a letter to licensees presenting the Oroville Dam Independent Forensic Team's final report. In that letter, the Commission asked licensees and their Chief Dam Safety Engineers/Coordinators to "read this report, share it with your senior executives as well as all your dam safety staff and discuss how the findings may apply to your own facilities and overall dam safety program.

According to the Commission, that report concludes that flaws in the Oroville Dam Spillway existed since construction that were missed by the owner, regulators, and consultants. In the Commission's words, "It is very clear that just because a project has operated successfully for a long period of time does not guarantee that it will continue to do so." Emphasizing a safety-oriented corporate culture, the Commission also highlighted the report's finding that "compliance with regulatory requirements is not sufficient to manage risk and meet dam owners' legal and ethical responsibilities." The Commission's letter to hydropower licensees and exemptees highlights the importance of communication between dam safety staff and senior executives as part of an Owner's Dam Safety Program, and stated its expectation that regulated dam owners will have internal discussions to ensure facility safety.

Sabine Pass LNG tanks leaked, says regulator

Monday, February 12, 2018

U.S. regulators of natural gas infrastructure have issued an order requiring the owner of a liquefied natural gas terminal in Louisiana to remove part of that facility from service, following the discovery of unintended releases of LNG from the facility.

At issue is Sabine Pass Liquefaction, LLC's Sabine Pass Liquefaction Facility. The company is a subsidiary of Cheniere Energy, Inc. The Sabine Pass LNG terminal includes five LNG storage tanks with capacity of approximately 16.9 billion cubic feet equivalent (Bcfe), two marine berths that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d, adjacent to a series of liquefaction trains. The facility has received U.S. Department of Energy authorization for export of LNG by vessel.

According to a Corrective Action Order issued by the Pipeline and Hazardous Materials Safety Administration on February 8, 2018, on January 22, 2018, workers at the Sabine Pass plant discovered a release of LNG from a storage tank at the facility. The order states that LNG escaped from the tank into the annulus -- the space between the tank's inner and outer walls -- which eventually caused cracks in the outer tank wall and the pooling of LNG in a secondary containment area. It also says that the federal investigation into this incident discovered additional LNG releases from multiple cracks in another tank at the site, with evidence of "brittle failures" in the carbon steel outer tank wall.

The order says Sabine took steps upon discovery of the incident including commencing de-inventorying LNG from the tank, reducing system pressures, and deploying an emergency management team. Sabine reported no injuries or fatalities as a result of the incident, and there were no reported fires or explosions. The cause of the incident has not yet been determined.

The PHMSA order requiring corrective action includes a finding "that the continued operation of the Affected Tanks without corrective measures is or would be hazardous to life, property and the environment." It describes unintended releases of LNG as "rare ... low -frequency, high-consequence" events which "can result in a serious hazard to people and property." It notes, "To date, Sabine has been unable to correct the long-standing safety concerns described above involving the Affected Tanks, cannot validate the exact source or amount of the LNG that may have leaked into the annulus of the Affected Tanks, and cannot identify the circumstances that allowed the LNG to escape containment in the first place."

The order requires Sabine to develop a timeline and plan for removing the two "Affected Tanks" and their associated systems from service. A third tank is described in a footnote to the order as having experienced releases of LNG from the inner tank into the annular space, but is not included as one of the "Affected Tanks" covered by the order requiring corrective action. It requires Sabine to develop a work-plan including tank-specific purging plans, a root-cause analysis plan, a detailed repair and modification plan, a continuing operation plan for facilities that remain in service, and a plan to return the affected tanks to service, and prohibits Sabine from returning the affected tanks to service until authorized to do so by the Director of PHMSA.

GAO report on electric grid geomagnetic disturbances

Friday, February 9, 2018

A report released by the U.S. Government Accountability Office found that U.S. and Canadian electricity suppliers have taken steps to prepare for potential electromagnetic disruptions to the electric grid such as from solar storms or high-altitude nuclear detonations -- but that more research is needed on both geomagnetic disturbances and high-altitude electromagnetic pulses.

Under some circumstances, a severe solar storm or high-altitude nuclear blast could damage the U.S. electric grid and potentially cause extensive outages. Federal energy regulators have used both regulatory and more informal collaborative approaches to address the threat to the electric grid posed by electromagnetic pulses and geomagnetic disturbances. Regulatory approaches to electromagnetic disturbance readiness include mandatory reliability standards adopted by electric reliability organization NERC, which require some electricity suppliers to assess their vulnerability to extreme solar storms, and developing procedures for responding to grid security emergencies.

In this context, the Government Accountability Office was asked to review electricity industry actions to prepare for and mitigate electromagnetic risks. Its 95-page report, Critical Infrastructure Protection: Electricity Suppliers Have Taken Actions to Address Electromagnetic Risks, and Additional Research is Ongoing, examines topics including the degree to which U.S. and Canadian electricity generation and transmission owners and operators have identified information about the effects on the grid caused by geomagnetic disturbances and high-altitude electromagnetic pulses (HEMP), steps some suppliers have taken to protect against GMD and HEMP, and opportunities for U.S. suppliers to recover costs for protecting against GMD and HEMP.

According to the report, there is "general agreement that more research is needed on both GMD and HEMP." Risks identified include potential voltage instability leading to collapse of the bulk power system and blackouts, as well as possible damage to key system components. But more information is needed, according to the report -- especially on HEMP effects, given that previous studies have focused on impacts to military equipment as opposed to the commercial electric grid.

The cost of addressing reliability concerns can be significant. The GAO report describes some suppliers' reports "that costs they have incurred to protect against GMD and HEMP have been relatively small so far and they expect to recover those costs through customer rates." But the report warns that suppliers could face future increased costs, as a second regulatory standard phases in through 2022. For example, the report cites one supplier serving about 4.5 million retail customers as estimating "the cost of hardening a planned control center against HEMP to be at least $10 million." GAO calculated that fully passing this cost on to customers in a single year would add $2 to the average customer ’s electric bill for that year.

While regulated U.S. suppliers may be able to recover GMD protection costs through rates, the report notes that recovery is less certain for protection against HEMP because less is known about HEMP risks. The report also presages challenges for any kind of reliability-driven cost recovery for independent owners of power plants, who must recover reliability improvement costs through their sales of electricity without assurances about market prices.

NH SEC denies Northern Pass certificate

Thursday, February 1, 2018

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.