Laos dam construction and collapse

A dam under construction in Laos as part of a hydropower scheme has collapsed, causing flooding and damage.

At issue is the Xe-Pian Xe-Namnoy project, a 410-megawatt hydroelectric power project under development for Xe-Pian Xe-Namnoy Power Company (PNPC). PNPC is a joint venture among the government of Laos and construction and power companies from South Korea and Thailand. The project, whose construction costs are estimated at about $1 billion, involves the construction of three primary dams to form reservoirs. Construction of the system was reportedly 90% complete, with commercial operation projected for 2019, and an agreement in place agreement to export 90% of project power to Thailand. The project has been touted for the degree of international investment involved, although some have criticized the project for insufficient local benefits.

From an engineering perspective, the project's primary dams impound water in a large reservoir. The project also includes three auxiliary "saddle dams" near several heads of the reservoir, essentially to prevent the reservoir from spilling down the impoundment's back side as it fills.

A map of the project, found at http://www.pnpclaos.com/index.php/en/project/maps

Project maps posted online by PNPC show saddle dams on three of the main reservoir's western branches.

Another project map found at http://www.pnpclaos.com/index.php/en/project/maps

One of these smaller saddle dams reportedly failed on July 23, 2018, allegedly due to severe rains. Saddle Dam D -- a facility 8 meters wide, 770 meters long and 16 meters high -- was built to support water diversion around the project's reservoir. But the structure reportedly fractured, causing water to spill downstream to the Xe Pian river outside of the project's intended path of water flow. According to the prime minister of Laos, at least 26 people have died and 131 are missing from the resulting flooding, and several villages .

Response and recovery actions are ongoing. The dam collapse highlights the importance of safety in dam construction and reservoir operations, as did the February 2017 failure of the Oroville Dam's spillway in California.

FERC proposes revoking hydro license for noncompliance

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.

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

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.

FERC dam license transfers, death and estates

What happens when an individual person dies holding a Federal Energy Regulatory Commission license for a hydroelectric project?  While their will may specify an heir for the dam and project works, the process of inheriting a licensed dam can involve both state estate law and a license transfer through FERC.

The Federal Energy Regulatory Commission licenses hydroelectric projects under Part I of the Federal Power Act.  The Commission's most recent list shows over 1,000 projects with licenses.  While most are held by corporate or public entities, about 25 licenses are held directly by named individuals.  Most of these projects licensed to individuals have relatively small authorized generating capacities, but once licensed their operation and transfer are governed by federal processes.

State law usually controls what happens to property owned by an individual upon his or her death.  Suppose the licensee's will provides that the licensed hydroelectric project is transferred to another person.   That provision may be valid as a matter of state law, but as a matter of federal law the license only transfers if the Commission approves the transfer.

Practically speaking, this can mean that the estate of the licensee needs to file an application to FERC for the transfer of the project license.  A recent application relating to the Pine Creek Hydroelectric Project in Montana illustrates this process.

The Commission initially issued a 50-year license for the Pine Creek project to Howard and Mildred Carter, on July 25, 1986, with a present authorized generating capacity of 373 kW.  After Howard Carter's death, Mildred Carter was the surviving licensee on the project.  After Mildred Carter's subsequent death, a Montana state court started the probate process through which the project would transfer to Mrs. Carter's son Allen.  In October 2015, the Carter estate applied to the FERC for transfer of the license to Allen.  The Commission issued a public notice of the application for transfer of license and solicited comments, motions to intervene, and protests, none of which were filed.

The Commission approved the Pine Creek project license transfer on January 8, 2016.  The order includes a finding that transfer of the license for this project is consistent with the Commission's regulations and is in the public interest.  Its approval of the transfer was contingent upon: (1) transfer of title of the properties under license, transfer of all project files including all dam safety related documents, and delivery of all license instruments to the inheriting licensee, which shall be subject to the terms and conditions of the license as though it were the original licensee; and (2) the heir acknowledging acceptance of the order and its terms and conditions by signing and returning an acceptance sheet.  The license transfer order required the new licensee to submit certified copies of all instruments of conveyance and the signed acceptance sheet within 60 days.

While direct inheritance of FERC-licensed hydroelectric projects is relatively rare, similar issues can arise when corporate entities holding FERC licenses dissolve or otherwise "die."  Depending on the specific facts, more common changes in ownership of an entity holding a FERC license may also require some activity to remain in compliance with federal law.

More hydropower relicensure expected

Many U.S. hydropower projects face relicensure by the Federal Energy Regulatory Commission within the next 3 years, making hydro project relicensing a hot topic.

The FERC is the nation's primary federal regulator of hydropower facilities.  Under Part I of the Federal Power Act, the Commission's responsibilities over hydropower include issuing licenses for the construction of new projects, relicensing for the continuance of existing projects, and oversight of all ongoing project operations, including dam safety inspections and environmental monitoring.

According to the Commission, about 1,023 issued licenses were active as of April 1, 2015.  Licenses are typically effective for up to 50 years, largely because dams and hydroelectric power facilities are typically long-lived assets and because the regulatory process for licensure is extensive (and expensive for project developers or owners).  Nevertheless, as time marches on, even a 50-year license will ultimately expire, so owners of FERC-licensed hydropower projects must eventually evaluate relicensure. 

Federal law and regulations, including Section 15(b)(1) of the Federal Power Act and 18 C.F.R. §5.5 of the Commission’s regulations, govern the relicensure process.  Between 5 and 5.5 years before an existing license expires, the licensee must notify the Commission whether or not it intends to file an application for a new license.  This filing is known as a Notice of Intent or NOI.  At the same time, the licensee seeking relicensure must also file a Pre-Application Document (PAD).  The PAD must include: (1) a process plan and schedule; (2) a description of the project’s location, facilities, and operation; (3) a description of the existing environment at the project and its resource impacts; (4) a preliminary list of issues and proposed studies; and (5) a list of contacts.  A licensee must also distribute the PAD to appropriate federal, state, and interstate resource agencies, Indian tribes, local governments, and members of the public likely to be interested in the project’s relicensing.

The Commission has noted an anticipated uptick in the rate of relicensure applications.  From October 1, 2010 through September 30, 2014, the Commission has received an annual average of about 12 Notices of Intent to relicense hydroelectric projects.  According to the FERC, 47 licensed projects were in the relicensure process as of April 1.  But even more projects face relicensure in the next 3 years.  According to an April 1 notice issued by the Commission, about 100 FERC-licensed hydropower projects will begin the relicensing process between October 1, 2016, and September 30, 2018.  The Commission thus anticipates the annual average number of Notices of Intent to increase to about 34.

Owners of FERC-licensed hydropower projects nearing the end of their license terms must plan ahead to prepare for relicensure.  Given the expected increase in hydroelectric project relicensure, Commission staff reasonably expects an increase in their workload.  While most existing projects have historically been able to win new licenses, in some cases hydropower project relicensing can become controversial.  Expect the next several years to bring increased relicensing activity.

Sea level rise and coastal LNG terminals

Should federal agencies consider climate change and sea-level rise as they review the environmental impacts of liquefied natural gas terminals?

Yes, according to letters recently filed with the Federal Energy Regulatory Commission by the Sabin Center for Climate Change Law.  Last week the Columbia Law School center submitted comments on two cases involving applications to develop liquefied natural gas export facilities in Maine and Louisiana.

Pursuant to the National Environmental Policy Act (NEPA) and its implementing regulations, in approving an activity, the Commission must consider reasonably foreseeable indirect and cumulative environmental impacts of that activity.  Each case targeted by the Sabin Center involves a proposal to develop facilities for the liquefaction and export of natural gas from coastal or riverine sites: 

• Downeast Liquefaction, LLC has proposed the Downeast LNG Import-Export Project, to be located in Robbinston, Maine.  The bi-directional terminal on the banks of the Passamaquoddy Bay would be capable of processing an average of approximately 300 MMcf per day of pipeline-quality natural gas (including fuel and inerts) in the liquefaction mode and 100 MMcf per day in the vaporization mode.

• Louisiana LNG Energy, LLC has proposed the Mississippi River LNG Project, to be located in Plaquemines Parish south of the Port of New Orleans.  The project would have an initial capacity of 2 million metric tonnes per annum (MTPA), with a targeted start-up in late 2017.

Procedurally, each of these cases is at the stage where the Commission solicits comment on the scope of issues it should include in its environmental review.  In similar letters filed in each docket (Downeast and Louisiana), the Sabin Center took no position on the export of liquefied natural gas or on whether the project should be approved. Instead, the center noticed that while the Commission's Notice of Intent to prepare an environmental impact statement included many important issues to consider, the notice did not identify the potential impact of climate change on the LNG project.

Specifically, the Sabin Center's letters note that sea level rise, and an associated increase in flooding and storm surges, may pose a significant risk due to the project sites' coastal location.  The letters argue that NEPA requires the Commission to assess the projected range of sea level rise and storm surge throughout the life of the projects and identify ways to prepare for climate change-related risks.  They also called for requiring the projects' design to incorporate an additional margin of safety, known as “freeboard,” to account for unanticipated risk factors that can contribute to flood heights, such as waves and the effect of development on ground water absorption.

Whether the Commission will agree with the Sabin Center remains to be seen.  As federal agencies issue permits for energy projects, they face increasing pressure from the public -- and presumably from the administration -- to consider the projects' broader implications for and from climate change.

Yellowstone park proposes utility upgrades

The U.S. National Park Service manages over 84 million acres of land for both conservation and visitor use.  For wilderness parks, these joint objectives lead to the challenge of providing park facilities with electricity despite their remote location.  The Park Service has launched energy efficiency and sustainability programs, but many visitor and administrative facilities still need electricity for safety and comfort.  How should the Park Service balance conservation and development?

Old Faithful geyser erupts in Yellowstone National Park.

Yellowstone National Park, the nation's first park, highlights the difficulty.  Most facilities in the park receive electricity from transmission and distribution lines owned by utility NorthWestern Energy, but the park's rugged environment, challenging climate, and relatively old electrical infrastrucutre lead to frequent power outages - over 250 in 2012.  Unlike much of the electric grid outside the park, facilities in Yellowstone lack modern communication infrastructure - a Supervisory Control and Data Acquisition or SCADA system - that would let the utility diagnose and correct the cause of power outages from the utility's central offices in Montana.

As a result, Yellowstone and NorthWestern Energy have proposed to update the park's electrical distribution system.  Proposed upgrades include an automated, remote monitoring and control system, the installation of equipment buildings, back-up power generators and propane fuel tanks.  The proposed communication system would require the construction of seven towers for radio equipment within the park, generally located at existing electrical substation sites.

Under the National Environmental Policy Act, the Park Service cannot approve the plan without conducting an environmental assessment of the impacts of the proposed development.  The Park Service has released its Environmental Assessment (10.5 megabyte PDF), which is open for public comment until December 6.

The use of national park lands for energy infrastructure can be controversial due to differing philosophies on the level of development desirable in parks.  At the same time, the Park Service notes that the Yellowstone outages have had negative effects on park operations and visitor experience, creating health and safety concerns and lost revenue for concessioners.  How will this balance play out in Yellowstone?

Feds pay damages in Yankee Atomic Power lawsuit

The Portland Press Herald reports that the federal government has partially paid damages awarded under a lawsuit filed by the owners of three former nuclear power plants for about $160 million in damages.  While final regulatory approvals remain pending, the companies plan to use the award to benefit ratepayers.

The nuclear plants -- Maine Yankee, Connecticut Yankee, and Yankee Rowe -- closed in the 1990s.  Federal law requires the federal government to develop a plan for long-term storage and disposal of radioactive waste.  While waste removal was supposed to start in 1998, the federal government has yet to designate a permanent waste repository or to remove the spent fuel.  As a result, the radioactive waste is stored in concrete casks at the sites of the former plants, at the plant owners' expense.  For Maine Yankee, those storage and maintenance costs range from $7 million to $11 million annually, with similar expenses for the other two plants.

The plant owners filed a lawsuit against the federal government in 1998, seeking damages for the cost of maintaining the spent fuel onsite.  After a series of awards and appeals,  a 2012 U.S. Court of Appeals decision upheld the award of $39,667,243 to Connecticut Yankee and $81,690,866 to Maine Yankee, and increased Yankee Atomic's damages award from $21,246,912.55 to $38,268,654.55.

These amount have reportedly now been paid, and the power companies are proposing how they will use the proceeds to benefit ratepayers.  Meanwhile, because the U.S. Court of Claims ruled that utility companies cannot receive damage awards for storage costs that have not yet been incurred, the Yankee Companies have filed a second round of damages claims for approximately $247 million, and anticipate filing a third round of damage claims before the end of 2013.

From 1972 until permanent shutdown in 1997, Maine Yankee operated a 900 megawatt pressurized water reactor in Wiscasset, Maine.  During its operations, Maine Yankee was the largest generating station in Maine.  The plant closed after its owners received a report by the Nuclear Regulatory Commission staff identifying safety problems that were deemed too costly to fix.  Even after closure, the unexpected costs of storing the spent fuel onsite only worsened the plants' economics.  The lawsuit judgment is designed to compensate the plant owners for these costs, although the litigation itself carries a price tag for both the companies and the U.S. taxpayer.

What role will nuclear power play in our energy mix in the coming years?  For now, no federal waste repository is planned.  Safety is paramount, particularly following the 2011 Fukushima disaster in Japan.  Nuclear power plants can produce cost-effective baseload electricity, but face the risk of surprise costs such as those faced by Maine Yankee.  Can a holistic legal and business solution enable the safe operation of nuclear power plants?

Civil engineers grade Maine dams D+

A group of civil engineers have released a report card for Maine infrastructure, giving Maine a C- overall and giving Maine's dams a D+.

ASCE's 2012 Report Card for Maine's Infrastructure (71-page PDF) comes four years after its first Report Card was issued in 2008.  The Report Card covers infrastructure including roads, bridges, railroads, ports and waterways, passenger transportation, airports, dams, municipal wastewater, municipal drinking water, contaminated site remediation, solid waste, schools, energy, and state parks.  It was prepared by a team of nineteen ASCE infrastructure leaders who analyzed issues including existing conditions, capacity, operations & maintenance or deferred maintenance, public safety & security, risk and consequences of failure, and current and projected levels of funding.

As the report notes, Maine has over a 1,000 dams, mostly privately owned.  153 of Maine's dams are classified as high- or significant-hazard-potential.  Dam safety is an important issue, both for dam owners and from a public policy perspective.  When dams fail, they can pose risks to people, communities, properties, and the environment.  According to the report, 131 federally regulated dams are in good repair, but most non-hydropower dams are subject only to state regulation.  Most of Maine’s dams are low-hazard potential, but are more than 50 years old.  Moreover, most of these dams do not generate revenues, making it harder to fund their upkeep even though they may provide values like maintaining lake environments for people and wildlife.

The ASCE report finds that Maine continues to fall well below the needed funding for dam safety inspectors and ranks near the bottom nationally for dam safety program funding.  The report critiques Maine’s Dam Safety Program, which spends much less than the other Northern New England states, is understaffed and has no enforcement division.

Will the ASCE report card lead to changes in how Maine regulates dams?  What funding sources are available to help private dam owners maintain their facilities in safe condition?  Will the state respond by revamping its dam safety program?

Maine court sustains challenge to smart meter project, partially

The Maine Supreme Judicial Court has issued an opinion that calls into question the Maine Public Utilities Commission's dismissal of a complaint against a utility regarding its use of smart-meter technology.  With over 600,000 smart meters already installed, what the court ruling means is unclear.

In 2010, the Commission approved a proposal by Central Maine Power Company (CMP) to install smart meters on its customers' sites.  The project, which CMP called Advanced Metering Infrastructure, entailed replacing existing customer meters with "smart meters" capable of transmitting customer usage data back to the utility using radio frequency signals.

The project triggered a series of customer complaints raising concerns about the health and safety of smart-meter technology associated with the AMI project, focusing on the health effects of RF radiation emitted by the wireless smart meters and the technology’s potential to violate individuals’ privacy.  Customers also complained about the lack of an opt-out provision allowing customers to choose to retain their existing meters.

In 2011, the Commission ordered CMP to provide two alternatives for customers who choose not to have the standard wireless smart meter installed on their premises: either a standard meter, or a smart meter set to receive-only mode.  Under the Commission's order, customers opting out would pay an extra fee.

In response, nineteen CMP customers filed a complaint against both CMP and the Commission, challenging the opt-out fee.  The Commission dismissed that complaint, finding that it had considered and resolved the issues raised in the complaint by ordering CMP to allow customers to opt out.  This dismissal triggered an appeal by the customers to the Maine Supreme Judicial Court.

In the court's opinion issued last week, Friedman v. Public Utilities Commission, the court agreed with the customer complainants that the Commission should not have dismissed the portion of the complaint against CMP addressing health and safety issues.

In reaching this conclusion, the court noted that one of the Commission’s core regulatory responsibilities is to ensure that public utilities provide “safe, reasonable and adequate service” to customers.  The court found that the Commission had explicitly declined to decide "that smart meter technology is not a credible threat to the health and safety of CMP’s customers".  On that sole ground, the court vacated the portion of the Commission’s dismissal of the customer complaint that was directed at CMP and addressed health and safety concerns.

So what does the court's ruling mean in practical terms? CMP has already installed about 600,000 smart meters across its service territory, and has only about 2,000 smart meters left to install. The Commission is undoubtedly reviewing the court's order and has scheduled a deliberative session for next Tuesday, July 24, at 10:00 a.m.

Maine dam safety in question

Dam safety is an important issue.  As Hurricane Irene demonstrated at the Marshfield Dam in Vermont last month, storms (and other conditions like earthquakes) place significant stresses on dams.  When the stresses become too severe, the risk of dam failure increases, placing people downstream at risk.  Some dams do not survive these conditions, such as Colcord Pond in Porter, Maine which blew out in March of 2010.

Water spills over the Doughty Dam in North Berwick, Maine.  This site provided power to numerous mills over the past centuries.

While the Federal Energy Regulatory Commission has jurisdiction over many aspects of most hydroelectric dams, states have asserted an interest in ensuring the safety of people and property near other dams and dammed rivers.  Maine enacted a dam safety law in 2001 creating a safety inspection and enforcement program through the state Department of Defense, Veterans and Emergency Management.  Under this program, dams are inventoried and categorized by their hazard potential, ranging from low hazard potential (minimal losses, primarily to the owner's property) to high hazard potential (misoperation or failure could “probably cause loss of life").

Investigative journalists recently revealed that the state was 2 to 7 years overdue for inspections of half of its high hazard potential dams, Records are missing for the inspection of other dams, and only 3 of the state's 24 high hazard dams were documented as being inspected on time.  The journalists suggested that the state dam inspection office was severely understaffed for the workload required by the dam safety statute.

While the condition of many dams may not be known by the state, some dams' conditions are well-documented.  A number of older reports have showed that many dams were deteriorating and nearing the end of their design life.  Many of these dams do not have hydroelectric generation, but rather maintain a lake level.  Many formerly provided mechanical power to people working at the site, in the form of waterpower harnessed under the riparian owner's mill privilege, but fell into disuse with the spread of fossil fuels and utility-provided electricity.

The condition of each dam, and what if anything should be done about it, is a fact-specific question that must be answered on a case-by-case basis. Different philosophies exist on how to protect public safety while respecting dam owners' private property rights.  Nevertheless, the safety of Maine's state-jurisdictional dams is an important issue to consider.