Smart meters are safe, says Maine agency staff

Thursday, March 27, 2014

The staff of the Maine Public Utilities Commission has issued a report concluding that the use of "smart meters" -- advanced utility metering infrastructure capable of communicating wirelessly with the utility -- is a "safe, reasonable, and adequate utility service."

Smart meters and other new utility technologies offer the opportunity to cut ratepayer costs while enabling new and innovative services.  Building on the ubiquity of cell phones, the internet, and other devices that can communicate using radio frequency emissions, smart meters can provide utilities with real-time data on each customer's consumption of electricity.  This can eliminate the need for traditional meter readers, enable utilities to manage outages in real-time, and can open up opportunities for real-time pricing of electricity.  Many utilities have adopted smart meters and other so-called "advanced metering infrastructure", including Maine's largest electric utility Central Maine Power Co.

But some people are concerned about the safety of smart meters, and in particular with the health effects of the radio frequency emissions associated with the meters' communication system.  Utilities around the country have faced questions, and even legal challenges, over the safety of smart meters.  As CMP rolled out its smart meter program, the Maine Public Utilities Commission received a series of complaints and requests for investigation into whether CMP's advanced metering infrastructure program complied with Maine law requiring utilities to provide safe, reasonable, and adequate utility service.

After legal proceedings before the Commission and Maine's highest state court, in 2012, the Commission opened an investigation into "the health and safety issue related to CMP's installation of smart meter technology."  That investigation led to Tuesday's release of a Commission staff report (67-page PDF) summarizing the evidence it had collected and staff's conclusions.  Highlights from the report include the following findings:
  • The radio frequency (RF) emissions from CMP' s smart meters and other AMI components comply with duly promulgated federal safety regulations and other RF emission standards;
  • No state, federal, or Canadian regulatory body or health agency that has considered the health impacts of smart meters (including Maine 's Center for Disease Control and Prevention (Maine CDC)) has found smart meters to be unsafe;
  • The scientific evidence presented in this proceeding is inconclusive with respect to the human health impacts from low-level RF emissions generally;
  • There are no credible, peer-reviewed scientific studies in the record that demonstrate, or even purport to demonstrate, a direct human health risk specifically from smart meter RF emissions;
  • The studies that have been presented in the record to demonstrate the risk to human health from exposure to RF-emitting devices are based on exposure to substantially higher levels of RF emissions than smart meters;
  • The relative RF emission exposure from smart meters is significantly less than other commonly used RF-emitting electronic devices; and
  • CMP' s installation and operation of its smart meter system is consistent with federal and state energy policy and is a generally accepted utility practice throughout the country.
Based on these findings, the staff report concludes that "CMP's installation and operation of its smart meter system is consistent with its statutory obligation to furnish safe, reasonable and adequate facilities and service."  That said, the report also concurs with recommendations that continued research should be done on the impacts on human health from radio frequency emissions.

It now falls to the full Commission to take up the issue.  Will the Commissioners agree with their staff's findings and conclusion?

Biofuels lead growth in U.S. biomass energy

Monday, March 24, 2014

The use of energy from biomass resources in the United States grew more than 60% over the decade between 2002 and 2013 -- primarily in the form of increased use of biofuels like ethanol and biodiesel that are produced from biomass.

A fuel pump displays prices for gasoline blended with up to 10% ethanol.

According to the U.S. Energy Information Administration, biomass accounted for about half of all renewable energy consumed in 2013 and 5% of total U.S. energy consumed. The three primary sources of this biomass are wood and forest products byproducts, waste including municipal solid waste and landfill gas, and raw organic feedstocks like corn and soybean oil used to produce biofuels.

Of biomass energy resources, biofuels experienced the greatest growth over the last decade. From 2002 to 2013, biofuels created from biomass grew more than 500%, driven largely by increases in U.S. production of ethanol and biodiesel for blending as transportation fuels. These biofuels are typically produced from feedstocks such as agricultural crops and other plant material, animal byproducts, and recycled waste. For U.S. ethanol production, corn is the dominant feedstock, while biodiesel producers rely on soybean oil for just over half of feedstock needs and an array of biomass resources for the rest. Market demand for these biofuels comes in part from federal mandates such as the U.S. Environmental Protection Agency's Renewable Fuel Standard, which requires the blending of certain volumes of biofuels into gasoline and diesel.

Meanwhile, EIA data shows that consumption of wood and waste energy increased just 4% over the decade. About two-thirds of U.S. wood energy is consumed for industrial processes, while nearly all U.S. waste energy is consumed for electric generation or industrial processes.

If this trend continues, woody biomass and waste energy will continue to hold their positions in our portfolio of energy resources, while continued growth in the conversion of biomass into biofuels for transportation and other needs will increase biofuels' weighting in the nation's energy mix.  At the same time, debates continue over the cost and value of programs encouraging the growth of corn as a biofuel feedstock.  What does the future hold for biomass in the U.S.?

Snohomish tidal project wins FERC pilot license

Friday, March 21, 2014

Federal regulators have issued a pilot license for a proposed tidal energy project in Washington.

Tidal waters off the Maine coast.
Yesterday, the Federal Energy Regulatory Commission issued a 10-year pilot license to Public Utility District No. 1 of Snohomish County for the proposed Admiralty Inlet Pilot Tidal Project.  The 600-kilowatt hydrokinetic project, to be located in Puget Sound in the state of Washington, is designed as a temporary, experimental project to evaluate the commercial viability of tidal energy development in Puget Sound.

According to the Commission's Order Issuing Pilot Project License (85-page PDF), the proposed project features two tidal turbines to be manufactured by OpenHydro, each measuring 6 meters in diameter, secured to the seabed by the turbines' 414-ton weight.  Peak tidal currents at the site exceed 3 meters per second.  The Public Utility District plans to connect the project to the mainland grid via subsea cables connecting to District-leased land south of the Coupeville Ferry Terminal.

In granting the pilot license, the Commission considered a range of possible resource impacts from the project.  The site lies near key shipping lanes to the ports of Seattle, Tacoma, Olympia, and Everett, and is near a key trans-oceanic fiber optic cable connecting North America to Japan.  To address concerns over impacts to these resources, the Commission imposed conditions and monitoring requirements on the project.

The Commission's pilot licensure program differs somewhat from its general licensing of hydropower projects.  As described in a whitepaper on the pilot project licensing process prepared by Commission staff, pilot projects should be (1) small; (2) short term; (3) located in non-sensitive areas based on the Commission’s review of the record; (4) removable and able to be shut down on short notice; (5) removed, with the site restored, before the end of the license term (unless a new license is granted); and (6) initiated by a draft application in a form sufficient to support environmental analysis. Projects meeting these criteria enjoy a streamlined regulatory review process.

With the pilot license in hand, the Public Utility District may prepare for project development.  But if the project goes forward, the District may have to justify its costs.  As noted in the Commission’s order, the project has relatively high capital, operation, and maintenance costs with respect to the amount of power produced.  According to the Commission’s order, the levelized annual cost of operating the project will be about $1,848,294, or $7,574.98 per megawatt-hour of energy generated -- significantly higher than the estimated $30/MWh cost of alternative power.  Based on an estimated average annual generation of 244,000 kilowatt-hours as licensed, Commission staff projects that in the first year of operation, the project power will cost $1,840,974 more than the cost of alternative power.

Admittedly, the Snohomish project is designed as an experiment -- a pilot project to test technology and project feasibility.  The Snohomish project is among the first hydrokinetic projects in the country to receive a FERC license.  The first pilot project issued for a tidal project, the Roosevelt Island Tidal Energy Project, similarly faces projected above-market energy costs.  Like the Roosevelt Island project, the Snohomish project will be relatively small.  But given its financial picture, will the Snohomish project go forward?

NJ regulators reject offshore wind project

Thursday, March 20, 2014

The New Jersey Board of Public Utilities has voted against extending ratepayer subsidies to an offshore wind project proposed by developer Fishermen's Energy, challenging the project's financial viability.

The New Jersey coast near Atlantic City, seen from above.

Back in 2011, Fishermen's Energy proposed a 25-megawatt offshore wind pilot project to be located off Atlantic City.  The developer applied to the Board of Public Utilities for ratepayer support under New Jersey's Offshore Wind Economic Development Act of 2010.  That law directed the Board of Public Utilities to develop a program to require utilities to source a percentage of the electricity they sell in New Jersey from one or more qualified offshore wind projects.  To track energy from offshore wind, the law envisioned the creation of offshore renewable energy certificates, or ORECs, that could be sold by qualified offshore wind projects to the load-serving utilities.  The concept was that given the relatively high costs and uncertainty of offshore wind, no project could be financed or built without a steady revenue stream from OREC sales.

But the New Jersey project appeared to stall before the Board.  Charged with creating the OREC program and evaluating whether the Fishermen's Energy project could qualify to produce ORECs, the Board was faced with serious technical tasks.  As the regulatory process for the Fishermen's Energy project lengthened -- ultimately stretching to over 1,000 days -- Board staff raised concerns over the financial viability of the project, as well as over the impact of the requested subsidy to ratepayer costs.  Despite trimming the project's estimated costs to $188 million, these concerns remained, leading Board staff to recommend denial of Fishermen's Energy's request for OREC certification.
Yesterday, the Board of Public Utilities rejected Fishermen’s Energy’s proposal by a unanimous 4-0 decision.  While the Board's formal written order has not yet been released, expect it to explain the Board's reasoning in more detail when it surfaces next week.  In the meantime, Fishermen’s Energy is undoubtedly considering its options, which may include dropping the project, appealing the Board's rejection, or finding alternative ways to de-risk and finance the project.

NJ board to decide on offshore wind project

Wednesday, March 19, 2014

Will New Jersey regulators approve key support for an offshore wind project proposed off the Jersey shore?

Many coastal states and nations are placing new focus on energy projects designed to generate electricity from offshore winds.  A project off New Jersey, first proposed in 2011, appeared to make some initial progress, but has since seemed to stall -- due in part to regulatory delays at the state level.  With a decision by the state Board of Public Utilities (BPU) expected this week, will the Fishermen's Energy offshore wind project move forward?

Fishing boats in a small harbor along Maine's midcoast.

The New Jersey coast offers a fairly unique combination of wind resources and proximity to customer demand.  To capitalize on this combination, the New Jersey legislature and government adopted measures promoting the development of the state's offshore wind resource.  For example, New Jersey's Energy Master Plan calls for an ambitious target of 1,100 megawatts of offshore wind installed by 2020.

In response to the opportunity, in May 2011,  Fisherman's Energy submitted an application to the BPU under the Offshore Wind Economic Development Act for an offshore wind demonstration project.  The Cape May, New Jersey-based developer proposed five, five-megawatt wind turbines in state waters about 2.8 miles off the Atlantic City coast, with a total capacity of 25 megawatts and an estimated cost of $200 million to $300 million.  By the end of 2012, the project had won substantially all of the permits necessary for its development and operation, including approvals by the New Jersey Department of Environmental Protection and Army Corps of Engineers -- but a key piece of the regulatory and financing puzzles remains missing.

Under New Jersey law, the BPU may select one or more qualified offshore wind  projects for financial support in the form of a long-term contract to buy Offshore Wind Renewable Energy Certificates, or ORECs, from the developer.  This revenue stream is viewed as essential to enable a developer to finance and construct a project.

But nearly 3 years later, the state OREC review process remains ongoing. Last year, BPU Staff recommended the BPU reject Fishermen’s project on the grounds that it demonstrated no economic benefits but bore unnecessary technology risk due to its selection of XEMC turbines.  But project advocates, including the New Jersey Rate Counsel, support the project for its apparent consumer benefits.  Nevertheless, the BPU has yet to approve an OREC program.

Meanwhile, crucial federal tax incentives such as the renewable energy business investment tax credit have ended.  Many renewable project developers have found these credits essential in building financing packages for their projects over the last years; while the credits may be reenacted in some form, their loss may mean Fishermen's Energy needs to revise its financial projections.

Fishermen's Energy -- and the many other stakeholders following the project -- may soon learn the project's fate.  The New Jersey BPU is scheduled to vote today on whether to approve the project and authorize it to produce and sell ORECs.  Will the BPU grant Fishermen's Energy's request?

Hydropower relicensing surge expected

Tuesday, March 18, 2014

Hydropower industry experts are gathering near Worcester, Massachusetts, this week for a conference on hydropower re-licensing. Organized by EUCI and hosted by Alden Research Laboratory, the March 18-19 Hydropower Re-Licensing Conference features speakers from federal and state regulatory agencies, owners of hydropower projects, and consultants.

The power of falling water.

Hydropower currently accounts for about two-thirds of all renewable electricity generated in the U.S, with room for growth primarily by expansion of existing facilities at existing storage dams. Most hydropower projects fall under the jurisdiction of the Federal Energy Regulatory Commission, receiving either a license or an exemption pursuant to the Federal Power Act.

Before most existing projects may expand, they need to secure a license amendment from the FERC allowing changes to the project. Planned and upcoming project expansions will drive significant relicensing in the coming years.

The age of the nation's existing hydropower projects will also drive additional relicensing activity in the near term. Of roughly 2,000 existing hydropower licenses and exemptions issued by the FERC, nearly one-quarter will expire within the next 15 years. Since dams have relatively high construction and permitting costs and relatively long useful lives, since demand for renewable electricity remains relatively high, since most dams were built decades ago and since existing licenses typically run for 30 to 50 years, most of these existing dams will likely apply for new licenses before the terms of their existing licenses expire.

For these reasons, expect to see significant re-licensing activity around hydropower projects in the next decade.

Following this week's conference, EUCI will host a workshop on financing new and existing small hydropower projects. A panel of presenters, including Jon Petrillo of Gravity Renewables, Dana Hall of the Low Impact Hydropower Institute, my colleague Peter Brown of Preti Flaherty, and me, will engage with attendees on the ever-important question of how to finance hydropower projects.

For more information about the event, contact me at 207-791-3000 or

FERC directs standards requiring utility hardening against physical threat

Monday, March 17, 2014

In the wake of last year's sniper assault on a California electrical substation, federal regulators have initiated a process to require utilities to demonstrate that they have hardened their power plants, transmission lines, and other infrastructure against physical attacks.  Last week the Federal Energy Regulatory Commission ordered the North American Electric Reliability Corporation, or NERC, to develop reliability standards requiring utilities to address risks due to physical security threats and vulnerabilities.  If NERC adopts reliability standards to protect against physical threats, will the standards improve electric reliability -- and if so, at what cost?

Stacks from a power plant subject to NERC standards rise above a cove in Salem, Massachusetts.

NERC, a not-for-profit entity whose mission is to ensure the reliability of the bulk power system in North America, has been designated as the United States' electric reliability organization.  To carry out this mission, NERC develops and enforces reliability standards for owners and operators of critical electrical infrastructure.  NERC's existing standards span 1,778 pages, and cover issues ranging from personnel training and emergency preparedness to protection against hacking and cyberterrorism. 

Following the April 16, 2013, destruction by intense gunfire of a PG&E Corp. substation in San Jose, California, much attention has fallen on the protection of the U.S. electrical grid against physical threats.  At the federal regulatory level, this attention led the FERC to issue an order on March 7, 2014, directing NERC to adopt additional standards for physical security.  That order prescribes the creation of new standards requiring owners and operators of the so-called Bulk-Power System to take at least three steps to protect physical security:

  • First, owners and operators must perform a risk assessment of their system to identify their "critical facilities".  Critical facilities are defined as those that, if rendered inoperable or damaged, could have a critical impact on the operation of the interconnection through instability, uncontrolled separation, or cascading failures of the Bulk-Power System.

  • Second, owners and operators of critical facilities must evaluate potential threats and vulnerabilities to those facilities.

  • Third, owners and operators must develop and implement a security plan to address potential threats and vulnerabilities.

The order directing physical protections standards has prompted at least two sets of questions in the utility industry.  First, will these standards lead to improved reliability?  While the efficacy of the standards will likely only be proven in retrospect, if at all, fears brought to life by the California attack and others have convinced a majority of the Commission that the standards are necessary.

Other questions have arisen about the cost of implementing the standards.  While some defenses against physical threats may be adopted relatively inexpensively -- for example, opaque fencing around critical facilities -- others may prove expensive.  When the possible scope and extent of critical facilities are taken into account, some estimates of the potential cost -- including that of concurring FERC Commissioner John Norris -- rise into the billions.

Under the Commission's order, NERC has until June 5, 2014, to prepare and submit its proposed new reliability standards.

Switch movie showing in Maine

Thursday, March 13, 2014

Tonight the Maine chapter of the U.S. Green Building Council and ReVision Energy are hosting a showing of the movie Switch at the Portland Public Library.

Switch, a 2009 documentary produced by Harry Lynch and geologist Dr. Scott Tinker, describes some of the changes affecting the production and consumption of energy resources around the world.  From coal and oil, to nuclear power and renewable resources, to energy efficiency, the way society produces and converts fuels and other energy resources into useful power is shifting.  These changes are driven by advances in technology, as well as market and regulatory forces.  The movie features visits to places including a coal mine, geothermal power plant, and a hydropower station, coupled with interviews with industry and regulatory leaders about how they are responding to these forces.

Following the movie, the hosts have asked me to give a brief presentation on Maine's portfolio of energy resources and to answer questions from the audience.  I'm looking forward to the event!

Solar, geothermal led new US capacity in January 2014

Friday, March 7, 2014

Solar and geothermal resources led the new utility-scale electric generating capacity installed in the U.S. in January 2014, according to a report by the staff of the Federal Energy Regulatory Commission.  In all, the report identified 325 megawatts of new generation placed in service in January, substantially all of which is powered by renewable resources.

Old Faithful Geyser erupts in Yellowstone National Park -- a natural geothermal feature.

Solar power contributed the largest share of new generating capacity installed in January, with 287 megawatts of solar projects placed in service.  The largest project, Exelon Corp.'s Antelope Valley Solar Phase II expansion project in Los Angeles County, California, added 130 megawatts of capacity to an existing 230 megawatt project.  The power generated is sold to Pacific Gas and Electric under long-term contract.  Other large new solar projects include MidAmerican Solar’s 61 MW Topaz Solar Farm Phase III expansion project in San Luis Obispo County, California, and two 20 MW projects (Duke Energy Corp.’s Dogwood Solar Power project in Halifax County, North Carolina, and NextEra Energy Inc.’s Mountain View Solar project in Clark County, Nevada).  All of these projects rely on long-term power purchase agreements with utilities.

Geothermal steam power was the second largest category of new electric generating capacity placed in service in January 2014, in the form of Gradient Resources Inc.’s 30 MW Patua Hot Springs Geothermal project in Lyon County, Nevada.  As with the solar projects described above, the power generated by the Patua Hot Springs project is sold to a utility -- in this case, Sacramento Municipal Utility District, under a long-term contract.

Rounding out the new capacity installations in January were 3 small biomass units with a combined capacity of 3 megawatts, and one wind project with an installed capacity of 4 megawatts -- Consolidated Edison Inc.’s 4 MW Russell Point Wind Farm project in Logan County, Ohio.

Despite this growth in solar and geothermal power resources, together these resources account for just over 1% of the nation's total installed operating generating capacity.  Yet the relative growth in solar and geothermal power over the past years has been striking, and is expected to continue for the near term.  Will these resources soon play a larger role in the nation's energy portfolio?

Oregon wave project permit surrendered

Wednesday, March 5, 2014

The developer of a proposed large wave energy project off the Oregon coast has surrendered a key federal permit for the project.

Waves lap islands off the Maine coast near Casco Bay, a more sheltered site than that proposed off Oregon.
Ocean Power Technologies subsidiary Reedsport OPT Wave Park, LLC had proposed a 50 megawatt project in the Pacific Ocean off the central Oregon coast.  This larger project was intended to follow on the heels of OPT's "Phase I" development, a 1.5 megawatt non-grid connected pilot project which in 2012 became the first U.S. wave project to win a license from the Federal Energy Regulatory Commission.

OPT also won preliminary permits from the FERC to study the feasibility of larger projects off Reedsport, including a 15 megawatt "Phase II" and the 50 megawatt "Phase III" project.  OPT's Phase III preliminary permit gave it three years to study the feasibility of the "Reedsport Expanded Project", after which OPT could seek a license to develop and operate the larger scale phases.

That permit was set to expire on February 28, 2014.  Given the technological, permitting, and community engagement challenges raised by developing any advanced energy project, many permittees find that they need more than 3 years to study a site.  The FERC allows such developers to seek successive preliminary permits, effectively extending the due diligence period for qualified developers able to show real progress.

But based on a February 28, 2014, FERC filing, OPT announced that it would not seek a successive preliminary permit at this time, and would instead surrender the Phase III preliminary permit.  In its filing, OPT acknowledged the significant efforts made by the state of Oregon to facilitate wave energy projects, but noted the challenges interposed by a cascading series of unforeseen delays:delays in the Phase I study and development processes, resulting delays in the Phase II consultation, licensing, study, and monitoring processes, and "increased project-related costs."  Ultimately, OPT noted that while it continues to evaluate its Phase I and Phase II implementation options, "OPT's plans for an expanded Phase III Project are sufficiently uncertain at this time that the company cannot justify requesting an additional three-year preliminary permit extension."

Meanwhile, last month another OPT affiliate announced an agreement with Lockheed Martin to develop a 62.5 megawatt wave energy project off the coast of Australia.  While it is tempting to read between the lines and surmise that the Australian permitting process, culture, or site conditions are more favorable than those in Oregon, OPT has given no concrete indication that this is the case.  Estimates of U.S. wave energy potential remain large -- with at least one report identifying a total available wave energy resource of 2,650 terawatt-hours per year.  Whether or not the expanded Oregon project returns to active development, the size of the resource points to continued interest in developing the U.S.'s marine renewable energy resources.