US Army solar engine project

The United States Department of Defense has announced plans to develop a gigawatt of renewable electricity generation capacity at Army and Air Force installations by 2025.  In pursuit of this goal, U.S. armed forces branches are evaluating their technological options.  For a depot in Utah, the Army has reportedly selected a technology that uses concentrated solar energy to power mechanical engines.

Iconic Utah desert scenery: Delicate Arch, in Arches National Park.

Located about 45 minutes southwest of Salt Lake City, the Tooele Army Depot is designed to be the conventional ammunition hub for the western U.S., as well as a "peculiar equipment center" -- meaning a storage place for unusual weapons, munition and equipment.  Tooele is already home to the Army's first commercial-scale wind turbine, a 1.5-megawatt unit which was commissioned in 2010.

The site on the fringes of Utah's West Desert gets a lot of sun.  This may have led the Army to focus on solar energy technologies for a larger project.  According to reports by KSL, the Army has selected a company called Infinia to develop a solar energy project.   That project will entail 430 Power Dishes, modular units developed by Infinia.  Each Power Dish uses sun-tracking parabolic mirrors to concentrate solar energy on a chamber of helium gas.  The expansion of this gas drives a Stirling engine -- effectively a piston connected to a generator which produces electricity.  Each unit can produce 3.2 kW of alternating current power.

However, a recent vote by the Senate Armed Services Committee may dampen the Department of Defense's ability to develop renewable energy sources and limit the military's spending on renewable energy projects.  By 13-12 votes, the committee voted to block the construction of a biofuels refinery for the armed forces, as well as to prohibit paying more for alternative fuels than for traditional fossil fuels.

Monhegan offshore wind postponed

The Rockland, Maine-based Free Press Online reports that the testing of a scaled-down floating deep-water offshore wind turbine off Monhegan Island this summer has been postponed until 2013.

Dockside, Monhegan.

In 2009, the Maine Ocean Energy Task Force selected a site off Monhegan as an offshore wind test site.  At the site about 2 miles south of the island, the University of Maine-led DeepCWind Consortium plans to develop a one-third scale (about 100' tall) floating platform and test turbine.  The consortium has described the Monhegan offshore wind project as a pilot project, designed to test platform and turbine technologies as well as to assess project impacts on the ocean environment.

Pre-development of the Monhegan wind project has been taking place.  The project has faced challenges, including a lawsuit alleging that the Maine Department of Conservation wrongfully granted the project a permit to use the site.  Throughout, the DeepCWind Consortium has targeted project deployment and installation for the summer of 2012.

Now, project proponent Dr. Habib Dagher is quoted as saying that some permits are still pending for the Monhegan site, meaning the project cannot be deployed this summer.  2013 is the new target for project deployment.

Pittsfield NH dam repowering project

As governments and businesses consider the hydroelectric potential of existing non-powered dams, competition is heating up to claim and evaluate the best sites.  Federal regulators yesterday resolved a conflict between two developers by awarding a preliminary permit to a developer interested in studying the feasibility of repowering or rebuilding hydroelectric energy production at an existing mill dam on the Suncook River in Pittsfield, New Hampshire.

Another former mill dam in the heart of a New England village: the Doughty Dam in North Berwick, Maine.

Yesterday's order by the Federal Energy Regulatory Commission (9-page PDF) granted a preliminary permit to KC Hydro LLC of New Hampshire to study the feasibility of the Pittsfield Mill Dam Hydropower Project.  Originally built for industrial purposes, the Pittsfield Mill Dam is currently owned by the New Hampshire Department of Environmental Services.

As described in KC Hydro's original permit application (11-page PDF), the project concept involved either restoring an existing but mothballed 415 kW turbine which previously operated under an exemption from licensing, or installing entirely new facilities (potentially with a 530 kW capacity) to capture the hydroelectric potential of the water already impounded behind the dam.

After KC Hydro submitted its preliminary permit, another developer - AMENICO Green Solutions, LLC - applied for a competing preliminary permit for the same site.  AMENICO proposed a similar project, which focused on restoring the existing 415 kW turbine.  AMENICO noted that it had property rights to the site, which it claimed KC Hydro did not.

Noting that the applications were comparable, FERC recited its standard for resolving the competing claims:

Staff has reviewed the applications and found no basis for concluding that either applicant’s plan is superior to the other. Neither applicant has presented a plan based on detailed studies or the results of agency consultation. Where the plans of the applicants are equally well adapted to develop, conserve, and utilize in the public interest the water resources of the region, the Commission will favor the applicant with the earliest application acceptance date.

Because KC Hydro had applied first, FERC awarded the preliminary permit to KC Hydro.  In doing so, FERC noted that a permit applicant is not required to have obtained all access rights to a project site as a condition of receiving a preliminary permit.  However, FERC did note that a preliminary permit does not grant a right of entry onto any lands, so a permittee must obtain any necessary authorizations and comply with any applicable laws and regulations to conduct any field studies.

With its preliminary permit in hand, KC Hydro now has 3 years to investigate the site and apply for a full project license.  Will the Pittsfield dam ultimately be repowered?

Pilgrim nuclear plant down temporarily

The Pilgrim Nuclear Power Station in Plymouth, Massachusetts, was shut down temporarily yesterday due to an apparent malfunction. Media reports suggest a problem with a condenser, a piece of equipment that converts the steam produced by the plant back into water.

Nuclear power plants typically produce electricity by using fissile nuclear material to produce heat. This thermal energy vaporizes water into steam. In turn, this steam spins one or more turbines, each of which is connected to an electric generator. In this regard, nuclear power plants' reliance on steam resembles other thermal power plants such as those fired by combustion fuels like coal or biomass.

As with many other steam-based power plants, nuclear power plants often include steam condensers. A steam condenser takes the steam that is passed through the turbines and converts it back into liquid water. This enables the turbines to extract more energy from the flow of steam, and improves plant efficiency. It appears that a condenser at the Pilgrim station stopped working, leading to a shutdown of the plant.

Any time major equipment at a nuclear power plant sales or malfunctions, operators typically take it very seriously.  Plant owner Entergy has reportedly said that it will not restart the plant until it figures out what went wrong.

Pilgrim Station is a relatively large generating facility, capable of producing up to 688 megawatts of power. The plant was reportedly operating at 30% of its capacity prior to yesterday's shutdown. As result, the short-term impacts on electricity markets in New England may be relatively minimal. However, if the plant continues to be down for an extended period of time, particularly as temperatures heat up and air-conditioning loads increase, the region may experience marginally higher power pricing as result of the shutdown.

The Pilgrim plant is also undergoing a relicensing process through the federal Nuclear Regulatory Commission.

Wyoming-Colorado water pipeline, hydropower

Federal regulators have upheld their rejection of a proposal to pipe water over 500 miles from southwestern Wyoming’s Green River and Flaming Gorge Reservoir to Colorado. The project, known formally as the Regional Watershed Supply Project but more commonly called the Flaming Gorge Pipeline, has been sent back to the drawing board.  The recent permit denial appears to rest largely on the vague and incomplete nature of the application, but it also points to possible gaps in how the federal government regulates water use and hydropower.

Water - a scarce but valuable resource in the American west.

 
The Regional Watershed Supply Project was originally proposed by private developer Million Conservation Resource Group to make new water supply available for use by municipalities, agriculture, and industries in southeastern Wyoming and the Front Range of Colorado. In 2008, the developer applied to the U.S. Army Corps of Engineers for a permit under Section 404 of the Clean Water Act. Under its Section 404 authority, the Army Corps regulates activities involving the discharge of dredged or fill material into waters of the U.S.

In July 2011, based on the record in the case, the Army Corps withdrew the pipeline application, saying in a public notice that the “primary purpose of the project may now change to electrical power generation”, an activity appropriately under the purview of the Federal Energy Regulatory Commission.

Wyco Power and Water Inc., the successor in interest to Million Conservation Resource Group, then applied to the Federal Energy Regulatory Commission for a preliminary permit for its project. By this time, the project concept included seven hydropower projects along the pipeline, including two pumped storage projects and five turbines within the pipeline. In response to the public notice of the permit application, over 200 comments expressly opposing the proposed project were submitted by the Governor of Wyoming, state agencies, counties, municipalities, water conservation districts, utilities, environmental or resource advocacy groups, and individuals.

In February, FERC dismissed Wyco’s request for a preliminary permit (3-page PDF) as premature, noting that the pipeline did not yet exist, nor did the applicant have authorizations for any specific route, nor had a route been substantially identified. FERC also noted that its only role associated with the proposed water supply pipeline would be to authorize the construction and operation of any proposed hydropower projects along the pipeline, not to authorize the siting of the pipeline itself.

Although Wyco asked FERC for a rehearing of its dismissal, yesterday the Commission upheld its earlier decision. In FERC’s order denying request for rehearing and clarification (9-page PDF), FERC reiterated that while it “regularly licenses discrete hydropower developments within substantial water conveyance systems, it has long been the Commission’s practice not to license the entire water conveyance system itself.”

So where does that leave Wyco? With both the Army Corps and FERC finding that the permits sought are premature, a logical next step would be to pin down a specific route and to seek authorizations from the federal, state, and private landowners whose property would be crossed. The developer has suggested that financing the project will be difficult without first obtaining some governmental approvals, and it may be hard to reach deals with landowners without having sufficient financial commitments. Nevertheless, FERC’s decision instructs Wyco that it may come back with a preliminary permit for the hydropower components of its pipeline project once the pipeline is more well-defined.

Fish passage for hydrokinetic projects?

Fishways are often found at dams to allow fish to pass upstream or downstream - but what does fish passage mean for dam-less hydrokinetic projects?

Hydrokinetic energy projects are an innovative way to produce electricity from moving water without building dams.  Companies are developing a variety of technologies, many of which use water flowing in a river, ocean or tidal current to spin turbine-generator sets.  Most grid-connected hydrokinetic projects are regulated by the Federal Energy Regulatory Commission under its authority over hydropower.  This authority comes largely from the Federal Power Act, which requires the Commission to include certain terms in the hydropower project licenses it issues and gives it discretion to impose other conditions.  For example, Section 18 of the Federal Power Act provides that the Commission shall require the construction, maintenance, and operation by a licensee of such fishways as may be prescribed by the Secretary of the Interior or the Secretary of Commerce.

Hydrokinetic technologies are still fairly new, so only a handful of projects have received FERC licenses so far.  Given that hydrokinetic projects do not include the construction of a new dam, one might not expect fish passage to be an issue, particularly at tidal or ocean sites.  Indeed, it appears that for at least some hydrokinetic projects, fish passage may not be an issue.  For example, when FERC issued a pilot project license to Verdant Power, LLC for its Roosevelt Island Tidal Energy Project in New York City's East River, the Commission did not include a reservation of the right to require a fishway in the license.

The Commission did include such a fishway reservation in the pilot license it granted to Ocean Renewable Power Company's Cobscook Bay Tidal project in Maine waters.  In that case, the Secretary of the Interior cited important and highly valued populations of resident and migratory fish, including endangered Atlantic salmon.  Although the Secretary did not prescribe a fishway at the time, Interior requested that the Commission reserve its authority to prescribe fishways under Section 18.  When FERC granted ORPC's license, it included an article reserving the authority to require the licensee to construct, operate, and maintain, or to provide for the construction, operation, and maintenance of such fishways as may be prescribed by the Secretary of the Interior.

Although the project licensee later requested an exemption from this article because its project is not a
dam and will not create any impoundment, the Commission declined to amend the license.  Explaining its reasoning, the Commission pointed to the policy it developed from its traditional hydropower licensing: if the Secretary of the Interior or Commerce so requests, the Commission will include an article reserving the Commission’s authority to require the construction and operation of fishways to preserve the requesting Secretary's future right to to prescribe fishways under Section 18.

What a possible fishway system for a tidal hydrokinetic project remains to be seen, as does whether FERC will impose such a requirement on any operating projects.  If the Secretary of the Interior or Commerce prescribes a fishway, FERC can assert its jurisdiction under Section 18 to require fishway installation.  Factors that could lead to such a decision may include the particular fish species and resources at each project's site, and a project's actual impacts on those fish.

Nova Scotia unveils tidal energy goal

The Canadian Maritime province of Nova Scotia has unveiled a plan to develop its tidal energy resources.

Nova Scotia has articulated a vision to be a global leader in the development of technology and systems that produce environmentally sustainable, competitively priced electricity from the ocean.  Since 1984, when the 20 MW Annapolis Royal Tidal Power Plant was commissioned, Nova Scotia has been home to the only tidal barrage plant of its kind in North America.

This week, Nova Scotia Energy Minister Charlie Parker released a document known as the Nova Scotia Marine Renewable Energy Strategy (44-page PDF).  Citing the magnitude of the province's Bay of Fundy tidal resource - more than 160 billion tonnes of water flow with each tide, which the province calculates can deliver a commercial potential of approximately 2,400 megawatts of power - the strategy offers plans to address research, development, and regulatory initiatives.

Although the strategy includes wave and offshore wind power, its primary focus is on tidal energy production.  The Marine Renewable Energy Strategy sets a target of 300 MW of commercial tidal development by 2020, an amount roughly equal to 10% of the province's electricity consumption.

To achieve this goal, the Strategy proposes awarding one or more Power Development Licenses to large-scale project developers, likely partnerships of technology and utility or power generation companies.  Given the language in the Strategy, which references "[i]ndustry interest in developing a large-scale, 300 MW commercial project", it appears possible that the province is targeting a single, 300 MW tidal project to achieve its goals.  If so, it could lead to the development of the largest tidal power plant in the world, larger than the French La Rance project or the Korean Sihwa Lake project.

Securing solar panels against theft

As more solar panels are installed in remote locations, how can they be secured against theft?

New Hampshire's Swift River, along the Kancamagus Highway.

Between new, more efficient technologies and government incentive programs, people are installing solar photovoltaic panels at a much faster rate than in the past.  While most solar PV projects are being developed on industrial or commercial buildings or homes, remote or off-the-grid solar projects form a growing sector of the market.  This can be particularly cost-effective where traditional grid-based electricity would be cost-prohibitive to install.  For example, the National Park Service is using solar panels to power campground facilities in remote locations, as are state park units and other public land management agencies like the U.S. Forest Service.

Theft of these solar panels and related electric equipment may be a growing problem in some locations.  For example, the Manchester Union Leader reports that thieves stole a variety of equipment including solar panels, electrical panels, charge controllers, inverters and deep cycle batteries from Forest Service facilities along New Hampshire's Kancamagus Highway this past winter.  Along with associated vandalism, the damage and losses to the campground and visitor facilities in the White Mountain National Forest are reported to exceed $10,000.

For some years, electric utilities have faced similar challenges in the form of copper theft, where thieves steal wires and other electric equipment for its value as scrap metal.  As people, businesses and agencies other than utilities become distributed producers of electric energy, they are being exposed to the parallel risk of solar panel theft.  Securing solar energy equipment could take a variety of forms, from physical security (e.g. bolting the equipment down more securely) to monitoring, patrols, or electronic surveillance.  Adding more security to an installation may increase its costs somewhat, but may be a good investment for some situations compared to the risk of loss.

Biogas at Apple's NC data center

Continuing to look at Apple's plans for energy supply at its data center in Maiden, North Carolina:

This spring a series of filings by Apple to the Federal Energy Regulatory Commission gave the public some insight into Apple's planned electric generation facilities at the Maiden data center, home to Apple's iCloud service.  (See Tuesday's blog entry for a look at its solar photovoltaic project, and Wednesday's entry for its fuel cell project.)

Fuel cells convert fuels into electricity through a chemical process that does not rely on combustion.  According to one of Apple's filings with FERC, Apple plans to use biogas to power its fuel cells:

The Systems will be fueled with biogas that will be transported via a natural gas pipeline system.  To be injected into the natural gas pipeline system and qualify as pipeline-grade gas, biogas must meet strict heat content and quality requirements.  Consequently, raw biogas must be upgraded (i.e., cleaned and separated to remove components such as hydrogen sulfide, chlorine, and sulfur and to increase methane content) prior to being injected into a pipeline.  Once injected into the pipeline system, it comingles with conventional natural gas and is indistinguishable from conventional natural gas in terms of safety and burning quality.  The biogas, having been upgraded/cleaned to pipeline-quality and then injected into the natural gas pipeline system displaces a comparable quantity of conventional natural gas.
The volume and heat content of the biogas will be measured at a utility-grade meter at the point of injection.  The biogas will then enter the natural gas pipeline infrastructure that has an established balancing measurement system regulated by the Federal Energy Regulatory Commission (Commission).  The biogas will be nominated for the Facility in accordance with the pipeline’s posted business practices and relevant Commission requirements.  Not only the contract and purchase of biogas, but also the nomination process demonstrates compliance with 18 C.F.R. § 292.204 (b).  A utility-grade meter at the Facility will measure actual gas consumption by the Facility.  A revenue-grade meter will measure electricity generated by the Facility.

Furthermore, because the biogas can be upgraded to flow in a pipeline system and nominated for a particular facility, it allows for flexibility in the location of the generating unit.  This flexibility will provide for increased efficiency (operational and maintenance), enhanced reliability, and improved land use. These benefits were recognized by the North Carolina Utilities Commission (“NCUC”).  The NCUC ruled that biogas fuel, which is derived from a renewable energy resource, cleaned to pipeline quality, injected into the pipeline system and nominated for an electric generation facility within the state of North Carolina, is a renewable energy resource known as “Directed Biogas” (NCUC Order Issued March 21, 2012, in docket SP 100, Sub 29). 

This Facility is in keeping with the stated reasons for the implementation of the Public Utility Regulatory Policies Act of 1978 (PURPA), specifically the increased conservation of electric energy, increased efficiency in the use of facility and resources by electric utilities, and the conservation of natural gas.  In the case of this Facility, the use of biogas, which displaces conventional natural gas, to generate electricity will reduce greenhouse gas emissions and smog forming pollutants while also diversifying the fuel used to generate electricity.  The Systems that make up this Facility consume less fuel and produce less CO2 than other technologies.  Each System emits less than 0.07 lbs/MW-hr of NOx , negligible SOx, less than 0.10 lbs/MW-hr of CO and less than 0.02 lbs/MW-hr of VOC.  Additionally, the Systems require very little water, with an average usage of approximately 0.00001 gallons/kWh. The low carbon footprint, de minimus criteria pollutants, small land use and negligible water use, make this Facility a prime example of an initiative that furthers the Commission’s stated goal of increasing renewable energy and investing in environmentally beneficial technologies.

Apple's Maiden, NC fuel cell project

Following on yesterday's look at Apple's planned solar photovoltaic system for its Maiden, North Carolina data center, here's a look at the fuel cell project Apple is also planning the Maiden facility.

A public filing Apple made last month to the Federal Energy Regulatory Commission describes the Maiden data center's proposed fuel cell system.  The filing represents Apple's self-certification that the fuel cell project meets the standards of the Public Utility Regulatory Policies Act (PURPA) of 1978 as a "qualifying facility", setting the facility up for incentives that could include the right to require Duke Energy Carolinas to buy its output.

Apple's fuel cell self-certification filing, docketed by FERC as QF12-327, describes the project:

The Facility will consist of 24 fuel cell systems (“Systems”) using a patented solid oxide fuel cell technology to generate electricity.  A single fuel cell consists of an anode, a cathode and an electrolyte placed between the two electrodes.  As fuel flows in through the anode side and an oxidant comes in over the cathode, a reaction is triggered that causes electrons to move into the fuel cell’s circuit, producing electricity.

Each System consists of thousands of fuel cells stacked together.  Multiple stacks are aggregated together into a "power module", and then multiple power modules, along with a common fuel input and electrical output are assembled as a complete system.  Each System is approximately the size of a standard parking space and will produce approximately 200 kW of power.  The Systems have a modular design that allows the simultaneous use of multiple Systems in order to achieve the desired electric generation output.  Each 200 kW (AC) System is comprised of six individual direct current (DC) power-producing modules and one input/output module for fuel intake and electricity output.  Each of the six individual DC power producing modules is feeding electricity to the input/output module which converts the DC power into the systems AC power output.  The combination of six DC modules and one input/output module comprise a 200 kW (AC) all-electric System.  Each System has a net baseload generating capacity of 200 kW (AC).  The total generating capacity of the Facility will be approximately 4.8 MW (AC).

The "patented solid oxide fuel cell technology to generate electricity" in this description is reported to be Bloom Energy's Bloom box technology.

Tomorrow, a look at the innovative fuel Apple proposes to use to power these fuel cells.

Apple's Maiden NC solar project

As Apple continues to develop a data center to handle its iCloud service, some details are emerging about the energy infrastructure to be built at the Maiden, North Carolina facility.  Two public filings Apple made last month to the Federal Energy Regulatory Commission describe the Maiden data center's solar photovoltaic and fuel cell systems.

Under federal law, certain efficient or renewable electricity generation facilities can certify themselves as "qualifying facilities" or QFs.  The Public Utility Regulatory Policies Act (PURPA) of 1978 required monopolistic electric utilities to buy power from QFs, as long as that cost was less than the utility's own "avoided cost".  Generally, a utility's avoided cost is the cost of the power the utility would have procured from a source other than the QF in question.  This policy was intended to improve the efficiency of the nation's fleet of electric generation, as lower-cost QFs displaced more expensive traditional utility generation.

In April, Apple submitted two filings to FERC certifying its planned Maiden solar and fuel cell systems as QFs.  These documents provide additional insight into Apple's plans.

In its solar photovoltaic project self-certification, docketed by FERC as QF12-328, Apple described the project:

Each of the photovoltaic installations will consist of multiple 435-watt photovoltaic modules on ground-mounted single-axis tracking systems. The current design includes 57,360 435-watt modules. The modules will be connected in series strings of 10 to achieve the appropriate DC voltage. The modules will track the sun by rotating about a north-south axis. At the current time, we expect 14 photovoltaic installations will make up the solar farm: ten 1.50 MW installations and four 1.25 MW installations. The final number of installations and modules will depend on detailed design considerations in consultation with the utility, the photovoltaic system provider, and local permitting authorities. Each installation will be connected to two 750 kW or two 625 kW inverters. Inverters will convert the DC current produced by the systems to AC current. A step up transformer is installed between the inverter outputs and the point of connection to Duke's distribution system. Each installation has a dedicated transformer. The photovoltaic installations will be installed in a phased manner, whereby the installations will be interconnected as they are completed.

Check out tomorrow's blog entry for a look at Apple's biogas fuel cell facility.

Pro football goes green?

This year the National Football League's Philadelphia Eagles plan to install renewable electricity generation at the Eagle's home stadium.

Under the deal announced earlier this spring, energy and utility giant NRG will install 11,000 solar panels and 14 small-scale wind turbines at Lincoln Financial Field in Philadelphia.  NRG reportedly plans to install solar panels along the south and west sides of the stadium as well as in parking lot space, with wind turbines lining the stadium's north and south sides.  Construction is supposed to be complete by the end of 2012.

Sporting facilities like pro football fields typically consume most of their electricity during the relatively few days of the year when they are used, so these renewable electric generation assets may never fully power the Eagles' field during a home game.  At these times, the stadium will most likely continue to draw power from the utility electric grid.  For this reason, it may be no coincidence that the deal also calls for NRG to become the official supplier of grid power to the stadium.

On the flip side, the solar and wind generation will likely produce most of its power when the stadium demands relatively little power, making Lincoln Financial Field a potential candidate for a net metering program such as Pennsylvania has enacted.  Over an entire year, reports suggest that the solar and wind assets proposed for Lincoln Financial Field will produce about six times the power used during all Eagles home games.

The NRG deal is not the first proposal to develop clean energy facilities at the Eagles' stadium.  In 2010, the Eagles announced a similar partnership with Solar Blue, which would have included a natural gas-fired cogeneration power plant in addition to solar and wind generation.  That project was ultimately scrapped.

Nevertheless, if the NRG project happens, the Eagles will join a growing trend of professional sports teams seeking to green their image, improve their sustainability, and cut their energy costs. 

NJ-PA transmission line challenged

A New Jersey court is considering a challenge by environmental activists to a proposed high-voltage transmission line connecting Pennsylvania and New Jersey.

Proposed by PPL Electric Utilities and Public Service Electric and Gas Co., the Susquehanna-Roseland line would run 145 miles from PPL's Susquehanna substation near Berwick, Pennsylvania to Roseland, New Jersey.  The route, which is nearly finalized, would cross three units of land managed by the National Park Service: the Delaware Water Gap National Recreation Area, the Middle Delaware National Scenic and Recreational River and National Recreation Water Trail, and the Appalachian National Scenic Trail. 

The Susquehanna-Roseland project has received the approval of the New Jersey Board of Public Utilities, as well as federal support in the form of an expedited permitting process.  Regional grid operator PJM Interconnection, LLC has also said that the line is essential to improving reliability and reducing transmission line congestion in the region.

At the same time, the line has drawn opposition from environmental groups and others.  The Sierra Club and other organizations have challenged the line as continuing a "reliance on toxic fossil fuels by shipping coal-fired power into New Jersey." Instead, the Sierra Club calls for increased use of demand response, energy efficiency and renewable energy to meet peak energy demands.  Other have challenged the project's proposed route through National Park Service lands, including widening some existing transmission corridors and associated road-building activity.

This past Wednesday, the Appellate Division of the Superior Court of New Jersey heard oral argument over whether the New Jersey Board of Public Utilities' approval of the project was valid.  Among the challenges raised was whether the BPU fully considered non-transmission alternatives to the line, such as demand response and energy efficiency.

While the court process concludes, the utility proponents believe that construction should not be affected by the lawsuits.  The line is expected to be placed in service by summer 2015.

Maine tidal PPA terms for ORPC

Last month, the Maine Public Utilities Commission approved the terms of a 20-year power purchase agreement between three utilities and Ocean Renewable Power Company.  Projected for initial development later this year, ORPC's Maine Tidal Energy Project would ultimately include a series of hydrokinetic turbine generator units spread across three project sites and phases.

Acting under a 2010 state law, the Maine PUC held a request for proposals for long-term contracts for deep-water offshore wind pilot projects and tidal energy demonstration projects.  The law required applicants to demonstrate that their project will provide tangible economic benefits to the state, as well as a commitment to invest in related manufacturing facilities in Maine.

ORPC responded to the RFP, and was ultimately selected by the PUC for a contract.  While some details of the final power purchase agreement remain to be negotiated, last month PUC approved a term sheet specifying pricing terms and a variety of non-pricing terms.

Under the term sheet, ORPC will sell the utilities energy and capacity from the Maine project.  The price of energy will start at 21.5 cents per kilowatt-hour in the first year, escalating at 2% per year over the 20-year contract term.  If ORPC can qualify the project for capacity payments in the New England market - another energy-related product - it will receive the prevailing market price, although the grid operator has recently denied capacity payments to other renewable resources in eastern and northern Maine.  The deal does not include any renewable energy credits the project earns, which ORPC could retain or sell separately.

The term sheet approved by the Commission also include a series non-pricing terms intended to ensure that the state realizes the economic development benefits required by statute.  These terms include a variety of commitments by ORPC, including:

• to maintain or establish manufacturing, assembly, and testing operations in Maine
• to continue partnerships with entities in the downeast Washington County region
• to upgrade local distribution lines in Lubec, as needed to connect the project's power to the mainland grid
• to create and/or retain at least 80 direct full-time equivalent jobs in Maine during the development, construction and installation of the project
• to create and/or retain at least 12 direct full-time equivalent jobs in Maine during the operation and maintenance phase of the project
• to use commercially reasonable efforts to expend at least 50% of the project's capital investments and 50% of the operating expenditures in Maine

In approving the term sheet with these terms, the Commission found that the project would yield economic benefits including direct wage growth in Maine, direct investment in Maine, improved general economic conditions in the state, and the development of intellectual capital and an expert workforce capable of supporting long-term growth.

The parties are now negotiating the final details of the contract.  Expect the PUC to deliberate on a final contract later this year.

NPS promotes greener national parks

A new plan by the U.S. National Park Service seeks to improve the sustainability and energy efficiency of its holdings.  The NPS Green Parks Plan (16-page PDF)  outlines the service's plan to reduce its impact on the environment, mitigate the effects of climate change, and integrate sustainable practices throughout its operations.

Solar panels line a bathroom roof at Devil's Garden campground, Arches National Park, Utah.

While the park service is famed for the wild and scenic landscapes it protects - totaling over 84,000,000 acres - the NPS also manages the largest number of structures of any civilian agency in the federal government.  All told, the NPS portfolio of 397 national parks includes more than 67,000 structures with more than 50 million square feet of constructed space and more than 3,000 utility systems.  Each year, 2.6 billion gallons of water are consumed in national parks, and the service's annual energy costs average $44 million.

The Green Parks Plan identifies nine strategic goals:

• Continuously Improve Environmental Performance: meeting and exceeding the requirements of all applicable environmental laws
• Be Climate Friendly and Climate Ready: reducing greenhouse gas emissions and adapting facilities identified as at risk from climate change
• Be Energy Smart: improving facility energy performance and increasing reliance on renewable energy
• Be Water Wise: improving facility water use efficiency
• Green Our Rides: transforming the NPS fleet of vehicles and adopting greener transportation methods
• Buy Green and Reduce, Reuse, and Recycle: purchasing environmentally friendly products and increasing waste diversion and recycling
• Preserve Outdoor Values:minimizing the impact of facility operations on the external environment
• Adopt Best Practices:adopting sustainable best practices in all facility operations
• Foster Sustainability Beyond Our Boundaries:engaging visitors about sustainability and inviting their participation

The park service is looking forward to its centennial in 2016; in last year's NPS Call to Action, the service committed to reducing its carbon footprint before that date.  The park service views the Green Parks Plan as the roadmap for implementing that commitment.  While the fully-articulated Green Parks Plan is new, many parks have already adopted sustainability initiatives.  For example, campground facilities in Arches National Park use solar photovoltaic panels to power water pumps and light buildings.

What does the Green Parks Plan mean?  For the park service, it may lead to improved sustainability and lower operating costs.  For greentech businesses, it may mean opportunities to install energy efficiency and renewable energy projects, or to sell greener vehicles.  For park visitors, it should mean cleaner air and water, and more opportunities to participate in sustainability.  Expect the park service to release periodic updates on its progress toward achieving the nine goals of the Green Parks Plan.

Sunken history behind Penobscot dams

As two dams come out of Maine's Penobscot River, the conservation organization leading the dam removal effort has discovered what historians might view as sunken treasure: submerged mill dam structures from centuries past.  At the same time, these sunken dam remnants may continue to impede fish passage once the modern dams are removed, potentially frustrating the dam owner's intent in removing them.

The Penobscot River Restoration Trust is undertaking the removal of the Veazie and Great Works Dams on the Penobscot River.  Following a 2004 settlement agreement among previous dam owners, environmental and conservation groups, and governmental agencies, the Federal Energy Regulatory Commission approved their removal, along with the installation of fish passage equipment at the upstream Howland dam on the Piscataquis River.

Dam removal is expected to help fish and other aquatic wildlife, but FERC required the Trust to develop a plan to mitigate any adverse impacts of dam removal on infrastructure and archaeologic resources.  For example, the Trust knew that the historic remnants of previous dams and lumber mills lay submerged in the impoundment behind the Veazie Dam.  The remnants are associated with a series of lumber mills successively known as the Penobscot Mill Dam Company Mills, the City Mills, the Corporation Mills, and the Veazie Lumber Company Mill, which consisted of two sets of saw mills connected along water-control structures that ran parallel to the Penobscot River, and which were constructed in the mid-nineteenth century. Moreover, the site was purchased in 1889 for use as one of Maine’s first
hydroelectric facilities.

The Trust, along with the state historical preservation office, entered into a memorandum of agreement requiring the Trust to document the Veazie remnant structures after the modern dam is removed.  Because the historic mill dam is expected to impair natural river flow after the modern dam is gone, the Trust also plans to remove the historic structure after it is documented.

As it turns out, the historic Veazie dam is not the only historic or archaeological resource submerged beneath the Penobscot River's waters. While finalizing plans for removal of the Great Works dam, the Trust discovered that a similar, inundated, remnant structures exist in the Great Works impoundment.  The structural remains within the impoundment of the Great Works Dam were constructed as two structures in the early 19th century to provide water for two early sawmill complexes on the Penobscot River at Great Works: for the mills of Rufus Dwinel on the west bank, and for the mills of the Great Works Milling and Manufacturing Company on the east bank. These original dams, on each side of the river, were built as wing dams that extended upriver and out from the river bank, and likely were built independently of each other. The two dams were then consolidated under a single ownership in the early 1880s by the Penobscot Chemical Fibre Company, who built an early mill for producing wood pulp for paper on the Penobscot River.

Both of these sites may be eligible for nomination to the National Register of Historic Places as historic archaeological sites.

As a result of the re-discovery of these additional historic remnants, the Trust sought and obtained FERC's approval to document and remove part of the historic Great Works structures.  The Trust anticipates removing the modern Great Works dam as early as this summer.

spring-fed small hydro in Idaho?

Small-scale hydroelectric projects are receiving renewed interest as society looks for cost-effective ways to produce electricity using local, renewable resources.  Depending on available sites and on what alterntative resources might be available, microhydro or small-scale hydroelectric projects can fit the bill.  Even if you own a first-class site for a microhydro project, before you can build or operate your project, you need to understand what federal and state regulations may apply.  Some small hydro projects are treated much like full-scale dam-based hydropower projects, while others (like small projects using existing conduits, pipes or canals) can get an easier regulatory path to approval.

A small hydro project proposed near Grace, Idaho illustrates some of these regulatory considerations, and the importance of understanding how regulators apply the rules.  Grace is a town of about 1,000 people located in Idaho's Gem Valley.  The Bear River runs through the valley on its course flowing out of Bear Lake, around the Bear River Range by Soda Springs, and then south through Grace into Utah's Cache Valley.  In the early twentieth century, recognizing the area's water resources and topographic variation, a series of dams, diversion pipes and powerhouses were built along the Bear River to produce hydroelectricity.  One side effect was that a stretch of river known as Black Canyon was largely dewatered, as an aqueduct carried the water around the canyon to a downstream powerhouse.  Ultimately, Utah Power and Light (and then PacifiCorp) came to operate these assets, and chose to remove one of the dams, an aqueduct and one powerhouse in 2006 and 2007, and to provide some increased flows through the Black Canyon section.

There may be ways to generate hydroelectricity in Grace without diverting water away from the Bear River. Last month, a local farmer with interests in canals and hydro development proposed a new hydro project near Grace.  The Gilbert Hydropower Project proposed to capture the flows of several natural springs and pipe this water about 700 feet to a turbine/generator unit.  Currently, the water is partially used for pasture irrigation with the unused portion flowing into the Bear River; the developer proposes to install a 24‐inch diameter above-ground pipeline to send the water to a Pelton turbine attached to a 75 kW generator.

In its application to the Federal Energy Regulatory Commission (docketed by FERC as Project No. 14367-000), the project developer requested an exemption from the licensing requirements of the Federal Power Act under the so-called "5 megawatt exemption" rule.  That rule allows the Commission to exempt small hydroelectric projects with an installed capacity of 5 megawatts or less that: (1) are located at the site of any dam in existence on or before July 22, 2005, and that use the water power potential of such dam for the generation of electricity; or (2) use a “natural water feature” to generate electricity, without the need for any dam or impoundment.

FERC dismissed the Gilbert project's request for an exemption, noting, "Because [the] project would utilize the flows of a natural spring that travel through 700 feet of pipe to reach the proposed turbine/generator unit, it would neither be at the site of an existing dam nor use the flows from a natural water feature", and thus was ineligible for an exemption.  However, FERC did invite the Gilbert developers to convert their exemption application to a license application, which the developers did earlier this month.  The developers now have until June 18, 2012, to submit the additional information needed for a complete license application.

What's in the future for Grace, Idaho?  What role could using nontraditional water resources such as springs play there or elsewhere in our energy future?

Removing WA's Condit dam, recap

A major dam removal project is underway on the White Salmon River in the state of Washington.  Video footage of its breach (made available by National Geographic) shows something few living humans have seen but which is already recur in the near future: the removal of a major dam and associated dewatering of its impoundment.

In 1913, the Northwestern Electric Company built the Condit Hydroelectric Project to provide electricity to a nearby paper company and even to feed Portland, Oregon.  The dam was rated at 14.7 MW of nameplate capacity - a far cry from the Hoover Dam (2080 MW) or Grand Coulee Dam (6809 MW), but nevertheless a major dam in terms of its power production and significance.

In 1996, increasing pressure on dam owner PacifiCorp to install fish ladders and perform modifications for environmental compliance led PacifiCorp to seek the dam's decommissioning and removal.  In 2010, the Federal Energy Regulatory Commission approved the removal of the Condit Dam.  In late 2011, contractors breached the dam, draining the upstream impoundment.

If you haven't seen a dam breach before, or if you are simply impressed by the immense power of moving water, you may appreciate the National Geographic video footage of the Condit Dam's breach and the resulting rush of water and sediment.

Now that the Condit Dam has been removed, remediation and restoration efforts are under way.  You can track those efforts on the Washington State Department of Ecology's website, as well as on PacifiCorp's website.

Maine regulators approve tidal energy PPA concept

Yesterday, the Maine Public Utilities Commission approved the terms of a power purchase agreement between three large utilities and a hydrokinetic tidal power project in Maine waters.

Low tide at Preble Cove, Great Cranberry Island, Maine.

Hydrokinetic energy projects produce electricity from moving water like tides, waves, ocean currents, or rivers, typically without dams.  As I noted yesterday, a 2010 Maine law required the PUC to conduct a competitive process to solicit proposals for long-term contracts for offshore wind and tidal projects.  The PUC received multiple submissions in response.  Commission staff have been negotiating with some of the bidders, and yesterday approved a proposal by Ocean Renewable Power Co. to sell the output of a small tidal project in Cobscook Bay to Maine's three largest utilities.

Under the terms approved the Commission, ORPC will receive a 20-year contract with utilities Central Maine Power Co., Bangor Hydro-Electric Co., and Maine Public Service Co. to sell the output of its underwater tidal power generation units.  ORPC plans to install the first of these units in Cobscook Bay this summer, and plans to expand its pilot project to include sites off Lubec and Eastport in the next 4 years.

While many of the terms of the resulting contract remain to be worked out, one piece appears firm: the price.  Utilities will pay 21.5 cents per kilowatt-hour for the tide-generated electricity in the first year; this base price of 21.5 cents will escalate at 2% per year, reaching a price of about 39 cents per kWh in the final contract year.  (By way of comparison, the Cape Wind offshore wind PPA approved in Massachusetts starts at 18.7 cents per kWh, with a 3.5% annual escalator over its 15 year term.  The ORPC initial rate is over twice the average rate currently paid by Maine utility customers on "standard offer" default service, or about 5 times higher than the current wholesale price in the New England market.)

For ORPC, the contract is a significant boon.  Securing a 20-year power purchase agreement should greatly assist the developer in securing financing for the project.  This project is designed as a demonstration or pilot project, but may be able to serve as a proof that ORPC's technology and installation systems will work on a larger scale.

For ratepayers, the volume of the contract is relatively low - as licensed by FERC, the Cobscook Project has a maximum capacity of 300 kW - meaning that its above-market costs will be diluted in the much larger pool of power consumed in Maine.  Nevertheless, if the contract volume grows as ORPC builds more of its scalable tidal generation units, those costs will become less and less dilute.  On the other hand, the contract itself - which still needs approval by the PUC once it is finally negotiated - may include other products or commodities such as capacity or renewable energy credits (RECs).  Developers typically prefer securing long-term contracts for as many commodities as possible, which helps solidify their future revenues, but it can make it harder to compare two contracts.

Many tidal projects today face high capital costs, let alone research and development expenses, but many believe that their fuel-free nature will ultimately enable tidal power to have a low fundamental cost of production of electricity in the future.  ORPC's project may shed some light on how that belief fares in the Gulf of Maine.

Maine PUC considers offshore wind, tidal

Petit Manan Light, several miles off the Maine coast.

Today the Maine Public Utilities Commission considers a term sheet for a long-term contract with the developer of a deepwater offshore wind or tidal energy project.  If the Commission ultimately approves the contract, it could represent Maine utilities' first offshore wind or tidal power purchase agreement.

In recent years, coastal states have become excited by the possibility of developing offshore wind and tidal energy resources.  Proponents hope that technological advances will enable both cost-effective energy production and economic development as the offshore wind sector gains a foothold.  In 2010, following record oil prices, the Maine Legislature enacted a law directing the Public Utilities Commission to hold a competitive solicitation for offshore wind proposals.  The law, P.L. 2009, ch. 615, requires the PUC to solicit proposals for long-term contracts to supply installed capacity and associated renewable energy and renewable energy credits from one or more deep-water offshore wind energy pilot projects or tidal energy demonstration projects.  Projects must employ one or more floating wind energy turbines in the Gulf of Maine, in water at least 300 feet deep and no less than 10 nautical miles offshore, and must be connected to the mainland grid.  The program may also include proposals by small-scale tidal power projects for similar long-term power purchase agreements.

In September 2010, the Maine PUC issued a request for proposals under the program.  Multiple bidders may have responded, although a subsidiary of Norwegian energy company Statoil may be the only entity to publicly announce its interest in developing a floating offshore wind project off Maine.

The Public Utilities Commission has placed the offshore wind contract docket on its agenda for today's deliberations as "Consideration of Long Term Contract Term Sheet".  The Maine PUC has not previously deliberated any long-term power purchase agreements for offshore wind or tidal power, but its past practice for land-based renewable projects suggests a possible procedural path.  If the Commission finds the terms of the proposal to be satisfactory and compliant with law, it may approve the term sheet and direct the bidder to negotiate a final contract with one or more Maine utilities.  Alternatively, the Commission could reject the term sheet and invite the bidder to negotiate more favorable terms.

Deliberations start at 10:00 a.m.  Will the Maine PUC show interest in the deepwater offshore wind or tidal power proposal before it today?

FERC seeks demand response standards

Demand response, an innovative strategy to ensuring the integrity of electric grids, is growing in popularity, prompting federal regulators to consider standardizing how demand response performance is measured.

Managing an electric grid entails ensuring a constant balance between electric generation and customer demand for electricity.  As customer demand rises, grid operators have traditionally called on more and more generating units.  In most markets, grid operators dispatch the lowest-cost units first to keep overall costs down.  As a result, generating units needed to meet peak demand tend to be more expensive than baseload generation.  Many peaking units also emit more pollutants per unit of energy than baseload units.

In a demand response program, customers can volunteer to be available to reduce their load during times of peak demand.  When done right, this reduction in customer demand can play much the same role as dispatching additional generation, but at a lower cost in dollars and environmental impacts.  Energy efficiency resources can also play a similar role.

The U.S. Congress and the Federal Energy Regulatory Commission have both recognized that demand response can be a decentralized, crowd-sourced alternative to peaking power plants.  Utilities and regional transmission organizations across the nation are implementing demand response programs.

As demand response grows in importance, the question of how to measure a customer's performance is important.  Different utilities and regions have adopted varying standards for how performance is measured.  In an attempt to standardize the measurement and verification of demand response and energy efficiency resources participating in organized wholesale electricity markets, the FERC has proposed to amend its regulations to incorporate by reference the demand-side management and energy efficiency business practice standards of the North American Energy Standards Board.  NAESB describes itself as "an industry forum for the development and promotion of standards which will lead to a seamless marketplace for wholesale and retail natural gas and electricity, as recognized by its customers, business community, participants, and regulatory entities."

In its Notice of Proposed Rulemaking (29-page PDF), Standards for Business Practices and Communication Protocols for Public Utilities, 139 FERC ¶ 61,041, FERC states its hope that "[a]doption of these standards is intended to improve the methods and procedures used to accurately measure demand response and energy efficiency resource performance" and that their adoption should help regional grid operators "properly credit demand response and energy efficiency resources for their services".

Debate over data center green claims

How green is Apple's iCloud data storage service?  That question provoked debate this week, as environmental activism group Greenpeace released a report critical of Apple's choices of power supply for its data center in Maiden, North Carolina, where the iCloud storage is based.

Greenpeace's report, How Clean is Your Cloud (52-page PDF), notes the explosive growth of cloud-based data and computing services offered by companies like Apple, Facebook, Amazon, Microsoft, Google,
and Yahoo.  These services are made possible by data centers, centralized networks of servers and computer infrastructure.  As Greenpeace put it, "Data centers are the factories of the 21st century information age, containing thousands of computers that store and manage our rapidly growing collection of data for consumption at a moment’s notice."

Data centers can be major consumers of electricity, needing cooling and air handling as well as energy for raw processing operations.  Some data center operators seek out renewable electricity, while others are developing on-site generation.  Most work to improve their energy efficiency, making the best possible use of the energy they need.

Apple has touted the green credentials of its Maiden data center, which was designed to earn LEED Platinum certification from the U.S. Green Building Council.  Apple's Maiden facility will also include a 20 MW solar facility on land adjacent to the data center, as well as a 5 MW biogas-based fuel cell system, systems Apple describes as "the nation’s largest end user-owned solar array" and "the largest nonutility fuel cell installation in the United States."

Greenpeace's report notes that despite these investments, Apple's data center is located in an area where utilities source a significant amount of power from coal-fired power plants.  Greenpeace and Apple dispute how much power the Maiden plant will consume (differing by as much as a factor of 5), and thus what fraction of its electricity will be produced from renewable on-site generation.

Whatever the facts may be, the debate illustrates society's interest in the environmental impacts of our technological choices - as well as the difficulty in evaluating some claims of greenness.

New hydropower from old canals

Innovative approaches could enable a significant increase in the production of hydroelectricity from water flowing through existing canals, conduits and major pipes owned by the U.S. federal government.  According to a recent report prepared by the federal Bureau of Reclamation, the 2012 Site Inventory and Hydropower Energy Assessment of Reclamation Owned Conduits, manmade water control structures managed by the Bureau of Reclamation have the potential to produce an additional 1.565 million MWh of electricity annually.

The U.S. Bureau of Reclamation is a federal water management agency within the Department of the Interior, already experienced at both water management and hydroelectric generation. The Bureau has built over 600 dams and reservoirs in 17 Western states, and is the largest wholesaler of water in the country as well as the second largest producer of hydroelectric power in the western United States. The Bureau's 58 powerplants produce over 40 billion kilowatt hours annually, generating nearly a billion dollars in revenue for the federal government.

Last year the Bureau of Reclamation performed a reconnaissance level assessment of the hydropower potential at 530 sites throughout Reclamation including dams, diversion dams, and some canals and tunnels. In its 2011 report, the Bureau found that 191 sites out of the 530 had some level of hydropower potential, with 70 of those sites (representing a total of 225 MW of generation capacity, or 1.2 million MWh annually) also showing some economic potential for hydropower development.

This year's report found 373 existing Bureau of Reclamation canals and conduits could be used to produce hydropower; together, they could generate an additional 365,219 megawatt-hours of hydropower annually.  Because these canals and conduits are both manmade and already existing, the development of hydroelectric generation facilities using their water may have relatively fewer adverse environmental impacts compared to building a new, traditional dam.  Congress is considering legislation to further enable the development of hydropower from these nontraditional resources, including H.R. 2842, the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act of 2011.

Torrefied wood: biomass to "biocoal"?

As society seeks improved fuels - and as forested regions seek new markets for forest products - torrefied wood or torrefied biomass is gathering interest.  Torrefaction is a roasting process in which wood or other raw biomass material is carefully heated to yield a higher-quality fuel for combustion or gasification. When combined with densification (think compressing, packing, and pelletizing), torrefied wood can be a fuel with a high energy density - and thus a high monetary value.

Trees growing in the Maine woods - is torrefaction in their future?

In torrefaction, raw wood or other biomass is typically heated to between 400 and 600 degrees F, a temperature selected to roast but not burn the material.  (Green coffee beans undergo a similar process when they are roasted.)  Wood and other raw plant material typically contains a large amount of water; this water is driven off by the torrefaction process, as are other volatile chemicals found in the raw material.  Heating also partially breaks down natural biopolymers in the wood (like cellulose, hemicellulose, and lignin), releasing even more volatiles.  The material left behind is solid, dry, and blackened: torrefied biomass.

Torrefied biomass has some advantages over raw wood as a fuel.  Because the volatile chemicals have already been driven off through torrefaction, the combustion of the biomass may have lower environmental emissions when it is finally used.  (A life-cycle analysis would take into account the volatiles driven off during torrefaction.)  Torrefied wood generally has a higher energy density than raw wood (some sources suggest 30% more), so it can be more cost-effective to transport and ship over longer distances.  This could open up more distant markets for forest products.  Torrefied biomass can also be mixed with coal to produce electricity in existing coal-fired power plants; this use, along with its dark color, has led some to call it “bio-coal”.

While torrefaction has been around for over a century, it is still in a relatively early phase in commercial use, particularly in the U.S.  What role will torrefied biomass play in the future of energy resources and forest products?

Utilities face smart meter hacking threat

Electric utilities are converting traditional electric meters to modern, remotely-readable smart meters - but some may be facing a new twist on electricity theft: hacking smart meters.

The term "smart meters" encompasses a variety of devices used by electric utilities to measure how much electric energy their customers consume.  In general, smart meters can eliminate the need for a meter reader to physically visit the customer's premises, relying instead on wireless radio frequency communication to tell the central office about the customer's consumption.  Many smart meters can also allow real-time tracking of customers' use of electricity, a precursor to time-of-use rates and other "smart grid" applications.  Federal and state regulators promote their installation, citing improved customer service, enhanced storm restoration efforts, and reduced costs for both ratepayers and utilities.

Cybersecurity blog KrebsOnSecurity has released part of a document that appears to be a bulletin by the Federal Bureau of Investigation noting a new threat: hacking smart meters.  According to the blog, a Puerto Rican utility may have lost "hundreds of millions of dollars annually" as a result of smart meter hacking.  Apparently some smart meter models are relatively vulnerable to being reprogrammed (or simply subverted) such that they underreport how much electricity the consumer is using.

Theft of electricity is not new, as people have likely attempted to bypass utility meters since their inception in the 19th century.  As society and the electric power industry have become increasingly digital, it may be inevitable that this trend would continue.  As utilities and regulators respond to the new threat, cybersecurity may play an important and increasing role.

Blythe solar project owner bankrupt

Solar energy project developer Solar Trust of America filed for bankruptcy this Monday, delivering a setback to what would be the largest solar energy project in the U.S.: the proposed 1,000 megawatt Blythe solar project under construction in the California desert.

Last April, I noted that the U.S. Department of Energy offered a conditional loan guarantee commitment to Solar Trust of America, a joint venture of German companies Solar Millennium AG and Ferrostaal Inc., for its solar energy project outside the city of Blythe, California, near the Arizona border.  DOE's conditional loan guarantee was offered to help finance the first two units at Blythe, which were originally planned to use parabolic trough mirrors to concentrate solar energy to boil water in a closed loop.  The resulting steam would spin turbine-generator sets to generate electricity. 

In August 2011, as photovoltaic cell prices fell, project partner Solar Millenium announced plans to convert the first 500 MW phase of the Blythe project to solar photovoltaics.  Photovoltaic technology appeared lower cost and more proven than the relatively complex solar thermal steam turbine generation originally conceived of for the project.  However, this shift in project design meant that the Blythe project could no longer take advantage of the federal loan guarantee.

Now, Solar Trust of America has filed for bankruptcy.  In its Chapter 11 filing, Solar Trust notes that its operations relied on funding from parent Solar Millenium - which filed for bankruptcy in December 2011, cutting off operating funds to Solar Trust.  Likewise, negotiations to sell the company and its projects failed when the prospective buyer, German firm solarhybrid, also went bankrupt.

What does the future hold for the Blythe project?  Along with the nearby Palen project (a two-phase, 500 MW solar thermal development, the Blythe project is Solar Trust's largest asset.  Whether Solar Trust or some successor picks up the pieces and moves forward remains to be seen, but presumably the investment to date in the Blythe project still retains significant value. 

Adding hydro to Army Corps dams

As an energy resource, hydroelectricity has great potential, but siting and environmental concerns make building a new dam in the U.S. difficult.  A new trend of adding renewable electric generation to existing non-hydroelectric dams may help the U.S. grow its hydropower production without building new dams.

Last month the Federal Energy Regulatory Commission issued a license for a new hydroelectric project in Vermont, the Townshend Dam Hydroelectric Project No. 13368.  The project, first proposed in 2010 by Blue Heron Hydro, LLC, involves the installation of hydroelectric turbine-generator arrays at the existing Townshend Dam on the West River near the town of Townshend, VT.  The Townshend Dam project is particularly interesting in that it represents a new model: upgrading existing dams without hydroelectric generation to be able to produce renewable electricity.

The U.S. Army Corps of Engineers owns and maintains the rock-and-earth-fill Townshend Dam, a structure 133 feet high and 1,700 feet long.  The Townshend Dam is part of a system of 14 dams that are operated to provide flood protection for the numerous communities along the Connecticut River.  In addition to flood control, the Corps operates Townshend Dam and Lake for fish and wildlife enhancement and recreation.

Blue Heron Hydro proposes to install twelve turbines and 77-kW submersible generators at the dam site, for a total of 924 kW.  As proposed, the turbines would not change the dam's current run-of-river operation but would rather divert water that currently spills over the dam to flow through the turbines, producing power.  A seasonal downstream fish passage facility would also be installed, primarily for Atlantic salmon.

FERC has now issued an original license for the project.  The license contains a variety of conditions and requirements, but grants Blue Heron Hydro the right to construct, operate, and maintain the project.

The Army Corps manages a portfolio of 693 dams, many of which do not currently have hydroelectric or hydrokinetic generation facilities installed.  Developers are exploring the opportunity to produce hydropower at many of these Army Corps sites, as well as at the thousands of other unpowered but existing dams across the country.  Will the near future bring more interest in adding hydroelectric generation to existing Army Corps dams?

Oil, from crude to fuels and chemicals

Petroleum - what we often think of as oil - powers a large sector of the world economy.  Crude oil, a naturally-occurring mix of substances produced by ancient life and transformed by time and geological forces, lies trapped beneath soil, rock, and the sea floor.  When captured and refined, the crude oil can be transformed into gasoline and diesel, but also into a wide variety of other fuels and chemicals.

In the U.S., crude oil is typically quantified in a 42-gallon unit known as the barrel.  While this bears some historic tie to actual barrels of oil, crude oil today is seldom packed in actual 42-gallon barrels, more typically being shipped in large seagoing oil tankers or pipelines.

At a refinery, each of the components of the crude oil mix is separated.  Some are converted from heavy, low-valued chemicals into lighter, higher-valued products like gasoline.  Processes like cracking, coking, and alkylation allow the production of more exotic petroleum derivatives.

From 42 gallons of crude oils, refineries can produce about 45 gallons of refined petroleum products. Typically, these might include:

• 19 gallons of gasoline
• 10 gallons of diesel
• 4 gallons of jet fuel
• 2 gallons of liquefied petroleum gases (propane, butane, etc.)
• 1 gallon of other distillates (heating oil)
• 2 gallons of residual fuel oil
• 7 gallons of other products

Most of this increase in total product volume comes as different fractions of the petroleum mix are distilled and transformed; the U.S. Energy Information Administration has described the increased volume after refining as "similar to what happens to popcorn, which gets bigger after it's popped".

Because each source of crude oil contains a different mix of hydrocarbons and other chemicals, the refining process yields different mixes of products for each type of crude. The demand for these products drives oil producers' decisions about where to drill and produce oil.

Deadline for offshore wind grants

Today marks the deadline for applicants to submit letters of intent to the U.S. Department of Energy seeking funding for offshore wind energy development.  On March 1, 2012, Secretary of Energy Steven Chu announced a six-year $180 million initiative to deploy offshore wind projects in U.S. waters.  Subject to congressional appropriations, this program includes $20 million available this year to support up to four innovative offshore wind energy installations across the United States.

The U.S. Department of Energy believes that the U.S. is rich in offshore wind resources.  Some reports have identified over 4,000 gigawatts of potential capacity, which adds up to several percent of the U.S.'s existing electric generation capacity across all fuels and resources.

To speed the development of this resource, DOE has proposed a competitive solicitation for grant funding for "Advanced Technology Demonstration Projects".  The goal is to install innovative offshore wind systems in U.S. waters in the most rapid and responsible manner possible, and expedite the development and deployment of innovative offshore wind energy systems with a credible potential for lowering the levelized cost of energy (LCOE) below 10 ¢/kWh or the local "hurdle" price at which offshore wind can compete with other regional generation sources without subsidies.

Applications must include certain materials as specified in the Funding Opportunity Announcement (docketed as DE-FOA-0000410).  The Department has stated that it expects applications to come from world-class multi-sector consortia, including energy project developers, equipment suppliers, research institutions and marine installation specialists.  Grant funds may be used to cover up to 80 percent of a project’s design costs and 50 percent of the hardware and installation costs. Letters of intent are due on March 30 and applications are due on May 31, 2012.

Net metering and utility charges

As more electricity customers are installing solar panels and other distributed generation, many are participating in net metering programs under which they can run their utility meter backwards -- but utilities are complaining that net metering customers don't pay their share of the grid's operating costs.

In states and utility territories where net metering is allowed, customers can use eligible distributed generation (typically renewable generation like solar photovoltaic or small-scale wind, or micro combined heat and power) to offset their consumption of electricity from the grid.  Even if the customer draws power from the grid at some times and injects power back onto the grid at other times, net metering or net energy billing allows the customer to offset distributed generation against purchases. 

While many states embrace net metering as a policy, some utilities complain that net metering customers can be free riders.  If a customer's solar panels produce as much power in a month as the customer consumed, net metering could credit that customer with a zero utility bill - even though at various times times, the customer relied on the grid for imports and exports.  As a result, some utilities are seeking to impose new charges on customers for net metering.  For example, last fall Virginia regulators approved part of utility Dominion's request to impose "standby" charges on certain net metering customers.  Solar advocates and other distributed generation interests typically oppose such charges as roadblocks to achieving the societal benefits of net metering.

The issue continues to simmer around the country.  California utility San Diego Gas & Electric Co. recently proposed adding a "network use charge" onto customers' bills.  SDG&E's concept was that the charge -- about $22 per month for the average net metering customer with a solar PV system -- would properly allocate the cost of maintaining the grid to these customers.  The utility argued that without the charge, net energy metering customers were being subsidized by all other customers.  Earlier this year, California regulators rejected the idea (see the 16-page order at the California Public Utilities Commission website), noting concerns that the proposed charge "may be inconsistent with current law, regardless of whether it is justified by cost causation principles or an analysis of the crosssubsidies inherent in current policies."  As a result, SDG&E refiled its rate application without the charge.