Energy Policy Update

Facebook data center power demand

2012-01-31T11:47:00.000-05:00

Facebook has revealed that its data center in Prineville, Oregon consumes 28 megawatts of electricity -- consistent with other comparably-sized data facilities, but a significant draw on the local electric grid. As data center operations grow, they will need reliable access to affordable electricity.

Data centers, which are centralized locations where computer servers store and process information, are in increasing demand. From managing the smart grid through real-time data collection and processing to managing information about online contacts, data centers support many of the activities consumers take for granted every day.

Fundamentally composed of electronic data storage and processing equipment, data centers can consume significant amounts of electricity. Managing the cost and environmental impacts of that power consumption is important to many data center operators. Some, like Google, have chosen to source renewable power for their data centers. Others pursue improved energy efficiency for their data centers.

In Facebook's case, the initial 300,000 square foot facility reportedly consumes up to 28 megawatts of power. By comparison, all of the other businesses and homes in Crook County reportedly consume just 30 megawatts of power, meaning Facebook's data center could already consume about half of the electricity in the region. Future phases might roughly triple that electricity consumption, and other businesses and governmental entities are considering siting data centers near Prineville's location in central Oregon.

Ener1 bankruptcy and DOE grant

2012-01-27T07:30:00.002-05:00

Battery maker Ener1 is in news for yesterday's Chapter 11 bankruptcy filing, two years after its subsidiary was awarded a $118.5 million grant from the U.S. Department of Energy.

Ener1 Inc. holds several operating companies. Its subsidiary EnerDel produces automotive-industry thin cell lithium-ion batteries in Indiana. Other subsidiaries focus on fuel cells and nanotechnology, as well as manufacturing automotive-grade lithium-ion batteries in South Korea.

Battery making unit EnerDel won the $118.5 federal grant in 2009 for its proposal to expand two battery factories in Indiana and add a third facility. Many of the details of the proposal are available in the final Environmental Assessment prepared by the Department of Energy in support of the incentive:

The proposed financial assistance would help EnerDel expand its manufacturing and testing capabilities at two existing facilities and start up a third facility for future development into a complete lithium-ion battery manufacturing plant. The existing EnerDel facilities consist of a 92,000-square-foot building in Indianapolis and a 32,000-square-foot building in Noblesville, just north of Indianapolis. The lithium-ion battery manufacturing capacity of the Indianapolis facility would increase through the addition of equipment, and the Noblesville location would transition into full use as a prototype development and battery testing facility through the addition and change-out of equipment. The exteriors of the Indianapolis and Noblesville facilities would be unchanged. The third facility is a newly acquired vacant warehouse near Greenfield, Indiana, just east of Indianapolis. This 423,000-square-foot building would require minor construction and equipment installation on the exterior of the building; however, essentially all of the work necessary to transform it into a manufacturing plant would consist of installation of equipment inside the building.

EnerDel received a $118.5 grant pursuant to a cost-sharing arrangement. Ener1 has since said that electric vehicles haven't caught on with drivers as quickly as it expected. Key customer, Norwegian electric vehicle maker Think Global, went bankrupt in June 2011.

Yesterday's bankruptcy filing by Ener1 comes at a time when policymakers are scrutinizing the energy department's grant and loan programs. Following the recent failures of other DOE loan guarantee and grant recipients such as Solyndra LLC and flywheel energy storage developer Beacon Power, Ener1's bankruptcy will likely add to the debate over the proper model for federal investment in the private sector energy industry.

Utah pumped storage project seeks license

2012-01-26T08:08:00.000-05:00

Electricity can be tricky to store once it is generated. Batteries, flywheels, and other energy storage technologies can provide some storage capacity, but pumped storage -- using electricity to pump water uphill during times of low power pricing, and letting it fall back down to generate electricity when needed -- is the most-used bulk electricity storage medium in the US. As of 2010, the United States was home to 21.5 gigawatts of pumped storage generating capacity. Pumped storage can be used both to balance supply and demand on the electric grid and to arbitrage fuel and electricity costs.

While some question whether electricity produced through pumped storage should qualify as renewable energy, pumped storage in the US is regulated by the Federal Energy Regulatory Commission as hydropower. Most pumped storage projects will ultimately need a FERC license, but obtaining a preliminary permit is a typical first step in the approval process. A preliminary permit gives a developer the right to investigate the feasibility of aproject, typically for a three-year term, and convey exclusive first priority to file for a full license during that window.

This month, a proposed pumped storage in the Utah desert applied for a preliminary permit. Utah Independent Power, Inc. filed its application to FERC for a preliminary permit for the Long Canyon Pumped Storage Project (18-page PDF). Utah Independent Power proposes to build two dams to store water drawn from the Colorado River near Moab, Utah. These dams would create an upper reservoir on the high plateau above Long Canyon and a lower reservoir at the end of Long Canyon. The developer suggests that the power required for pumping would be supplied to the proposed project through the transmission grid using existing off peak power, while power would be produced by the project during peak periods and sold through the Western Electricity Coordinating Council grid at competitive peak rates.

The principals behind Utah Independent Power are no strangers to investigating pumped storage projects, having been involved in other proposals in the desert Southwest in recent decades. Indeed, in 2008, Utah Independent Power applied for and obtained a preliminary permit for the Long Canyon Pumped Storage project. (Here is Utah Independent Power's 2008 application, and the Commission's 2008 order issuing preliminary permit.) Utah Independent Power surrendered that preliminary permit in 2011, along with another preliminary permit for the nearby Bull Canyon Pumped Storage project. Its 2012 Long Canyon application bears significant similarities to its earlier proposal, with some differences including a slightly lower upper dam.

Utah Independent Power's proposal is likely to trigger significant interest. On the one hand, being able to use existing natural resources -- in this case, Colorado River water and canyon topography -- to store electricity may be an attractive proposition. On the other hand, Colorado River water is already scarce and at the center of water right fights. Moreover, the Long Canyon project would lie close to scenic and protected lands, such as Dead Horse Point State Park and Canyonlands National Park. An existing jeep road runs along Long Canyon, and the area receives both motorized and non-motorized recreation. In 2008, the State of Utah filed comments questioning the applicant's rights to the necessary water and land, as well as the impacts to the viewshed and natural landscape from the dams, transmission lines, and other project facilities.

POET ethanol plant declines DOE loan guarantee

2012-01-25T08:06:00.000-05:00

Cellulosic ethanol producer POET LLC has declined a $105 million federal loan guarantee for its planned "Project LIBERTY" facility in Emmetsburg, Iowa, instead turning to private funding from Dutch company Royal DSM NV. This choice has implications both for energy policy and for the biofuels industry.

Last year brought an end to a US Department of Energy program to help fund innovative energy projects with loan guarantees. Before it ended in September 2011, DOE's Section 1705 loan guarantee program backstopped a total of $16 billion in loans for 28 projects ranging from nuclear power to solar, wind to transmission, biofuels to energy efficiency. Questions about the value and implementation of the loan program grew after the recipient of the first loan guarantee, solar panel maker Solyndra LLC, failed and went bankrupt.

Before the Section 1705 loan program ended, POET was awarded a guarantee for $105 million. POET is developing the Project LIBERTY plant, which aims to use cutting-edge enzymatic hydrolysis to produce fermentable sugars from corn crop waste, and then to use special yeasts to transform the sugar into usable ethanol. By 2013, the plant could be producing up to 25 million gallons per year.

This week POET announced that it was declining the DOE loan guarantee. Instead, POET will partner with Royal DSM, a private business that grew out of a former Dutch national coal-mining company. Together, the companies will invest up to $250 million in initial capital expenditures for Project LIBERTY.

What does POET's choice mean? For POET, the terms of the joint venture with Royal DSM are presumably more favorable than the alternative. Royal DSM's money is likely what made it most attractive to POET, but its experience and markets may have also played a role.

For Iowa, any financial arrangement that realizes $250 million in capital investments in the state is likely to be greeted with open arms.

For other ethanol producers, the deal may signal increased interest in ethanol from the investment community. The U.S. Environmental Protection Agency estimates that its renewable fuels standards will require 16 billion gallons of advanced cellulosic biofuel per year by 2022; using the Project LIBERTY plant as a model, this could mean up to 400 new biorefineries will be built by 2022 to meet these standards. By extension, other recipients of DOE loan guarantees may similarly partner with private-sector entities to complete project financing.

NYC tidal project gets pilot license

2012-01-24T08:07:00.000-05:00

Federal regulators have issued a pilot project license to a tidal power proposal to be developed in the East River off New York City. Yesterday the Federal Energy Regulatory Commission awarded a license to the Roosevelt Island Tidal Energy Project (62-page PDF).

As described in the license, the Roosevelt Island project will start relatively small, and is licensed for additional phases of growth. The first phase entails deployment of three 35-kW Kinetic Hydropower Systems developed by Verdant Power, LLC. Each of these units has a 5-meter diameter turbine connected to generator. Over time, additional turbine units could be deployed, up to a total of 30 turbines, for a total nameplate capacity of 1,050 kilowatts.

Verdant chose to seek a pilot project license for the Roosevelt Island tidal development. FERC views its hydrokinetic pilot project licensing process as a variant of its Integrated Licensing Process. Compared to other paths to FERC hydropower licenses, the pilot project process is designed to allow developers to test new hydrokinetic and hydropower technologies while minimizing both their costs and the risk of adverse environmental impacts.

Commission staff have described the ideal pilot project as (1) small, (2) short term, (3) located in environmentally 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. Based on the Roosevelt Island project's similarity to this conceptual ideal, FERC staff recommended that Verdant pursue a pilot project license.

Verdant's pilot project license includes a variety of conditions and mitigation requirements. Among these are a requirement that Verdant commence construction of Phase 1 within two years, and to complete construction of Phase 3 within six years of the issuance date of the license. If Verdant meets these deadlines, the Roosevelt Island could be producing electricity within the next few years.

Other innovative ocean energy projects are pursuing FERC's pilot project licensure path, such as the Cobscook Bay Tidal Energy Project proposed by Ocean Renewable Power Company Maine, LLC. Verdant's license is the first hydrokinetic pilot project license that FERC has issued; others may follow in its footsteps.

Wave, tidal energy potential in US waters

2012-01-23T11:33:00.000-05:00

The U.S. Department of Energy released two reports last week documenting two of the nation's potential ocean energy resources: waves and tidal streams. Hydrokinetic energy resources such as waves, tides, and currents may soon play an increasing role in US energy supply.

Although each of these reports was prepared in 2011, DOE is pointing to the reports as demonstrating the potential of conventional and innovative water power resources to generate electricity. In its statement promoting the reports, the Department of Energy noted that water power, including conventional hydropower and wave, tidal, and other water power resources, can potentially provide 15% of our nation's electricity by 2030 (up from 6% currently). As DOE noted, the United States currently uses about 4,000 terawatt hours (TWh) of electricity per year. Based on these reports, and other studies, DOE estimates that the maximum theoretical electric generation that could theoretically be produced from waves and tidal currents is approximately 1,420 TWh per year, approximately one-third of the nation's total annual electricity usag.

The wave energy assessment report, Mapping and Assessment of the United States Ocean Wave Energy Resource, was prepared by the Electric Power Research Institute (EPRI). That report identified a total available wave energy resource of 2,650 TWh per year. As in previous studies, Alaska's Pacific coast is the wave energy standout, hosting about half of the total available wave energy. The west coast (Washington, Oregon, and California), the northern east coast (from Maine through North Carolina), and Hawaii also host significant wave energy resources.

The tidal stream report, Assessment of Energy Production Potential from Tidal Streams in the United States, was prepared by Georgia Tech Research Corp. It describes the effort to create a national database of tidal stream energy potential. The geographic distribution of the tidal stream resource is similar to that of wave energy: Alaska contains the largest number of locations with "considerably high kinetic power density", followed by Maine, Washington, Oregon, California, New Hampshire, Massachusetts, New York, New Jersey, North and South Carolina, Georgia, and Florida. In total, the report identified 50 GW of tidal stream capacity nationwide, 47 GW of which is in Alaska.

The size of these resources is significant. What remains to be seen is whether hydrokinetic energy can be generated in a cost-effective manner. With significant research and developments ongoing, competitively-priced hydrokinetic power may soon be generated along US coasts.

Quick draw for hydrokinetic priority

2012-01-20T08:05:00.000-05:00

Last year, I noted the "gold rush" aspect of hydrokinetic energy development in the US, as developers raced to the Federal Energy Regulatory Commission to file claims on promising sites. Some of the most obvious areas for hydrokinetic development, such as the Mississippi River system, generated hundreds of applications for preliminary permits which would grant exclusive rights to study the site and prepare a first-priority license application within three years.

In some cases, multiple developers applied for a preliminary permit for the same site. Whoever files a valid application first is given first priority; developers filing an application for the same site later face an uphill battle as competing applicants.

In the heat of the gold rush, sometimes multiple applications come in with identical filing times. How does FERC resolve these disputes? A quick draw?

A random drawing, as it turns out. As long as the Commission believes that none of the applicants’ plans is better adapted than the others to develop, conserve, and utilize in the public interest the water resources of the region at issue, FERC uses a random drawing to resolve disputes over who gets to count as having been there first.

The Commission has used random drawings to assign priority to competing applications with identical filing times since at least 2009, when it granted first priority for a site to the city of Angoon, Alaska, defeating the cities of Petersburg and Wrangell. Since then, it has issued notices announcing filing priority for preliminary permit application at least 33 more times, most recently resolving ten disputes by random drawing this past Wednesday.

The need for such a mechanism highlights the booming interest in many high-value sites for generating innovative hydroelectricity without building new dams. The hydrokinetic quick draw may be a sign that the most promising sites have attracted competitive interest, even if the means of picking a temporary winner (typically a term of three years) is ultimately random.

Will Yarmouth remove dams?

2012-01-19T10:19:00.001-05:00

The town of Yarmouth, Maine holds a public hearing tonight on whether to remove two town-owned dams in the Royal River. The dams near Bridge Street and East Elm Street were built long ago to impound water and provide power to mills along the river's course to Casco Bay. As early as 1759, an iron mill used hydropower produced by the East Elm Street dam's predecessor. Over time, the dams were updated; in 1984, hydroelectric generation was installed at the Sparhawk Mill adjacent to the Bridge Street dam.

Last fall, dam removal advocates and the town held several meetings to discuss their removal. Although the dams are equipped with fishways operated by the Maine Department of Marine Resources, environmental and fisheries advocacy groups consider them nonfunctional.

At a December 2011 workshop, all five of Yarmouth's town councilors who were present agreed that the dams should be moved. To move forward with dam removal, the town will need both financing and regulatory approvals.

Tonight, the dam removal proposal faces a public hearing.

Frequency regulation and Order 755

2012-01-18T07:51:00.000-05:00

Managing an electric grid requires a constant balancing act: instantaneously matching supply and demand. Grid operators maintain this real-time balance using a variety of tools, from traditional generation dispatch to innovative demand response.

Among the many parameters that must be balanced is the frequency of the alternating current on the grid. Each element of the grid must operate not only in synch but at the same frequency -- in the U.S., typically about 60 hertz. If supply and demand become imbalanced, the frequency of the grid power shifts away from 60 Hz, causing equipment damage, reliability problems, and even safety risks.

Traditionally, grid operators instructed generators to ramp up or ramp down small amounts as needed to maintain frequency regulation. While this generator-based approach works by injecting additional power into the transmission grid where needed, new technologies exist that may be able to provide frequency regulation more effectively. Compared to generation resources, flywheels, batteries, and other energy storage technologies may be able to regulate the grid's frequency not only at a lower cost but also with fewer emissions and other environmental impacts, as they do not rely on incremental fuel consumption. Storage is considered more capable of matching the grid operator's constantly-changing regulation signal.

Energy storage resources can also respond more quickly to grid frequency disturbances, providing a valuable fast-response frequency regulation service.

A recent federal order is designed to compensate those who can provide fast-response frequency regulation most effectively. FERC Order 755 (123 page PDF) requires grid operators to compensate frequency regulation resources based on the actual service they provide. Previously, grid operators paid fast responders the same price for frequency response as that paid to other providers, without regard to the more valuable speed and power quality provided by fast responders.

Under Order 755, grid operators will have to pay fast-responding frequency regulation resources a quality-based price. Given the energy storage technologies now under development, many anticipate that Order No. 755 will give birth to an expanded frequency regulation industry. For example, estimates of the total frequency regulation market size for the organized electric markets in the U.S. range from 4,000 megawatts to 7,500 MW.

Matinicus Island energy options

2012-01-17T08:06:00.000-05:00

Residents of remote islands often face energy costs that are higher than those on the mainland. This can be for many reasons, most of which stem from islands' relatively small populations and remote locations.

Islands far enough offshore are often not connected to the mainland electric grid via submarine cables. If the island is to have its own electric grid, it must develop both generation and distribution wires. Some island communities are considering renewable energy resources like wind and solar, but for the most part diesel has fueled the bulk of electric generation on remote islands. Diesel can be expensive on the mainland, and is even more expensive when it needs to be shipped out to the island for consumption.

The Maine island of Matinicus fits this model. Located over 20 miles offshore, the 740-acre island is home to about 20 year-round residents and about 200 summer residents. Since 1965, the Matinicus Plantation Electric Company has provided electric utility service to islanders. The Matinicus utility is consumer-owned, meaning it is owned wholly by its consumers (as opposed to outside investors). Electric generation is provided by a set of diesel units: two rated at 45 kW and a third rated at 65 kW. The utility also maintains a 150 kW backup generator for emergencies. The company does not serve the nearby island of Criehaven, which lacks a centralized electric utility system.

How do the circumstances of Matinicus Island affect energy costs? In 2010, the Matinicus utility sold 225,000 kWh of electricity at an average rate of 65.2 cents per kWh, or about 4 times the average price residential customers pay on the mainland. Producing this power required burning a fair amount of diesel - about 40,000 gallons per year. Many islanders pay about $200 per month for electricity.

The desire to cut costs and enhance the local environment have led to several proposals to switch Matinicus to renewable resources in recent decades. Some commenters have suggested Matinicus could pursue an island-based wind project as Vinalhaven did, while others view the site as inappropriate. Others have suggested floating offshore wind could be a match for Matinicus; next summer's test installation of a floating offshore wind turbine off Monhegan could help us understand the impacts of such a project near Matinicus. Other renewable ocean resources, like tidal energy, could one day play a role in the island's energy portfolio. For any such project to succeed, it will have to be both cost-effective and palatable to island residents. Until then, residents and visitors alike can look to the island's diesel generators as the primary source of electricity.

Google grows wind power supply

2012-01-16T13:39:00.000-05:00

Google Energy LLC, a subsidiary of internet search company Google Inc., recently informed federal regulators of a long-term power purchase agreement with a 100.8-megawatt wind-powered electric generation project in Oklahoma.

Under the deal, Google agreed to buy all of the energy output from Minco Wind II, LLC's wind project for a term of 20 years. Minco Wind II is operated by a subsidiary of NextEra Energy Resources. As part of the deal, Google can claim that it is powering a data center in Pryor, OK, with power from the wind project.

The Oklahoma PPA nearly doubles the amount of wind capacity under contract by Google. In 2010, Google Energy entered into a power purchase agreement to buy 114 MW of wind from Garden Wind, LLC. Garden Wind, also a NextEra subsidiary, owns and operates a 150 MW wind project in Iowa. Garden Wind sold Google Energy a 76% share of the project's output for a term of 20 years. In addition, Google indirectly owns a 20.5% interest in Peace Garden Wind, LLC, which owns and operates about 169 MW of wind generation in the central region.

This comes two months after Google announced it was scaling back its program aimed at making renewable energy cost less than coal. Google's RE

Maine net energy billing

2012-01-13T10:37:00.000-05:00

Maine's net energy billing program gives electricity consumers have the opportunity to offset their electric bill by generating electricity themselves. This not only supports small-scale and some community-based renewable and efficient electric generation, but can provide customers a significant financial incentive.

Net energy billing is Maine's form of net metering, which allows electric customers with small-scale wind generators, solar panels or other renewable and efficient generation units to sell the power they produce to the utility grid. In exchange, the utility banks credits that are used to offset the customer's bill for power purchased from the grid. If the customer generates more electricity in a month than it uses, credits can be banked and carried forward for a 12-month period to offset future bills.

Net energy billing customers can not only sell their power to the grid and bank it for later, but also receive a favorable exchange rate. Most electric generators who sell to the grid are paid a relatively low wholesale rate, but net energy billing customers are credited at the higher retail rate. This can provide participating customers a significant financial edge, and could be used to enhance the value of existing community-scale renewable generation such as a small hydroelectric facility.

Maine has offered various forms of net metering since 1987, making it an early leader in the practice. Many other states have adopted net metering programs, and Congress has directed states to make net metering available to consumers. Maine's net energy billing program has evolved over time, and now applies to a variety of technologies including solar photovoltaics, wind, biomass, small hydroelectric, hydrokinetic or tidal, geothermal electric, renewable-based fuel cells, and micro-combined heat and power (micro-CHP).

Maine's net energy billing program has several special features. Generation projects don't have to be located at the same place as the net metering customer. Maine allows virtual net metering, where a generator meter can be netted against its owner's meter no matter where each is located, as long as both are in the same utility's service territory.

Maine also allows customers to pool together to develop a net metering project. This so-called "shared ownership billing" allows multiple customers with an ownership interest in a project to share in the benefits of net metering, and may enable more cost-effective projects through the economies of scale.

On top of all this, customers can combine the benefits of net metering with other incentives. For example, such as grant and rebate funding for qualified projects through state-level energy offices or program support through several federal agencies.

Here are links to the net metering webpages of Maine's three large utilities: Central Maine Power, Bangor Hydro-Electric, and Maine Public Service.

Vermont considers renewable energy law

2012-01-12T08:05:00.000-05:00

The Vermont Legislature is considering a proposal to enact a renewable portfolio standard, a law requiring utilities to source a specified percentage of their electricity from eligible renewable resources. If enacted, Bill S-170 (72-page PDF) could change Vermont's energy landscape.

Power lines run through a field near Colchester Pond, Vermont.

Today, Vermont is the only New England state not to have a statutory renewable portfolio standard, or RPS. Instead, Vermont's approach to renewable energy has focused on SPEED, or the Sustainably Priced Energy Enterprise Development Program. SPEED's goal is that by 2012, at least 10% of the state's 2005-eraelectric load be served by new sources of renewable energy, or 20% of total load by 2017. To further that goal, SPEED created incentives such as a feed-in tariff designed to encourage new renewable development. Unlike true RPS programs in other states, the Vermont program's targets are not strictly binding.

Bill S-170 would take Vermont away from the goal-based model and toward a firm renewable energy mandate. The bill would create a two-tiered RPS, with a "tier one" for projects coming into service during 2005-2012 and a "tier two" for projects coming online in 2013 and later. The bill would require utilities to source power from new renewable resources in each of these categories, plus additional power from existing renewable facilities. In 2013, utilities would have to source 40% of their power from existing renewable resources, plus 10% more from "tier one" new resources. Over time, the requirement would grow; by 2025, utilities would have to add in 40% from "tier two" resources, adding up to environmental attributes representing 90% of total annual retail sales.

The bill also proposes to keep a revised version of SPEED alive, as well as a requirement that Vermont energy consumption be net-zero of carbon emissions by 2025, and provisiosn for a climate change education campaign. S-170 bill has been assigned to a legislative committee for review.

Cobscook tidal project environmental review

2012-01-11T08:07:00.000-05:00

A tidal energy project proposed in Maine has passed an initial federal environmental review. Federal regulators have released an environmental assessment of the Cobscook Bay Tidal Energy Project (182-page PDF), finding generally that licensing the hydrokinetic project with appropriate environmental protective measures would not constitute a major federal action that would significantly affect the quality of the human environment.

The Cobscook Bay project is proposed by Ocean Renewable Power Company Maine, LLC. ORPC proposes to develop a 300 kilowatt hydrokinetic project in Cobscook Bay near the city of Eastport and the town of Lubec, Maine. The project entails five cross-flow hydrokinetic turbine generator units, each with a rated capacity of 60 kW. According to FERC, the project's construction will cost an estimated $11.5 million, with operation and maintenance adding $146,000 per year. Staff's analysis suggests that during its first year of operation, the project would produce power at a cost that is $1.3 million more than the cost of alternative power (or about 1 cent per kWh above alternative power).

ORPC Maine has applied to the Federal Energy Regulatory Commission for an 8-year pilot license for the Cobscook project. Under the National Environmental Policy Act, federal agencies must evaluate the environmental impacts of agency actions such as issuing licenses for energy projects. Performing an environmental assessment is one step in the NEPA process. If the agency concludes that issuing the license would have relatively minor environmental impacts, as the FERC did for the Cobscook project, it can avoid the more stringent review process of preparing an environmental impact statement.

In the Cobscook project's environmental assessment, FERC staff recommended licensing the project with several additional modifications. FERC invites public comment for 30 days following publication of notice of the environmental assessment.

Park and forest service renewable energy

2012-01-10T07:42:00.000-05:00

Managers of national and state parks and forests are considering whether they can cut their energy bill by developing distributed generation projects. In many cases, distributed generation such as solar photovoltaic systems can be a good match for powering facilities like park headquarters, campgrounds, and maintenance buildings. This can be especially true for places that are off the main electric grid, such as pockets of development within preserved lands. It can also be true for grid-tied facilities, as incentives like net metering can make rooftop solar or other projects cost-effective for the end user.

Solar photovoltaic panels power the campground at Goblin Valley State Park, Utah.

Whether developed by a national park or state forest, connecting renewable generation to the grid involves working with the local electric utility. In many parts of the country, interconnecting with the utility can be a challenging process. Utilities typically must study whether the proposed generation can work with the existing set of transmission and distribution wires, and may get into disputes with customers over whether and how much upgrading is needed. Some utilities claim to be swamped with interconnection requests, and are missing deadlines for studying system impacts and cooperating with customers.

In California, a different set of difficulties is preventing millions of dollars of renewable energy projects on federal land from connecting to the grid. In response to economic incentives favoring distributed generation, the National Park Service and U.S. Forest Service have developed major new renewable projects at a variety of sites in California. For example, the Park Service developed an $800,000 solar project at Death Valley National Park, anticipated to cut 70% off the visitor center's annual electric bill of about $45,724. The Forest Service developed a large solar project at its Mono Lake facilities, along with other projects at existing sites. However, the federal agencies have been unable to sign interconnection agreements with utility Southern California Edison, meaning the parks' renewable projects remain idle despite federal policy supporting sustainable operations.

At issue is a provision of federal law that prevents agencies from signing contracts exposing them to the risk of unknown future damages because such contracts would commit money outside the congressional budgeting process. Federal agencies have been able to work around this restriction with other utilities, as evidenced by Yosemite National Park's successful interconnection of its $5.8 million solar photovoltaic project with the Pacific Gas & Electric grid. Southern California Edison appears to be a holdout.

Will 2012 see a continuation of the trend toward replacing diesel electric generation in parks and national forests with alternative resources?

Alaska proposes large new dam

2012-01-09T08:05:00.000-05:00

The Alaska Energy Authority has filed key documents with federal regulators giving formal notice of its intent to build the proposed 600 megawatt Susitna-Watana Hydroelectric Project. If this project is approved and built, it will be the largest hydroelectric project developed in the U.S. since 1966.

Plans to develop a large-scale hydropower project on the Susitna river have been considered for decades. In 2010, the Alaska Legislature established a goal of providing half of the state’s electric power from renewable sources by 2025. The Alaska Energy Authority, a public corporation of the state whose mission is to use Alaska's natural resources to produce electricity and lower costs, concluded that Alaska could not meet the 50% renewable goal without building a major new hydroelectric project.

On December 29, 2011, the Alaska Energy Authority filed a notification of intent to file an application for a hydroelectric license and a pre-application document with the Federal Energy Regulatory Commission. FERC docketed the project as No. 14241. (You can read these documents in FERC's eLibrary here.)

In those documents, the Alaska Energy Authority described the project as located about 180 miles north of Anchorage. The dam itself would be large: 700 to 800 feet in height, and with a crest length of over 2,700 feet. The dam would impound a 39-mile-long reservoir, flooding 20,000 acres and capable of storing about 2,400,000 acre-feet. The Authority plans to install three 200 MW turbine-generator sets for a total installed capacity of 600 MW, but is considering up to 800 MW of capacity.

The Authority expects the FERC hydropower licensing process to take up to 6 years. The size and impacts of the project make it attractive to some yet controversial to others. Public comments are already being filed in the FERC docket.

Environmental regulations and grid reliability

2012-01-06T09:49:00.000-05:00

As newly approved air emissions regulations for electric utility plants begin to take effect, federal and state regulators are forming plans to maintain the reliability of the electric grid while complying with the new regulations. Last month, the U.S. Environmental Protection Agency issued its final Mercury and Air Toxics Standards. The MATS rules require many utility generation units to use "maximum achievable control technology". For this reason, the rules are sometimes also known as "utility MACT".

Before the rules were finalized, the nation's electric reliability organization NERC expressed concerns that the new air emissions rules could increase the risk of power outages and stress on the grid by forcing the early retirement of a significant portion of the nation's coal-fired generating stations. In a battle of words that played out over November and December 2011, EPA and the U.S. Department of Energy countered by pointing out flaws in NERC's analysis. The federal agencies also noted that NERC seemed to assume that no one would plan for or manage grid reliability in the face of coal plant retirements. Nevertheless, the mercury standards and other anticipated rules are likely to affect the electric power industry to some degree.

Now that the air standards are final, federal and state energy regulators are planning a series of meetings to explore reliability issues provoked by these new and pending environmental rules for the power sector. Commissioners from the Federal Energy Regulatory Commission (FERC) and will meet with members of the National Association of Regulatory Utility Commissioners (NARUC), the national organization of state public utilities commissioners.

FERC and NARUC hope that the open forum will provoke a broad discussion of utility issues in the wake of the new environmental regulations. The first meeting of the FERC-NARUC Forum on Reliability and the Environment will take place in Washington on February 7, 2012.

Data center energy use, consolidation

2012-01-05T11:40:00.000-05:00

Data centers - centralized locations where computer servers store and process information - play a key role in the function of society today. Demand for data center capacity is growing, as more and more digital information is collected and used to refine our technological experiences. For example, the growth of a smart electric grid relies in part on real-time data collection and analysis on a massive scale.

Data centers consume significant amounts of energy, primarily in the form of electricity. Progress in computer energy efficiency has reduced data centers' electricity consumption per unit of capacity, but the overall growth of data center capacity means they consume more and more electricity every year. Some data centers choose to buy renewable energy to serve their needs. In addition, data centers typically need cooling capacity, creating additional energy demand.

Energy costs are driving some data centers to consolidate. For example, many data centers in the U.S. serve federal agencies. In 2010, the federal government began a major effort to consolidate data centers and close unneeded facilities. The Federal Data Center Consolidation Initiative is designed to promote "Green IT" principles by reducing the overall energy and real estate footprints of government data centers and reduce data center costs. If the initiative succeeds in its mission, it will shift investment towards more efficient technologies. Another anticipated benefit of consolidating data centers is enhanced IT security.

As the initiative developed, agencies identified 3,133 federal data centers -- nearly three times as many as the nation's Chief Information Officer initially posited. This growth is due in part to a broadened threshold for what counts as a data center, but also reflects imperfect information about total federal assets. Of these facilities, the initiative now plans to close roughly 40%, or at least 1,200 data center locations. According to the CIO's list, 525 will be closed by the end of 2012.

Many of the surplus facilities pruned off by the federal data center consolidation initiative may continue life in the private sector. New owners may succeed if they can manage these data centers' energy consumption and benefit from participation in creative energy strategies like demand response or net metering distributed generation.

Community-based renewable energy in Maine

2011-12-30T14:18:00.000-05:00

An innovative program in Maine seeks to facilitate the development of community-based renewable energy projects. The program offers significant incentives for the development of qualified electric generation projects of up to 10 MW in size.

In 2009, the Maine legislature enacted a law establishing the Community-Based Renewable Energy Pilot Program to encourage the sustainable development of community-based renewable energy. By community-based, Maine's program targets locally-owned community-scale projects (as opposed to large-scale renewable projects owned primarily by out-of-state entities).

Under the program, qualified renewable energy projects can receive significant incentives including a long-term contract to sell the facility’s output to a Maine transmission and distribution utility for up to 20 years at average prices up to $100 per MWh (equivalent to 10¢ per kWh). This incentive is attractive because not only can the contract prices be above average market prices, but also the long-term power purchase agreement makes projects easier to finance by enhancing revenue certainty.

Eligible projects can apply to the Maine Public Utilities Commission for certification as community-based renewable energy projects. This process involves making public filings, negotiating with Commission staff, and demonstrating that the project meets the program’s qualification requirements. These include restrictions on resource type, nameplate capacity, and ownership.

Under the pilot program, eligible resources include:

fuel cells
tidal power
solar energy
wind systems
geothermal systems
hydroelectric generators
generators fueled by landfill gas
biomass generators whose fuel includes anaerobic digestion of agricultural products, byproducts or wastes.

Each individual project must not exceed 10 MW in nameplate capacity. Projects must also be primarily locally owned, meaning that 51% or more of the facility must be owned by Maine residents, governmental entities, businesses, or other qualifying local owners.

Once certified, a qualified project can choose either of two incentives:a long-term contract for the output of the facility with a transmission and distribution utility, ora renewable energy credit (REC) multiplier giving a 50% bonus in the amount of RECs produced.

To date, most have viewed the long-term contract as the more attractive option. Under this incentive, projects meeting the program’s requirements can obtain a contract at a fixed or variable price, provided that two criteria are met. First, the average price per kilowatt-hour must not exceed 10 cents. Second, the cost of the contract must not exceed the cost of the project plus a reasonable rate of return on investment as determined by the Commission. These contracts may be approved for up to 20 year terms. Projects smaller than 1 MW can contract directly with the utility, while larger projects go through a competitive process held periodically by the Commission.

What will 2012 bring for Maine's community-based renewable energy pilot program?

Municipal hydrokinetic energy

2011-12-29T07:06:00.000-05:00

Interest is increasing in municipal hydrokinetic energy projects, as cities and towns consider whether they should generate renewable electricity from their water resources. Hydrokineticsentails generating electricity from moving water such as tides, waves, andfree-flowing rivers. Towns, states, and national governments may not only have an interest in generating power for their citizens, but may also have advantages in project development such as lower financing costs.

For example, the town of Wiscasset, Maine is considering whether to pursue a project togenerate electricity from tidal power in the Sheepscot River. The town thinks that tidal currents andflowing water in the Sheepscot could be used to generate electricity usinghydrokinetic technology. In 2008, the town applied to the Federal Energy RegulatoryCommission for a preliminary permit to study the feasibility of theproject. Wiscasset proposed to deploy aseries of hydrokinetic turbine generating units in the tidal Sheepscot, alongwith associated transmission facilities. Currently, Wiscasset appears to be considering using the RivGen unitsunder design by ORPC.

In May 2009, the FERCgranted Wiscasset its preliminary permit. Preliminary permits confer the right to investigate the feasibility of ahydropower project, typically for a three-year term. Preliminary permits do not authorize actualconstruction; to actually build and operate a hydrokinetic or hydroelectricproject generally requires a FERC license or exemption. The holder of a preliminary permit does havefirst priority to file for a full license as long as the preliminary permit remainsin effect, and FERC expects permittees to make progress toward ultimatelicensure. (For example, inSeptember 2011 a company affiliated with ORPC used its preliminary permitpriority to file a pilot license application for the Cobscook Bay Tidal EnergyProject.)

Next spring, the town faces a key deadline if it chooses toseek a hydrokinetic pilot project license for the project. Wiscasset’s preliminary permit is set toexpire on April 30, 2012. Filings in theproject’s FERC docket suggest that the town may seek to extend that deadline. For example, in a May 2011 filing, the townsaid, “we anticipate the Wiscasset Project will apply for a successivePreliminary Permit in May 2012”.

Generally, preliminary permits expire after three years, after which the original permittee has no special rights to the site. In certain circumstances, federal regulators can grantsuccessive preliminary permits. Forexample, FERC has given several municipal hydroelectric projects successivepreliminary permits when the towns need more time. Even this requires a showing of diligent effortsto investigate the project’s feasibility and partial progress toward readinessfor a license application.

In Wiscasset’s case, other deadlines within the preliminary permit process have already beenextended. For example, the 2009 preliminarypermit required the town to submit a Notice of Intent and draft licenseapplication in May 2011. Instead offiling these pre-application documents, the town chose to ask FERC for an extensionto allow more site studies and stakeholder consultation. FERC allowed the town more time, but onlyuntil the preliminary permit expires on April 30, 2012. FERC may give the town similar leniency if itapplies for a successive preliminary permit this spring. On the other hand, FERC promotes competitionand discourages “site-banking”; if someone else showed interest in developingthe Wiscasset site, FERC might be less inclined to issue the town a successivepreliminary permit.

Wiscasset has until the end of April 2012 to either file alicense or seek its successive preliminary permit. If Wiscasset moves forward, the Sheepscot hydrokinetic project could be an example of how towns can benefit from their renewable energy resources.

Court upholds Cape Wind PPA

2011-12-28T12:11:00.002-05:00

The proposed Cape Wind offshore wind project won a legal victory today, as the Massachusetts Supreme Judicial Court has upheld the power purchase agreement between Cape Wind and utility National Grid.

Back in November 2010, the Massachusetts Department of Public Utilities approved a long-term contract between National Grid and Cape Wind. Under the approved power purchase agreement, the utility agreed to buy half of the output from Cape Wind’s project for 15 years. Pricing for the power would start at 18.7 cents per kilowatt-hour, escalating 3.5 percent annually. The state regulator concluded that the benefits of the contract exceed its costs, even though the Department found that the contract will most likely cost ratepayers between $420 million and $695 million above market prices over its 15-year term.

Many parties participated in the case before the Department of Public Utilities over whether the contract should be approved. When the Department approved the contract, several of these parties appealed to Massachusetts’ highest court. These appellants included trade groups for industrial energy consumers, traditional power generators, an international energy company and a group opposed to the project. Challengers filed a variety of legal claims, including that the Department lacked authority to approve the contract given its high costs, alleged lack of competitive bidding, and even potential violations of the Massachusetts Green Communities Act.

Today the Supreme Judicial Court issued its written opinion upholding the Department’s decision to approve the PPA. In the opinion, the court found that the record before the Department contained sufficient evidence for the Department to conclude that the Cape Wind contract’s special benefits exceeded those of other renewable energy resources. The court also agreed that it was proper for the Department to find that those environmental benefits would accrue to all of National Grid’s customers, and thus to spreadthe contract’s above-market costs across its rate base.

EPA finalizes utility air emission regulations

2011-12-22T14:50:00.000-05:00

New federal environmental regulations on utility air emissions have been finalized, but their impact on electricity costs and grid reliability remains to be seen. The US Environmental Protection Agency has released its final rule for power plant air emissions. (Here's EPA's Final Rule, a 1,117-page PDF.) These rules, formally known as the Mercury and Air Toxics Standards or MATS, are also known as "utility MACT" because they require many utility generation units to use "maximum achievable control technology". The rule gives utility electric generation plants three years to comply with tighter air pollution control requirements.

Even before the rule was finalized, it provoked controversy over how it could impact electricity prices and the reliability of the US electric grid. According to the US Energy Information Administration, in 2010 coal was used to generate about 45% of the electricity consumed in the United States. The nation's electric reliability organization, NERC, released a report suggesting the new rules would force the early retirement of a significant portion of the nation's coal-fired generating stations. In NERC's analysis, if EPA's air rules force needed generators to shut down, the reliability of the electric grid could be at risk.

EPA and the Department of Energy disputed NERC's assumptions. Ultimately, EPA issued its final rule on December 21, 2011.

President Obama expressed his support for EPA's new rule. In a Presidential Memorandum, President Obama described how the new rules would improve air quality and public health. President Obama also explicitly addressed the linkage between these rules and grid reliability:

These new standards will promote the transition to a cleaner and more efficient U.S. electric power system. This system as a whole is critical infrastructure that plays a key role in the functioning of all facets of the U.S. economy, and maintaining its stability and reliability is of critical importance. It is therefore crucial that implementation of the MATS Rule proceed in a cost-effective manner that ensures electric reliability.

Analyses conducted by the EPA and the Department of Energy (DOE) indicate that the MATS Rule is not anticipated to compromise electric generating resource adequacy in any region of the country. The Clean Air Act offers a number of implementation flexibilities, and the EPA has a long and successful history of using those flexibilities to ensure a smooth transition to cleaner technologies.

The President also directed a coordinated process to plan and execute measures needed to implement the rule while maintaining the reliability of the electric power system. This process should be designed to "promote predictability and reduce uncertainty," and should include engagement and coordination with a broad array of stakeholders including the DOE, the Federal Energy Regulatory Commission, state utility regulators, regional transmission organizations, the North American Electric Reliability Corporation and regional electric reliability organizations, other grid planning authorities, and electric utilities.

FERC Order 755 promotes energy storage

2011-12-21T11:44:00.000-05:00

New technologies have the promise to help electric grid operators perform the challenging task of balancing supply and demand at all times. This means making sure there the exact amount of electricity is being generated across the region as is demanded by consumers at that very moment. Line losses and the constraints of each local transmission and distribution system add complication. If the grid gets out of balance, problems arise with the electricity's frequency and power quality. In the worst case, failure can lead to cascading blackout, and safety can be at issue.

Historically, the balancing act has involved sending coordinated dispatch instructions to generators and demand response resources. Rules typically guide the grid operator in telling individual generating units to operate at specific levels. For example, flows through hydroelectric turbines can be varied, or fuel can be added to boilers or combustion turbines at a faster or slower rate. Through careful management, these conventional generation resources have been used to balance supply and demand, providing services known as frequency response and frequency regulation.

Though it is partly automated and well-practiced, this conventional resource dispatch process does take some time to take effect. Energy storage technologies such as flywheels, and batteries can not only provide frequency regulation, but can engage and ramp up much faster than conventional resources can. These faster-ramping resources could provide the grid relief in real time, as opposed to ramping up more slowly like conventional generation.

In most US markets, providers of efficient fast-ramping frequency regulation have been compensated the same as when conventional units provide regulation service, even when using fast-ramping resources is more efficient. At times this has meant that conventional resources have been dispatched when fast-ramping ones would have been lower-cost (and less polluting). For these reasons, this October the Federal Energy Regulatory Commission found that the current frequency regulation compensation practices "result in rates that are unjust, unreasonable, and unduly discriminatory or preferential."

In Order No. 755, FERC issued a final rule requiring the grid operators in organized markets to compensate frequency regulation resources based on the actual service they provide. Under Order 755 (123 page PDF), this must include separate payments for capacity (the marginal unit’s opportunity costs of being available) and for your actual performance.

Winners under Order 755 include providers of fast-ramping frequency response. These could include developers and operators of flywheel energy storage companies like Beacon Power, battery storage facilities, and compressed air energy storage, and other resources still in the conceptual phase. Winners also include energy consumers in the markets affected by Order 755, who should benefit from lower costs through improved operational and economic efficiency.

Could net metering save municipal hydro?

2011-12-20T12:15:00.001-05:00

Two dams on the Royal River in Yarmouth, Maine are one step closer to removal, as a majority of the town council agreed earlier this month that the dams should be removed. The town owns two dams near Bridge Street and East Elm Street, which provided mechanical power to mills as early as 1816. The Sparhawk Mill site near Bridge Street was upgraded to produce hydroelectricity in 1984, and operates as a privately-owned hydroelectric project exempt from most Federal Energy Regulatory Commission regulation. Yarmouth has considered dam removal for several years, with concerns over fish habitat restoration as the driving factor.

The push to remove the dams comes despite the value of the sites' ability to generate renewable electricity. A consultant hired by the town in 2010 estimated that the Bridge Street site could theoretically produce over $150,000 in annual hydropower revenues (7 page PDF), with $55,000 being a more realistic estimate of practical production from the existing facilities if they could be repaired and maintained. In reaching this figure, the report assumed the then-current energy price of 7 cents per kilowatt-hour (kWh). The report also assumed that the project could qualify for net metering, which the report defined as "unused power is purchased by the utility".

Maine's style of net metering is slightly different from that suggested in the report. Under what Maine calls net energy billing, the owner of an eligible renewable or micro combined heat and power (CHP) can use the generation facility to offset its consumption of electricity from the grid, effectively running its electric meter backwards. If a customer generates more electricity than it uses in any given month, the utility banks the excess amount as credits to be used within the next year.

One advantage gained by a net metering customer is that when generation offsets consumption, the customer saves on more than just the energy component of its electric bill. In Maine's electricity market, customers pay for both the energy they use and what it costs to deliver that energy over transmission and distribution wires. Today, the standard offer energy price for residential and small commercial customers in Central Maine Power's territory (including Yarmouth) is 7.4 cents per kWh. The Maine Public Utilities Commission reports that delivery fees add another 6.47 cents per kWh for residential customers, or 6.3 cents for small commercial customers. Thus the total cost to these customers of buying electricity and having it delivered is closer to 13.7 cents per kWh - nearly double that assumed in the town's report. This higher figure may more accurately reflect what the town could save by net metering the Sparhawk Mill project's output against its consumption.

Maine also allows more than one customer to cooperate in net metering. One eligible generation project can be used to offset consumption on up to 10 customer accounts, provided the participating customers establish partial ownership or an entitlement to the part of the project's output. This shared ownership net metering lets eligible projects reach their full potential, even when they can produce more electricity than the primary owner needs in a year.

If the town can take the full value of net metering into account and find a way to benefit from the existing renewable generation at the Sparhawk site, the economics would tip towards keeping the Sparhawk project running. There are other ways that project revenues could be boosted by smart participation in other energy programs, such as selling capacity or renewable energy certificates (RECs) if the project can be certified as renewable.

Would reevaluating the Royal River dam's hydropower potential lead the town to a different conclusion on whether the dam should be removed? The Yarmouth town council is holding a workshop session on January 5 and a public hearing on January 19 to discuss next steps.

Net metering charges in Virginia

2011-12-15T07:45:00.000-05:00

Virginia regulators recently approved an electric utility's request to impose additional charges on net metering customers with rooftop solar panels or other customer-sited generation.

Net metering -- when utility customers can offset their electric bill by using their own generation -- is a tool to encourage the spread of small-scale generating resources. Under net metering programs, customers are billed not based on how much electricity they buy from the grid over a given month, but rather based on their purchases netted against what they export from their own generation. For example, a home or business with solar photovoltaic panels on its roof could use net metering to run its utility bill backwards to the point where the customer has no bill at all. In some areas, customers can even run up a surplus of power through net metering.

Net metering facilitates distributed generation, in contrast to the centralized utility model that has historically prevailed. Mixing in some distributed grid-tied generation has advantages for the whole system, such as a reduced need for expensive new transmission lines. To promote the distributed model, Congress directed electric utilities to make net metering available as part of the Energy Policy Act of 2005.

Now, nearly all U.S. jurisdictions have net metering programs. Each state's implementation of net metering is unique. For example, under Virginia law, residential net meterers must pay their utility a "standby charge" -- a monthly amount to compensate the utility for the customer's ability to draw electricity from the grid, even beyond what would be charged under its net-metered bill.

Earlier, I noted that utility Dominion Virginia Power had asked the Virginia State Corporation Commission to approve “standby” charges on residential net-metered solarphotovoltaic systems larger than 10 kW. Last month, the State Corporation Commission approved part of the utility's request. The Commission approved a standby charge for transmission and distribution service - $2.79 per kW in monthly distribution standby charges and $1.40 per kW in monthly transmission standby charges. The Commission denied Dominion's request for generation standby charges for now, but encouraged the utility to come back for another proceeding to determine whether a generation standby charge would be proper.

Alaska's Susitna hydro project revived

2011-12-14T07:31:00.000-05:00

A large hydroelectric project proposed by Alaska's public power authority is moving closer to reality. With over 600 megawatts of electric generating capacity, the Susitna-Watana Hydroelectric Project would be the largest dam built in the U.S. since 1966, when the Glen Canyon Dam was built on the Colorado River in Arizona. If built, the Susitna project would represent a return to both mega-scale hydro and state-backed hydroelectric development in the United States.

The Susitna River project has been under consideration for nearly 50 years, although environmental concerns and the relatively low cost of oil dampened interest in the project for much of that time. Increasing fossil fuel costs, renewable energy targets, and interest in exploiting the state's sovereign resources have now led to a revival of the project. In 2011, Alaska state legislators unanimously approved funding for the Alaska Energy Authority to pursue the project.

The Alaska Energy Authority (AEA) was created by the Alaska Legislature as a public corporation of the state, albeit with a separate and independent legal existence. AEA's missions include reducing the cost of electricity in Alaska, and constructing, acquiring, financing, and operating projects that utilize Alaska's natural resources to produce electricity and heat.

Renewed interest in the Susitna project comes partly in response to Alaska's renewable portfolio standard law. In 2010, the Alaska Legislature enacted House Bill 306, creating a goal that the state receive 50% of its electric generation from renewable and alternative energy sources by 2025. The project could also produce low-cost electricity, with generation costs projected to be lower than natural gas over the life of the project, possibly significantly lower once the project's financing is paid off.

AEA now plans to follow the traditional process for licensing hydroelectric projects through the Federal Energy Regulatory Commission. AEA is expected to file its pre-application document with FERC on December 29, 2011, with the license review process expected to take up to six years.

If the Susitna project is built, it will be a departure from the recent trend of dam removal. Some observers have argued that the era of building large-scale hydroelectric facilities in the United States ended decades ago, but the Susitna project could reverse that trend. Moreover, the Susitna project would be built by a sovereign state government, echoing historic federal efforts like the Tennessee Valley Authority and Bonneville Power Authority.

Floating offshore wind in US waters?

2011-12-12T11:10:00.000-05:00

US coastal waters may soon see the development of floating offshore wind electric generating projects. Being able to install offshore wind turbines on floating platforms, as opposed to towers fixed to the seabed, may enable projects to tap into the vast deepwater ocean energy resource. This would represent a major step in history and technology, and could provide real data on the actual feasibility and costs of offshore wind in the United States.

The Cuckolds Light off Boothbay Harbor, Maine, with Seguin Island Light in the distance.

2012 may bring the deployment of North America's first floating offshore wind project. The DeepCWind Consortium and the University of Maine plan to test a floating wind turbine several miles off the Maine island of Monhegan next summer. The Monhegan project is designed as a pilot project, not a commercial effort. Nevertheless, the lessons learned off Monhegan could be used to shape a larger commercial project in 2013.

Historically, this project could be the first operating US offshore wind development. As 2011 closes, US waters still host neither operating commercial offshore wind projects, nor installed pilot projects of significant size. This is not for lack of interest. Universities and businesses are investing in offshore wind research and development, while developers eagerly pursue commercial projects in nearly all US jurisdictions. Commercial proposals range from projects fully permitted projects but unbuilt, to concepts still in the formation phase.

Technologically, a floating offshore wind project would demonstrate potential solutions to the engineering challenges posed by deep water sites. At least two floating turbines have recently been deployed around the world. The first, Statoil’s 2.3 megawatt Hywind unit, was installed off Norway in 2010. In November 2011, Portuguese utility Energias de Portugal (EDP) teamed up with Principle Power, Inc. to deploy a 2 megawatt turbine on a WindFloat platform off Portugal. The semisubmersible WindFloat design allows the unit to be towed in a horizontal position to the site, then erected without the use of a lift vessel. These test projects demonstrate some of the technologies required for deepwater offshore wind projects. A US project would represent a similar demonstration of new technology.

Floating offshore wind projects appear to have some momentum in Europe, and are poised to make a splash in US waters in the next year. Whether these efforts take hold depends on broader questions of economics and policy as much as on technology. What will 2012 bring?

National park energy use and strategies

2011-12-09T10:30:00.000-05:00

Small-scale alternative energy resources play an increasing role in how the U.S. National Park Service manages its lands, budget, and energy usage.

Solar panels line the roof of the comfort station at Devil's Garden Campground in Arches National Park, Utah.

The United States National Park Service manages about 88.4 million acres of land in the form of national parks, national monuments, and other historic and conservation properties. While much of the Park Service's holdings are preserved as undeveloped backcountry properties, the NPS provides visitor amenities like lodging, food and other concession services.

The remote locations of many Park Service sites make traditional energy resources expensive and challenging. Ranger stations and campground bathrooms may be located far from the traditional utility electric grid. Diesel generators can be used if road access to the site is possible, but have drawbacks: fuel is expensive, and generators can be loud, produce emissions, and may be out of character for a particular national park site.

In some cases, the Park Service is turning away from traditional energy resources to alternative and distributed energy resources like solar power. In fact, the Park Service has deployed distributed solar photovoltaic generation for over a decade.

Consider the example of Devil's Garden Campground in Arches National Park in Utah. While the campground is relatively remote (located at the end of a 30-mile dead-end road inside the park), Park Service facilities in the campground need electricity. These facilities include two campground hosts, three bathrooms, an amphitheater and a ranger station.

Historically, electricity for the campground facilities came from on-site diesel generators. These units ran 24 hours a day, consuming over 6,400 gallons of fuel per year. Producing electricity from diesel is seldom cost-competitive today; generating electricity from diesel at Devil's Garden Campground cost the National Park Service over $22,400 per year. This meant that the Park Service was generating electricity for a price of 28 cents per kilowatt-hour (kWh), about four times higher than the current average Utah price.

(As expensive as this is, it's still about a third of the cost of diesel-generated electricity on the remote Maine island of Monhegan. In 2010, electricity on Monhegan cost an average of 74.51 cents per kWh.)

As early as 1995, the Park Service joined with the state of Utah to develop four photovoltaic/diesel hybrid systems at Devil's Garden Campground. Each system is composed of a 1.4 kilowatt (kW) tracking array, a 4 kW inverter and a 40 kWh battery bank. Diesel units remain on-site and ready, but now run less than 4 hours per day. This cut the Park Service's annual operation and maintenance costs for the diesel generators from $22,400 to $10,000. The project dramatically reduced the noise level in the campground, and significantly cut the diesels' emissions of carbon dioxide, carbon monoxide, nitrogen oxides, and sulfur oxides.

As this example shows, sites that are already off the grid can be good candidates for small-scale distributed generation projects relying on alternative technologies like solar. Depending on project economics and other objectives (like the Park Service's sustainability initiative, improving noise levels and air quality, or education), replacing diesel with renewable energy -- and making energy efficiency improvements -- can make sense.

Other units in the National Park Service system are following the Arches example by turning to distributed renewable energy and energy efficiency. In 2011, Yosemite National Park installed a 672 kilowatt grid-tied solar array. The $5.8 million Yosemite project is bigger in scale (the Park Service's largest solar energy project) and is tied to the utility electric grid, but represents a similar strategy to that used in Arches and throughout the Park Service.

Maine ocean energy advances

2011-12-07T10:52:00.001-05:00

Maine's offshore wind industry may be moving forward, as the federal agency responsible for offshore wind site leasing is now considering a request by Norwegian energy company Statoil to lease a site for a Maine deepwater floating wind project.

Uninhabited Damariscove Island, off Boothbay Harbor, Maine.

The Maine site for which Statoil has applied lies over 12 miles offshore, south of Boothbay Harbor. It lies in United States waters south of Damariscove Island. This places the site near the pre-selected Damariscove Island wind site in Maine state-jurisdictional waters. Statoil's proposed site is also southwest of the Monhegan offshore wind site.

Statoil's request to the federal Bureau of Ocean Energy Management was submitted on an unsolicited basis. No BOEM Call for Information and Nominations (the agency's primary competitive solicitation tool) was in effect for these waters. Under current regulations, unsolicited leases face a slightly different process for review, including a determination of whether there is any competitive interest in the site.

(You can read four public pages from Statoil's application here.)

Statoil is a large and diverse energy company headquartered in Stavanger, Norway, and owned primarily by the government of Norway. Statoil's portfolio includes petroleum, gas, pipeline, and electric utility businesses. Statoil is now exploring ocean energy opportunities, and developed the world's first full-scale floating wind turbine, the 2.3 megawatt Hywind unit. Statoil has applied for a site lease off Maine, which could be its first US offshore wind site.

BOEM has deemed Statoil NA's lease application to be complete, and the applicant to be legally qualified. Now BOEM is engaged in a review of Statoil's technical and financial qualifications.

Tomorrow morning, a joint state-federal task force will meet to review Statoil's request. The Maine Task Force of the Bureau of Ocean Energy Management consists of a broad array of agency representatives. Tomorrow's meeting will feature presentations by representatives from the governor's energy office, Maine Public Utilities Commission, United States Coast Guard, Department of Defense, NOAA, as well as BOEM and the Department of Interior itself. This meeting will be held on December 8 at the Marriot Hotel in South Portland, Maine, at 9:30 a.m.

Separately, Statoil is negotiating with staff from the Maine Public Utilities Commission for a long-term contract to sell the project's output to utilities. Statoil responded to the Maine commission's 2010 request for proposals for pilot floating offshore wind projects. This offshore wind long-term contracting program was established by a Maine law designed to facilitate the development of a deep-water offshore wind energy pilot project.

If the Commission approves a long-term contract for the project's output, it could give the wind farm sufficient revenue certainty. At the same time, the Commission is required to weigh the costs and benefits of any such contract, and must find that ordering a utility to buy the energy, capacity and renewable energy credits at the price and other terms proposed would not have an unreasonable impact on the utility's rate.

EPA regulations vs electric grid reliability

2011-12-02T09:34:00.001-05:00

Debate continues over the impacts of new environmental regulations on the reliability of the U.S. electric power grid. Players in the recent debates include the nation's chief electric reliability organization (North American Electric Reliability Corporation, or NERC) and the U.S. Environmental Protection Agency -- and now, the U.S. Department of Energy has weighed in.

Earlier this week, NERC released a report suggesting that new regulations under development by the U.S. Environmental Protection Agency may force the early retirement of many coal-fired generating plants. NERC pointed to several rules under development and implementation, including EPA's Cross-State Air Pollution Rule (creating trading systems to control the emissions of NOx and SO2 from electric generators), Mercury and Air Toxics Standards (imposing emissions standards on coal and oil-fired electric generators for mercury, acid gases and particulate matter), and Cooling Water Intake Structures (regulating generators' intake of water). On NERC's analysis, this could jeopardize the security and reliability of the electric grid.

EPA disputed these findings, noting that NERC's report contained "faulty characterizations" of its rules, that several rules were still in draft form, and that regulated generators would have more time and greater flexibility in adapting to the final rules.

Yesterday, the U.S. Department of Energy released its report, "Resource Adequacy Implications of Forthcoming EPA Air Quality Regulations" (41 page PDF). The Department of Energy sided with EPA, noting that even under a "stringent" scenario in which a total of 29 gigawatts of coal capacity would be retired by 2015 -- a conservative assumption, according to the Department -- target reserve margins for generating capacity could be maintained across the country. The Department also noted that mechanisms exist to help regulators keep the lights on if the rules prove too much.

The Department's report is not likely to end the debate. Several of EPA's rules are still under development, such as the cooling water intake regulations. The rules that are now final will take several years to ramp up. Key agencies have vowed to maintain reliability no matter what happens -- but what impact will the environmental regulations have on the grid?

EPA regs and electric grid reliability

2011-11-30T14:42:00.001-05:00

Debate is ongoing about the effect of new environmental regulations on the U.S. electric grid. Some worry that tighter environmental controls will force certain electric generators to shut down, driving up the cost of electricity or putting electric reliability at risk. Others believe that the grid's integrity can be maintained, and that the new regulations are necessary to protect human health and the environment.

Support for the concerned side of the equation comes from a recent report by the North American Electric Reliability Corporation. NERC is the nation's electric reliability organization, charged with ensuring the reliability of the North American bulk power system. In NERC's 2011 Long-Term Reliability Assessment (559 page PDF), NERC notes that recent and future environmental regulations may force the early retirement of a significant portion of the nation's coal-fired generating plants. These regulations include the recently-finalized Cross-State Air Pollution Rule, plus rules under development governing utility plants' water intakes and air emissions. According to NERC's report, EPA's new cooling water intake structures and mercury and air toxics standards rules "may significantly affect bulk power system reliability depending on the scope and timing of the rule implementation and the mechanisms in place to preserve reliability."

At the same time, others observe that NERC's report assumes multiple worst-case scenarios and ignored the health and environmental benefits of the rules. After reviewing a near-final draft of the NERC report, EPA itself wrote NERC a letter (4 page PDF), stating "it appears likely your report may contain ... faulty characterizations of our rules." EPA pointed to several flaws in NERC's analysis, including that NERC assumed generators would be forced to adopt the most expensive solutions immediately, rather than selecting the most cost-effective technologies for each facility. EPA noted that the bulk of threatened plant retirements suggested in NERC's report would come from the cooling water intake regulations -- regulations which are still under development. Finally, EPA pointed out that NERC's analysis appears to assume that no one tries to preserve grid reliability as the regulations begin to take effect, "an outcome that flies in the face of our 40 years of implementing the Clean Air Act and Clean Water Act." Given the positive impacts of the regulations -- with the Cross-State Air Pollution Rule alone projected to prevent 34,000 premature deaths and 400,000 cases of aggravated asthma per year -- EPA defended their value and refuted NERC's analysis.

Reliability of the grid is important, enough so that the Federal Energy Regulatory Commission convened a technical conference yesterday and today to discuss grid reliability and policy. While that proceeding may result in interim orders or changes to policy, it may take years for the environmental regulations to both take effect and to impact generating plants. At the same time, generators are keeping a close watch on federal environmental regulation as it develops.

Google reduces renewable research

2011-11-28T14:39:00.001-05:00

In recent years, Google has branched out from its core internet business to work on reducing the cost of renewable energy -- but now appears to have turned away from its renewable research efforts.

Here's a quick recap of some of Google's energy plays.

In February 2010, Google received market-based rate authority, a key federal approval to allow it to sell electricity at wholesale in the U.S. markets. Google stated that the Federal Energy Regulatory Commission's approval would allow it to hedge its energy procurements more effectively.
In April 2010, Google joined with 46 other companies supporting smart grid technology in asking President Obama to help consumers access real-time information about their electricity usage.
In July 2010, Google agreed to buy electricity from a NextEra affiliate's wind generating facility in Iowa to help power its data centers.
In October 2010, Google invested in underwater transmission lines to transmit power from offshore wind turbines to the mainland, including a 350-mile backbone line from Virginia to New Jersey.
In April 2011, Google invested up to $168 million in BrightSource Energy's 392 MW Ivanpah solar project in California.

In addition to these activities, Google launched its "Renewable Energy Cheaper than Coal" initiative. This program included engineering research and development to reduce the cost and water consumption of concentrating solar plants like Ivanpah. Now, Google has announced that it has "retired this initiative", while reaffirming its investment in Ivanpah and its green energy procurement.

What will the future hold for Google? Google it.

Tide Mill Institute event a success

2011-11-21T09:37:00.000-05:00

I was very pleased to attend this past weekend's Tide Mill Institute conference. The Tide Mill Institute describes its mission as "to advance the appreciation of tide mill history and technology by encouraging research, by promoting appropriate re-uses of former tide mill sites and by fostering communication among tide mill enthusiasts."Here's a link to the conference website:http://www.tidemillinstitute.org/23.htmlMy presentation compared tidal power projects past and present, looking at project economics, law and regulation. Interesting, many of the judicial opinions about tide mills from centuries past address concerns still expressed about tidal power projects. How will a given project affect water quality? Neighboring property? Fisheries and navigation on? Long before regulatory agencies or specific environmental statutes, tide mills effectively faced regulation in the form of court orders over lawsuits. Today, a host of agencies has regulatory authority over the development and operation of tide mills and tidal electric generation.It was great to meet so man people interested in the past, present and future of tidal energy.

Maryland dam faces sedimentation threat

2011-11-17T10:55:00.001-05:00

In September 2011, Tropical Storm Lee caused flooding in the mid-Atlantic region. The Susquehanna River rose far above its banks, causing disruptive floods in Pennsylvania and Maryland. Near the river’s mouth into Chesapeake Bay, massive flooding threatened to breach the 572-megawatt Conowingo Dam.

With its flood gates wide open, the dam survived the flooding. At peak flows, about 7 million gallons flowed through the dam every minute. That water transported millions of tons of sediment from the Susquehanna watershed out into the bay, along with large amounts of trash and debris.

The impacts of the flood are still being assessed. Under typical operations, the dam builds up about 2 million tons of sediment every year, or about two-thirds of the Susquehanna River's total sediment burden. (Compare the dams currently being removed from the Elwha River in Washington, which had trapped an estimated 24 million cubic yards of sediment.) Overall, four dams on the Susquehanna might hold up to 280 million tons of sediment.

While Lee removed several years' worth of sediment from the Conowingo Dam, more sediment builds up every year. The Army Corps is concerned that the Susquehanna River dams have nearly reached their full capacity to hold sediment, and is launching a project to study what could be done, such as sediment dredging or remediation.

Headwater benefits charges affect hydropower projects

2011-11-15T07:49:00.000-05:00

Suppose you own a federally-licensed dam and hydroelectricgeneration facilities on a river. Theamount of electricity you can produce is determined by factors including howmuch water is flowing through your turbines every second and the dam’s “head”,or effective height through which that water falls. Over an entire year, the amount of power youcan produce is also affected by how much water can be stored in the watershedabove your dam, and how well you can regulate the flow of water through yourturbines. For example, if you canimpound more floodwaters upstream instead of spilling excess water over the dam, you can maintain maximum flows through your powerhousefor a longer period of time than you otherwise could.

Now suppose someone else builds a dam upstream from yoursite that enables better storage and regulation of water flows through theriver. Setting aside any environmentalimpacts from that change in flow, one upside of the improved flow regulation isthat you can produce more power at your dam thanks to the upstreamimprovements.

Under the Federal Power Act, you may be required toreimburse that upstream dam owner for an equitable part of the benefits youreceive from its improvements. Federalhydropower licenses typically include a provision requiring the licensee toreimburse the owner of an upstream improvement for these headwater benefits.

Under the Commission’s regulations, headwater benefitscharges can be calculated using an “energy gains” methodology. This analysis includes an assessment of thedifference between the number of kilowatt-hours of energy produced at adownstream project with the headwater project and that which would be producedwithout the headwater project. Alternatively,dam owners may negotiate an agreement on headwater benefits charges and presentit to the Commission for approval as a settlement offer.

Renewable demands drive billions in transmission investment

2011-11-10T14:14:00.000-05:00

As demand for renewable electricity increases, utilities are proposing new transmission lines to connect the new crop of electric generation projects to consumer markets. Given the scale of these projects, and because renewable power projects are often sited far from the cities and industrial sites where the electricity will be consumed, the proposed transmission lines can come with a significant price tag. For example, the Northern Pass project - a proposed high-voltage DC transmission line capable of carrying 1200 megawatts of power from Quebec to New Hampshire - is projected to cost $1.1 billion. These costs, and who must pay them, can generate as much controversy as siting the route for the transmission lines.

Another major high-voltage direct current transmission line has been proposed by Rock Island Clean Line LLC. The Rock Island Clean Line would run about 500 miles from northwestern Iowa into Illinois, where it would connect with the mid-Atlantic regional grid operated by PJM Interconnection. The proposed line would be positioned to collect electricity produced by wind power facilities in the eastern parts of South Dakota and Nebraska as well as the western parts of Iowa and Minnesota. This power could be delivered into Illinois, either to satisfy that state's renewable portfolio standard or for further transmission throughout the mid-Atlantic region. Proponents of the line also claim that it would reduce transmission constraints between the Midwest ISO and PJM grids, as well as reducing wholesale energy prices in Iowa and Illinois.

The price tag for the Rock Island Clean Line project is projected to be $1.7 billion. While the current project is based on the assumption that the electricity flowing over the line would come from wind generation, there is no guarantee that the resource mix will be as expected.

FERC releases report on demand response

2011-11-09T07:42:00.000-05:00

Demand response is an innovative smart-grid approach to meeting society's electricity needs. As customer demands on electric grids increase, the generating resources needed to meet higher and higher peak demands are typically more expensive to run and have more adverse environmental impacts. In essence, demand response means covering electric load by having individuals or companies agree to temporarily cut back on electricity consumption in response to peak demand conditions. When customers are willing to provide this service at a lower cost than generation, demand response can be a decentralized, crowd-sourced alternative to peaking power plants.

U.S. federal regulatory staff released a report this week assessing the nation's demand response and smart meter resources. The Federal Energy Regulatory Commission staff report is the sixth annual briefing since the enactment of the Energy Policy Act of 2005, which contained provisions promoting the development of demand response resources and markets.

The report notes that more and more customers have access to the kind of advanced meters that facilitate demand response participation. These smart meters can not only measure instantaneous electricity demand, but typically report back to a utility automatically using radio frequency communications. Since 2009, advanced meters have risen from 8.7% to a 13.4% share of all installed meters. The report suggests that the actual penetration rate of advanced meters may be even higher if it includes meters that are installed but whose advanced features have not yet been activated.

The report also notes that in 2010, the grid operators it surveyed had a total of 31,702 MW of demand response resource potential, or enough to cover about 7% of the total 2010 peak demand. Regional demand response capacities ranged from as low as 2.3% of peak load in the Electric Reliability Council of Texas to as high as 10.5% in the mid-Atlantic region's PJM Interconnection. The report noted that demand response resourcs "made significant contributions to balancing supply and demand during system emergencies" in 2011.

Virginia considers net metering and utility standby charges

2011-11-08T08:08:00.000-05:00

Virginia, like many states, allows grid-connected electricity customers to use customer-sited generation to offset its electric bill. This practice is called net metering.

Virginia regulators are now considering a proposal by utilityDominion Virginia Power to impose two “standby” charges on net-metered solarphotovoltaic systems larger than 10 kW. The policy questions raised by this case appear in othercontexts where incentives for clean, distributed generation run up againstutility ratemaking considerations. Utilitiestypically argue that they need to allocate costs fairly among their customers,while customer-sited generation advocates point to both the value ofdistributed generation and the array of incentives promoting customer-sited generation.

In June 2011, the Virginia legislature enacted House Bill 1983, directing Dominion to allow residential customers to net meter solar photovoltaicsystems between 10 kW and 20 kW. Dominionresponded by petitioning the Virginia State Corporation Commission (SCC) for approvalof tariff changes that it argued are necessary to reflect itsactual costs in supporting these customers’ peak loads. The utility proposedto add monthly standby charges for transmission and distribution service basedon each net-metered customer’s highest 30-minute demand.

Utilities often argue that their fixed costsin serving net-metering customers – maintaining wires, transformers, and otherinfrastructure – are the same as if the customers had no generation. If a customer can be self-sufficient most ofthe time, the utility grid must still be of a sufficient size to deliver thecustomers’ peak demand when it is needed, such as when customer-sited generation fails. Dominion requested approval of its standbycharges to ensure fair cost allocation among customers.

Distributed generation advocates, on the other hand, arguethat the standby charges would result in overcharging net-meteredcustomers. In Dominion's case, a witness for the Maryland,District of Columbia and Virginia Solar Energy Industries Association testified thestandby charge would result in higher charges for a net-metered customer than aregular customer consuming the same amount of grid-purchased electricity. The witness also testified that net-meteringcustomers should receive credits for generating cost-effective energy, and for reducing the utility’stransmission line losses. Diverse distributedgeneration may also reduce utilities’ distribution costs. The solar association argued that Dominion's standby charges ignored these benefits, and would chill distributed solar development in spite of Virginia's net-metering policy.

The Virginia State Corporation Commission held a hearing onDominion's request last week, and is expected to issue an order resolving the matter.

Biofuels power first commercial airline flight

2011-11-07T09:19:00.000-05:00

Today marks the first U.S. commercial airline flight powered by biofuels. United Airlines has selected a Boeing 737-800 for the route from Houston to Chicago. The plane will be powered by Solajet, a fuel blend of 60 percent petroleum-basedjet fuel and 40 percent biofuel produced by California-based algae producer Solazyme.

Biofuels appear poised to play an increasing role in the transportation sector. Biofuels have traditionally included liquid fuels like ethanol (derived from corn or cellulosic sources) and biodiesel. Biofuels typically rely on plants or algae to convert solar energy into chemicals that can be refined and modified to produce usable fuels. The wood (biomass) burned in hearths and stoves around the world represents a very basic biofuel, but today's advanced biofuels can involve significantly more technology. The U.S. Department of Energy is funding research and development efforts to produce "drop-in biofuels", which can be used as additives or even replacements for liquid fuels like gasoline, diesel and jet fuels -- without requiring consumers or distributors to modify their engines and fuel distribution networks.

United Airlines is not the only carrier to take its biofuels experimentation live this week. On Wednesday, Alaska Airlines will fly two commercial flights from its bases in Seattle and Portland, Oregon, to Washington, D.C. Alaska Airlines' jets will be powered by a fuel blend composed of 20% biofuels from used cooking oil. Alaska Airlines chose Dynamic Fuels as its supplier; Dynamic Fuels is a joint venture between food product giant Tyson Foods and synthetic fuel producer Syntroleum.

Presidential permits for cross-border energy facilities

2011-11-03T13:54:00.000-04:00

Presidential permits for the import and export of energy resources across the United States' borders are critical to the development of cross-border energy facilities.

Millions of dollars of energy resources flow across the United States' borders every day. Trade in energy resources with Canada and Mexico accounts for the bulk of these transactions. Canada is the single largest foreign supplier of energy to the United States, providing about 20% of U.S. oil imports and 18% of U.S. natural gas imports according to the U.S. State Department. Canada and the United States share an integrated electricity grid and provide all of each other's electricity imports. Today and tomorrow, members and guests of the New England - Canada Business Council are meeting in Boston to discuss this close relationship.

Facilities spanning the border -- whether pipelines for oil or natural gas or transmission lines for electricity -- can only be built and operated once a federal approval called a "presidential permit" has been obtained. Since a 1968 Executive Order, presidential permits have been issued by the State Department. Presidential permits cover not only the facilities themselves, but also the commodities (oil, gas, electricity) transmitted over those facilities.

For example, the proposed Keystone XL pipeline from Canada to Texas will require a presidential permit. In today's news, President Obama is reported as saying that he will be the one to make the final decision on whether TransCanada will obtain its permit.

Yarmouth, Maine considers dam removal, other options

2011-10-31T14:59:00.002-04:00

The town of Yarmouth, Maine is holding a meeting on November 1, 2011 about the future of two town-owned dams on the lower Royal River.

The Royal River flows nearly 40 miles across Maine, from Sabbathday Pond in New Gloucester to meet Casco Bay in the town of Yarmouth. Along this course, the Royal River falls about 300 feet, much of which forms a series of old dams and falls in its lower reaches. The village of Yarmouth formed around several of these dam sites, which provided mechanical power to mills and businesses in the village. Today, dams remain on the Royal River. A non-hydropower dam spans the river near East Elm Street, while the Sparhawk Mill dam hosts hydroelectric generating facilities near Bridge Street.

The Sparhawk Mill dam was originally built to provide mechanical power, but hydroelectric generating facilities were installed in 1984. Now, the Sparhawk project can produce 270 kilowatts of power, and operates under a licensing exemption issued by the Federal Energy Regulatory Commission in 1985.

Today the town of Yarmouth owns the dams, and is considering their future. The Sparhawk dam is reportedly not producing much -- if any -- revenue for the town, while both dams may need maintenance and repairs. Some community members suggest dam removal for reasons ranging from municipal fiscal policy to enhancing fish passage along the Royal River. Others point to value of the Royal River's continuing ability to produce renewable hydroelectricity, and urge that the dams be maintained. The East Elm Street dam could even have electric generation facilities installed, either traditional hydroelectric or hydrokinetic devices.

The community forum starts at 7 p.m. on November 1 at Yarmouth Town Hall.

Keystone XL pipeline explained

2011-10-27T13:06:00.000-04:00

The proposed Keystone XL oil pipeline is drawing significant public attention. What is the Keystone XL project, and why is it controversial?

What is Keystone XL?
The Keystone XL project is a proposed extension of an existing crude oil pipeline. The $7 billion project would run from the Canadian province of Alberta to Texas, cutting across Saskatchewan, Montana, South Dakota, Nebraska, Kansas, and Oklahoma along the way. TransCanada Corporation proposes Keystone XL to expand its existing Keystone pipeline network, a former natural gas pipeline repurposed to ship crude oil south to meet U.S. demand.

What is the controversy?
The U.S. is a major consumer of oil and petroleum-derived products.

All major linear infrastructure projects tend to draw interest. Significant projects, whether a pipeline for natural gas or oil, electric transmission line, or highway, often affect interests across a wide geographic range. Relatively local siting concerns, like finding the best route for a given project and minimizing its direct environmental impacts, are common when planning any major infrastructure development.

In Keystone XL's case, project opponents point to additional concerns about the project's broader environmental impacts. Some decry the proposal as increasing dependence on foreign oil, and believe the U.S. already has sufficient Canadian oil import capacity. Others note that the oil to be shipped south over Keystone XL will be largely derived from Alberta's "tar sands" or "oil sands", and that extraction and production of crude oil from these sources involves greater greenhouse gas emissions or other environmental impacts.

What is happening now?
Concerns over the Keystone XL project are manifesting in multiple forms. Protests have led to more than 1,000 arrests, including high-profile protestors like actress Darryl Hannah and NASA scientist James Hansen. States affected by the pipeline proposal are moving cautiously; next week the Nebraska Legislature will meet at the request of Governor Dave Heineman to address concerns over Keystone XL.

To develop the project, TransCanada must secure a presidential permit to import oil across the national border. While that permitting process initially appeared to be on track, 14 members of Congress have asked for a delay to allow an investigation into how the State Department performed its environmental review of the project.

The fate of the Keystone XL project depends on a number of factors, including whether it can secure a presidential permit as well as how states react. Part of the project's financing hinges on contracts to deliver crude oil as soon as 2014, and TransCanada is reportedly concerned that delay would jeopardize that financing structure.

How price predictions affect heating oil supply contracts

2011-10-26T11:47:00.000-04:00

Nearly half the households in the northeastern region of the United States use heating oil to provide part or all of their space heating needs. While natural gas fuels furnaces in many homes in other regions of the country, New England is a significant consumer of heating oil. According to the U.S. Energy Information Administration, about 80% of U.S. households that use heating oil are located in the Northeast.

Those of us managing households in the Northeast know that heating oil companies typically offer customers different ways to buy oil. The most basic approach is to buy oil on the spot market. Under this approach, when a customer wants a delivery of oil, the customer can call around and select a supplier for a single delivery. This approach lets customers benefit when prices go down, but leaves customers exposed to the market risk that prices may go up.

One alternative some customers prefer is locking in heating oil prices through a supply contract with a single supplier. According to the EIA, customers' taste for this alternative changes based on predictions about future fuel prices. In the middle of the last decade, about one-third of Northeast homeowners chose contracts; that number approached half of homeowners in 2008 in response to anticipated high fuel prices. As it turned out, petroleum prices fell sharply in the second half of 2008; the fraction of homeowners with supply contracts fell to about 25% in both 2009 and 2010. Now, the EIA reports that heating oil associations in the Northeast are predicting that even fewer customers will lock prices in this year.

Vermont wind project contested

2011-10-24T13:50:00.004-04:00

A wind energy project in northern Vermont is the focus of significant controversy. Utility Green Mountain Power is currently developing the Kingdom Community Wind project on Lowell Mountain near the town of Lowell in Vermont's Northeast Kingdom. The 63 MW project is the first large-scale generation facility proposed by one of Vermont's investor-owned regulated utilities since the Searsburg wind project was approved in 1996.

In May 2010, Green Mountain Power Corporation, Vermont Electric Cooperative, Inc and Vermont Electric Power Company, Inc. filed a petition with the Vermont Public Service Board seeking approval to build up to a 63MW wind generation facility, and to install or upgrade about 17 miles of transmission line and associated substations.

A year later, the Vermont Public Service Board issued its final order and certificate of public good approving the project (182 page PDF). In the order, the Board found that "the proposed project will promote the general good of the state". Among the factors supporting the Board's decision was the fact that the project would produce energy without greenhouse gas emissions, and would thus support the goals of the Regional Greenhouse Gas Initiative (RGGI). The Board also noted that the project would help the state meet its goals of promoting new renewable generation as required in Vermont's SPEED, or Sustainably Priced Energy Enterprise Development Program. SPEED requires that, by 2012, at least 10% of the state's electric load be served by new sources of renewable energy. The Board also noted economic development benefits from the project, including job creation and tax revenues as well as the benefits of providing the developing utilities a long-term source of stably priced power.

The project drew opposition from a variety of sources, including those who oppose mountaintop wind development generically as well as those opposing development of this particular site. Now, while Green Mountain Power is preparing the site for construction, a group of protesters has set up a camp near the ridgeline. Abutting landowners have also asked a court to delay blasting and other work, claiming that they own part of the land where the blasting will occur.

What will happen to the Lowell Mountain project? Green Mountain Power planned to complete the project by December 3, 2011. As the Burlington Free Press has noted, the company has argued that delay is costly, and that too much delay would be fatal: Green Mountain Power must have project up and running by December 31, 2012 to qualify for $48 million in federal tax credit that are part of the project's overall financing plan.

Maine hydrokinetic energy project seeks pilot license

2011-10-21T11:09:00.001-04:00

Hydrokinetic power plants can produce usable power from the energy contained in moving water into electricity. Tidal currents, ocean waves, or water flowing through rivers can all be used to produce hydrokinetic energy. (To learn more, check out my summary of what's happening with hydrokinetics across the country.)

Hydrokinetic energy development is generally regulated by the Federal Energy Regulatory Commission. To be able to install and operate a hydrokinetic project at a given site, the developer typically goes through a multi-step regulatory process. This usually includes securing a preliminary permit granting the exclusive right to study the site for several years, followed by the FERC license application process.

Maine is home to a number of issued preliminary permits for proposed hydrokinetic energy projects. This month, one of those projects -- the Cobscook Bay Tidal Energy Project -- took a step forward, as its application for a pilot license was accepted by the Commission.

The Cobscook Bay project is proposed by ORPC Maine, LLC, a subsidiary of Ocean Renewable Power Company. ORPC proposes to deploy its proprietary scalable tidal energy power system in Cobscook Bay near the city of Eastport and the town of Lubec, Maine. Cobscook Bay's tidal energy resource has drawn interest for nearly 100 years, with proposals like the Passamaquoddy Power Project coming and going in that time. Hydrokinetic technologies are enabling renewed interest in the bay's tidal energy resources.

ORPC's pilot license application envisions two phases of project development. First, ORPC will test a single TidGen unit for one year. Next, ORPC would add four more TidGen units to create a linked project. Each TidGen unit has a maximum design capacity of 180 kilowatts, but is anticipated to produce only 60 kW during typical operations. Electricity produced by the project would be brought ashore via a 3,600-foot underwater cable, where it would be conditioned and interconnected with the grid owned by Bangor Hydro Electric Company.

FERC gave notice that it accepted ORPC's application for processing on October 6, 2011. Because ORPC is using the Commission's new pilot license process, the regulatory steps are more streamlined than for traditional hydropower licenses, and many of the deadlines are accelerated. Comments, recommendations, motions to intervene or protests are due within 30 days from that notice of acceptance.

Bye-bye BOEMRE, hello BOEM and BSEE

2011-10-17T16:36:00.002-04:00

The federal agency with prime responsibility for oceanenergy development has been shuffled yet again. After just over a year of operations BOEMRE - the former Bureau of Ocean Energy Management, Regulation and Enforcement - has been replaced by two offices: the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safetyand Environmental Enforcement (BSEE).

This reshuffling is the latest organizational change to thefederal oversight of ocean energy development, but it is not the first. Until 2010, the Minerals Management Service(MMS) regulated both conventional oil and gas production and renewable energyactivity. In the wake of the DeepwaterHorizon oil spill incident, and criticism of how MMS operated, U.S. Secretaryof the Interior Ken Salazar restructured MMS into BOEMRE.

Now, BOEMRE has been split in two, with the division occurringalong functional lines. BOEM describesitself as “responsible for managing environmentally and economicallyresponsible development of the nation’s offshore resources”. BOEM’s functions include offshore leasing,resource evaluation, review and administration of oil and gas exploration anddevelopment plans, renewable energy development, National Environmental PolicyAct (NEPA) analysis and environmental studies.

Under the new paradigm, BSEE is responsible for safety andenvironmental oversight of offshore oil and gas operations, includingpermitting and inspections, of offshore oil and gas operations. BSEE exercises functions including thedevelopment and enforcement of safety and environmental regulations, permittingoffshore exploration, development and production, inspections, offshoreregulatory programs, oil spill response and newly formed training andenvironmental compliance programs.

Feds decide not to delegate more transmission authority

2011-10-12T10:20:00.000-04:00

Yesterday, I wrote about the Department of Energy's proposal to delegate increased electric transmission siting authority to the Federal Energy Regulatory Commission. Since the enactment of the Energy Policy Act of 2005, the Department has had the authority to study congestion on the transmission system, and designate national interest electric transmission corridors where it believes more transmission facilities are needed. The act also gave the Commission “backstop”authority to approve transmission line routes when states fail to issue approvals within a year.

Until yesterday, Secretary Chu was considering whether to delegate the Department's congestion study and corridor designation functions to the Commission. Supporters of the increased delegation said it would facilitate the development of new transmission facilities needed both for future load growth and to connect renewable energy resources to customers. Opponents, including congressional leaders, noted that Congress had specifically divided the functions for good reasons, while states' rights advocates objected to increased consolidation in the Commission of power over transmission line siting -- traditionally a prerogative of each state.

Now, the Department and the Commission have issued a joint statement that transmission backstop siting authority will not be delegated. Instead, the joint statement proclaims "enhanced cooperation" as an alternative to delegating additional authority to the Commission, along with process improvements within the Department to allow more expeditious transmission siting.

Federal authority over transmission siting may be reshuffled

2011-10-11T13:35:00.001-04:00

U.S. Department of Energy Secretary Chu is considering apolicy change that will affect how electricity transmission lines are sited andbuilt. Since the dawn of the electricpower industry, states have had the authority over whether the siting of agiven transmission facility should be permitted within their boundaries. That traditional states’ right may beshifting away to the federal level.

Since the Energy Policy Act of 2005, the Department has had “backstop”authority to approve transmission line routes when states fail to issue approvals. In 2007, theDepartment of Energy used this authority to designate corridors of highlycongested transmission lines in the mid-Atlantic area (parts of Delaware,Ohio, Maryland, New Jersey, New York, Pennsylvania, Virginia, West Virginia,and the District of Columbia) and the southwest (parts of southern Californiaand western Arizona).

Proposed new transmission facilities located within thesedesignated National Interest Electric Transmission Corridors can apply to the FederalEnergy Regulatory Commission for siting approval if a host state does not approvethe project within one year. This couldhappen if a state regulatory proceeding drags on for longer than a year, or ifstate regulators condition project approvals in a manner that is not “economicallyfeasible” – both results more likely to happen in connection with larger and morecontroversial transmission line projects. While the Commission initially approved some transmission line sitingapplications that had been denied by state regulators, a federal appeals courtheld that the Commission lacked authority to approve a project in the face of astate’s affirmative denial (as opposed to mere regulatory delay).

At issue now is whether the Department of Energy shoulddelegate its corridor designation function to the Federal Energy RegulatoryCommission. Proponents of the measurepoint to the need for increased transmission development, citing the growth ofrenewable resources located far from customer loads as well as transmissioncongestion; they believe the Commission will be better suited to the task ofstudying congestion and designating national corridors than the Departmentis. Others oppose this proposeddelegation, noting that Congress specifically divided the corridor designationand project approval functions between the Department and the Commission, andthat states retain the ultimate rights to deny a siting application. A number ofcomments have been submitted to the Department on this proposed delegation.

Department of Energy loan guarantee program ends

2011-10-05T10:18:00.002-04:00

In recent years, the U.S. Department of Energy has operated three loan-based programs designed to help finance innovative energy projects. One of these DOE loan guarantee programs backstopped a total of $16 billion in loans for 28 projects, ended last week. Projects supported by the loan program ranged from nuclear power to solar, wind to transmission, biofuels to energy efficiency. Continued funding for the loan guarantee program for 2011 was called into doubt in the spring of 2011, and Congress ultimately continued the program's stimulus funding only through September 30, 2011. While many of the projects financed through the program have drawn praise, the first guarantee issued -- $535 million in guarantees for solar panel maker Solyndra LLC -- has been called into question by some observers after Solyndra ceased operations last month.

On the DOE loan program's last day of operation, the Department of Energy finalized nearly $5 billion in loan guarantees to four solar projects. Three of the solar projects are located in California (as are a number of other large-scale solar projects funded through the DOE loan guarantees), while the fourth is an innovative rooftop solar project distributed across 750 existing rooftops owned and managed by Prologis in up to 28 states and the District of Columbia.

The hard deadline of last Friday means that other projects whose loan guarantee issuance process was nearly complete did not receive funding. Will these projects find another way to be financed and built? What impact will the end of the loan guarantee program have? Congress appears to have intended the shuttered program to be a short-term stimulus program to help get the ball rolling on project development. Because the projects financed through the program generally have long construction periods, it may be some time before we can have solid data on the value of the DOE loan guarantee program.

Offshore wind energy proposed off New York

2011-10-03T10:39:00.000-04:00

The New York Power Authority - the public power organization for the state of New York - is pursuing the development of a utility-scale offshore wind farm in federal waters at least 13 miles south of New York City and the western tip of Long Island. NYPA intends to hold a competitive solicitation to select a developer for the project, which is expected to have up to 700 megawatts of nameplate capacity.

Sunset over Five Islands harbor, Georgetown Island, Maine.

The Long Island project is not NYPA's first foray into offshore wind. Until last month, NYPA was conducting a competitive process to select a developer for a project in the Great Lakes. NYPA shut down its Great Lakes Offshore Wind (GLOW) program at the end of September 2011.

Large hydroelectric projects around the world

2011-09-30T07:30:00.000-04:00

Hydroelectricity provides a significant amount of usable power across the world. According to the U.S. Energy Information Administration, in 2008 hydroelectric generation produced 3,119,012 million kilowatt-hours, or 16% of the total electricity produced in the world. In the U.S. between 1998 and 2009, hydroelectric generation produced between 6-9% of the nation's total electric generation, depending on water availability.

Hydroelectricity is also responsible for many of the largest generating facilities. For example, the federal Grand Coulee Dam in Washington has a summer nameplate capacity of 7,079 megawatts, making it nearly twice as large as the next biggest U.S. power plant (Arizona's Palo Verde nuclear generating station).

Around the world, large hydroelectric projects produce immense amounts of power. When China's Three Gorges Dam project on the Yangtze River is complete, it is projected to include 32 separate 700 megawatt generators, producing a total project capacity of 22.5 gigawatts. This will make the Three Gorges Dam not only the largest hydroelectric dam in the world, but also the largest power station of any type.

Brazil's Itaipu Dam, producing up to about 14 gigawatts from the Paraná River along the Brazil-Paraguay border, is both the second largest hydroelectric plant and the world's second largest power station of any type.

Brazilian developers have also proposed the Belo Monte dam on the Amazonian Xingu River, which has received key environmental permits despite opposition on social and environmental grounds. If built, Belo Monte would be able to produce up to about 11 gigawatts of power, making it the third largest hydroelectric facility in the world. This week, a Brazilian judge issued a legal injunction against the Belo Monte development, noting the risk that fisheries would be damaged by its construction and operation. Will Belo Monte become the world's third largest power plant?

NY Great Lakes wind project ends

2011-09-29T11:01:00.002-04:00

The Great Lakes of North America are home to significant potential for generating electricity from offshore wind. As it turns out, Chicago is called the Windy City for a good reason, and the winds blow even more consistently over the lakes. A study by the United States Department of Energy found 742.5 gigawatts of potential developable generation capacity in the Great Lakes.

In response to this potential, in 2009 the New York Power Authority announced plans to fund one or more offshore wind projects in the Great Lakes. NYPA's Great Lakes Offshore Wind program (GLOW) issued a competitive solicitation for proposed projects, and received proposals from five potential developers. As NYPA reviewed the bids, repeated delays in its announcement of winners and turnover within the Power Authority leadership pointed to increasing uncertainty about GLOW's future.

This week, the NYPA board voted to terminate the GLOW project. As reported by the Elmira, NY-based Star Gazette, the trustees voted unanimously not to pursue the project at this time. Reasons the board may have considered include local siting opposition and the size of the subsidies NYPA's consumers would have to pay project developers. Under NYPA's model, a 150 megawatt offshore wind project would have received between $60 million and $100 million a year. NYPA staff recommended that such an expenditure was not fiscally prudent at this time.

With GLOW dead in the water for now, offshore wind in New York's Great Lakes waters may not occur for some time. Will other states or provinces be the first to try to capture the Great Lakes winds?

Computer energy efficiency increases

2011-09-27T07:30:00.000-04:00

Computers can do amazing things, but are often viewed as consuming significant amounts of energy. For example, centralized server operations like large data centers can consume as much power as heavy industrial manufacturing. Whether powered by the default electricity mix or by purely renewable power, we often think that crunching numbers on computers means using a lot of power. For this reason, computer makers and customers alike push for energy efficiency in their computing activities.

Newly published research suggests that the energy efficiency of computers doubles roughly every 18 months. A team of researchers led by Stanford professor Jonathan Koomey looked at the peak power consumption of electronic computing devices ranging from 1946's ENIAC to the present. ENIAC, which the U.S. Army used to calculate trajectories for artillery, took up 1,800 square feet (bigger than the average U.S. house at the time), and could consume up to 150 kilowatts of electricity. Modern computers, and even smart phones, can now outperform ENIAC when it comes to computation, but are much more efficient in terms of their power demanded to perform a fixed set of calculations. According to what is now being called "Koomey's Law", over the years since ENIAC first powered up, computers' energy efficiency on that basis has doubled roughly every 18 months.

This finding follows on Professor Koomey's July 2011 report on data center energy usage, which found that although data centers consume more and more electricity each year, their energy consumption is growing less than their increase in server power.

Small hydro approved under fast process

2011-09-19T07:30:00.000-04:00

This month, federal energy regulators approved a small hydroelectric project within two months of its formal proposal under an innovative streamlined regulatory path.

Recognizing the potential of small hydro projects, the Federal Energy Regulatory Commission (FERC) is interested in simplifying the regulatory process for small projects. Last year, FERC signed a Memorandum of Understanding with the state of Colorado to streamline the procedures for developing small-scale hydropower projects in that state. Colorado has identified hundreds of small (5 MW or smaller) or conduit hydropower projects (turbines in water pipes and irrigation canals) whose total capacity could exceed 1,400 MW. Under the Memorandum of Understanding, Colorado is developing a pilot program to test ways to simplify the processes through which project developers obtain exemptions for small projects. For example, the application is presented to multiple agencies for simultaneous comment, rather than a prolonged multi-agency back and forth process.

Last week, FERC approved Colorado's first hydroelectric project under the Memorandum of Understanding. Docketed as Project P-14230, the Meeker Wenschhof hydroelectric project will be developed on an existing ranch irrigation pipeline in northwestern Colorado. Historically, water flowing through the pipe has been slowed by a valve before being stored in an underground cistern. As approved by FERC, the rancher will install a 23-kilowatt turbine in place of the valve. The project is expected to generate 100,000 kilowatt-hours per year on average.

The Meeker Wenschhof project's engineering details are interesting, making innovative and efficient use of the power of flowing water. Equally interesting is the speed with which the project flew through the regulatory approval process, with the application granted just two months after it was filed with FERC. Admittedly, this expedited process is currently limited to small hydro and conduit projects. Nevertheless, the Meeker Wenschhof project's rapid approval illustrates how quickly the regulatory process can be completed if it is designed to accommodate developers' needs.

Maine green power offer moves forward

2011-09-15T07:48:00.000-04:00

Greenpower offers are one way to help connect electricity customers with renewableenergy. These voluntary programs are designed to make it easier forwilling consumers to choose a greener energy mix for their home orbusiness. Green power offers are typically voluntary, meaning customersmust affirmatively enroll in the program and select their product. Inmany states, they create a mechanism for customers to buy renewable power overand above state renewable portfolio standards. While customers incompetitive markets are free to select their energy supplier, under the greenpower offer program one supplier is designated by regulators as the defaultgreen supplier at any given time. This formal designation gives thedefault green supplier better marketing access to its customers and facilitatesinteractions with the transmission and distribution utility.

Maine’sgreen power offer will launch soon. In December 2010, following on thestate legislature’s enactment of a community-based renewable energy pilotprogram, the Maine Public Utilities Commission issued a request for proposalsfrom suppliers to operate a green power offer for residential and smallcommercial electricity customers for a three year term.

Eligibleresources for the Maine program include fuel cells, tidal power, solar arrays,geothermal installations, hydroelectric generators that meet all state andfederal fish passage requirements, biomass generators, and wind powerinstallations. In response to the Maine commission's request for proposals, suppliers submitted bids proposing to supply productsconsisting of sufficient renewable energy credits (RECs) to cover half or allof each customer’s load.

At Tuesday'sdeliberative session, the Maine Public Utilities Commission selected thestate’s first green power offer supplier. While many of the details ofthe winner’s offering remain confidential for the moment, the regulatorsexpressed interest in a flexible product composed entirely of RECs fromrenewable energy facilities in Maine. The product would remainresource-agnostic, meaning the supplier could provide RECs from any eligibleMaine resource. This flexibility contrasts with other offers to deliverRECs from a specific resource such as wind. This product, which comes inaddition to a customer’s underlying energy supply and local utility wirescharges, is reported to cost 1.5 cents per kilowatt-hour.

With thewinner selected, Maine’s green power offer will move forward. The successof the program will depend on a number of factors including customers’appetites, the economy, and the green supplier’s marketing practices.

Delaware offshore wind project faces deadline, uncertainty

2011-09-14T07:36:00.000-04:00

Securing a power purchase agreement – a long-term contract bya utility or power marketer to buy electric energy from a generator – is often akey step in the finance and development of a new electric generation project. Where the buyer is a state-regulated utility,asin the case of Cape Wind’s offshore wind PPA with National Grid, state approvalof the contract may be required.

In 2008, offshore wind developer Bluewater Wind Delaware, LLCsigned a 25-year contract with utility Delmarva Power for up to 200 megawattsof power from Bluewater’s proposed wind farm 11.5 miles off the Delaware coast. That deal was approved by theDelaware Public Service Commission in 2008, and covers about a third of theproject’s expected output.

Like most power purchase agreements entered into prior toproject construction, the Bluewater-Delmarva contract contained a series ofmilestones and deadlines that each party must meet on schedule, or else theagreement may be terminated. Many of theseproject milestones specified in the PPA were predicated on expectations thatagencies like the former U.S. Minerals Management Service would develop regulationsand programs allowing for the development of offshore wind projects. As these regulatory developments took longerthan expected, last year Delmarvagot the Delaware PSC’s permission to extend a number of these deadlines.

While most of these deadlines were extended for two years,one date was extended for only three months. Under the original PPA, Bluewater could recover $4 million of its $6million development security deposit as late as June 23, 2011 if it cancelledthe deal. While the Delaware PSC partiallyextended this deadline, Bluewater only has until September 23, 2011 to withdrawfrom the agreement or else it will forfeit $2.75 million of its deposit.

Reports claim that Bluewater believes it needs a federalloan guarantee to complete the project’s finance – but fundingfor the Department of Energy’s loan program has been drastically slashed. Will the offshore wind developer choose topress forward given this uncertainty? Will the utility and the developer agree to seek a further deadline extension? What will Congress do to the DOE loanprograms?

Monhegan ocean energy

2011-09-13T07:54:00.000-04:00

The waters around the Maine island of Monhegan are a powerfulforce. Located about 12 nautical milesoffshore, Monhegan sports both a vibrant year-round community and significantseasonal tourism industry. The island’socean resources – including fish, lobster, wildlife and scenic location – form thebasis for much of its economy.

Nearing the dock, Monhegan.

Monhegan’s waters may also be home to ocean energy resources. In2009, the Maine Ocean Energy Task Force selected a site off Monhegan as anoffshore wind test site. At the siteabout 2 miles south of the island, the University of Maine-led DeepCWind Consortium plans to develop ascale-model floating platform and test turbine. The Monhegan wind project may be built and installed in 2012.

Monhegan is lashed by powerful waves as well, as evidencedby storiesof hurricane-spawned waves sweeping people away from the island. Wavescan contain significant amounts of energy; under the right circumstances, someof that waveenergy can be harnessed to produce usable power. Although there are no formal proposals todevelop wave energy projects off Monhegan, the rocky eastern shore demonstratesthe power of the ocean.

Landmark FERC electric orders promote fairness

2011-09-12T07:05:00.000-04:00

The Federal Energy Regulatory Commission is the lead federalagency in a variety of energy-related fields. FERC regulates the transmission and wholesale sales of electricity ininterstate commerce, the transmission and sale of natural gas for resale ininterstate commerce, and the transportation of oil by pipeline in interstatecommerce. FERC also approves the siting (andabandonment) of interstate natural gas pipelines and storage facilities, aswell as siting applications for electric transmission projects under limitedcircumstances. FERC also licenses andinspects private, municipal, and state hydroelectric projects.

FERC has issued a number of landmark orders pursuant to its jurisdictionover electric utilities. These landmarkorders focusing on promoting fair and competitive markets include:

Order No. 888 (Transmission Open Access. Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities). This landmark rulemaking fostered greater competition in wholesale power markets by reducing barriers to entry in the provision of transmission service. Historically, vertically integrated utilities dominated the electric power industry. Despite efforts to empower independent power producers and to promote competition, the Commission noted that “[b]ecause many traditional vertically integrated utilities still did not provide open access to third parties and favored their own generation if and when they provided transmission access to third parties, access to cheaper, more efficient generation sources remained limited.” In 1996, the Commission adopted Order No. 888 prohibiting public utilities from using their monopoly power over transmission to unduly discriminate against others. The Commission required interstate transmission utilities to file open access non-discriminatory transmission tariffs – Open Access Transmission Tariff or OATTs – containing minimum terms and conditions of non-discriminatory service. It also obligated such public utilities to “functionally unbundle” their generation and transmission services.
Order No. 890. An outgrowth of Docket Nos. RM05-17-000 & RM05-25-000 (Preventing Undue Discrimination and Preference in Transmission Service), Order No. 890 cracked down on opportunities for utilities to unduly discriminate against certain customers under the Commission’s pro forma OATT. In Order No. 890, the Commission strengthened its pro forma OATT toremedy undue discrimination, facilitate the Commission’s enforcement, and increase transparency of transmission planning and use rules.
Order No. 1000. The result of Docket No. RM10-23-000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities), FERC Order No. 1000 reforms how public utilities plan and pay for transmission upgrades. Previously, grid operators had fairly broad discretion to determine who should pay for an approved transmission line -- all regional consumers, the subset of consumers benefited by the line, generators, or others. FERC observed that the lack of a uniform framework for cost allocation decisions meant that on the one hand, consumers could be paying more for transmission than they should, while on the other hand renewable power projects might be stifled by a lack of transmission expansion. To fix this problem, the Commission issued Order No. 1000 to provide a framework for fair and open evaluation of transmission needs and to allocate the costs of transmission solutions fairly to those who receive benefits from them.
Order No. 719. The product of Docket Nos. RM07-19-000 and AD07-7-000 (Wholesale Competition in Regions with Organized Electric Markets), Order No. 719 offered a series of reforms to improve the operation of organized wholesale electric power markets. Based on the premise that improving the competitiveness of organized wholesale markets is integral to the Commission's mission, FERC required regional grid operators to reform their tariffs and practices in the areas of demand response, long-term power contracting, market monitoring, and the responsiveness grid operators to their customers – and through them, to the consumers who benefit from and pay for electricity services.
Order No. 745. The product of Docket No. RM10-17-000 (Demand Response Compensation in Organized Wholesale Energy Markets), Order No. 745 requires regional grid operators to compensate customers fairly for reducing their consumption of electric energy in response to the grid operator’s warnings of supply scarcity – demand response – when that reduction in energy use is cost-effective and capable of displacing the need to additional generation online.

Susquehanna River flooding threatens dam, communities

2011-09-09T10:07:00.000-04:00

Close on Hurricane Irene’s heels, the remnants of TropicalStorm Lee are dropping up to 10 inches of rain across the northeastern United States. As we saw whenIrene hit Vermont, storms like this can cause not only widespread flooding asstreams rise above their banks, but even risk dam failure and morecatastrophic flooding.

Now, the rains caused by Tropical Storm Lee have ledauthorities from Maryland to New York to order the evacuation of nearly 100,000people.

Flooding along the Susquehanna River is responsible for alarge portion of this risk. Arising outof branches in upstate New York and western Pennsylvania, the 464-mile longSusquehanna is the longest river on the east coast to drain into the AtlanticOcean. The river overtopped retainingwalls in Binghamton, NY earlier today, leading to road closures thateffectively isolate the city. Downstream,deepening floods have caused the evacuation of the entire city of Wilkes-Barre,PA.

The Susquehanna flooding has also impacted the Conowingo hydroelectricdam about 10 miles above the river’s mouth in Maryland. With 11 turbines providing a nameplate capacity of 572 megawatts, the Conowingo dam is one of the nation's largest non-federal hydroelectric facilities. Now operated by Exelon subsidiarySusquehanna Electric Company, the Conowingo Dam is threatened by the Susquehanna floodwaters. As a result, 50 of the dam’s 53 flood controlgates have been opened, causing authorities to evacuate people from thedownstream communities of Havre de Grace and Port Deposit. Area residents remember 1972's Hurricane Agnes, whose rains and flooding caused all 53 flood gates to be opened and the dam operator to prepare for a controlled breach of part of the dam.

As Lee’s rains move out of the area, water levels in theSusquehanna River will peak and then recede. Time will tell how damaging the flood waters will be.

USDA funds energy projects

2011-09-08T07:30:00.000-04:00

Businesses are taking advantage of incentives to reducetheir consumption of energy from the utility grid through both energyconservation and distributed renewable generation. A number of programs provide grant fundingfor part or all of these projects, on top of other incentives like taxbenefits.

The U.S. Department of Agriculture runs several energyincentive programs under the RuralEnergy for America Program (REAP). Theseprograms take different shapes; some offer payments or grants, whicle othersoffer loans and loan guarantees. All aredesigned to promote the development and commercialization of renewable energysources including wind, solar, geothermal, hydrogen, ocean waves, hydroelectric,biomass, and biofuel (ethanol, biodiesel, etc.)

REAP’s Renewable Energy Systems/Energy EfficiencyImprovement grant program is one funding source for farm and commercial projects. REAP conducts periodic solicitations forproject proposals, and awards grants on a competitive basis. Grant winners can receive up to 25% of their totaleligible project costs, capped at $500,000 per project for renewable energysystems and $250,000 per project for energy efficiency improvements.

When USDA published its Notice of Funds Availability for REAPthis spring, an estimated $70 million in REAP funding was expected this year,based on the allocations in the 2008 Farm Bill. In response to the request for applications, projects were proposed andselected in every state.

In August 2011, the USDAannounced $183,339 in grant funding for 8 Maine projects. Most of these grant awards were for solarenergy projects; two projects included solar and energy efficiency, while onefocused on a biomass project. Forexample, the Bancroft Contracting Corporation in South Paris won $40,000, splitbetween a rooftop solar array expected to produce 270,050 kilowatt-hours peryear and energy efficiency improvements.

USDA’s REAP program is one tool businesses can use to helpfinance innovative and cost-effective energy efficiency and renewable energy projects.

Maine dam safety in question

2011-09-07T10:12:00.000-04:00

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

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

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

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

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

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

Federal support for biofuel development

2011-09-02T11:25:00.000-04:00

The federal government is supporting the research, development, and commercialization of drop-in biofuels. This week the U.S. Department of Energy announced that three projects will receive up to $12 million in federal investment.

Biofuels have historically included plant-derived liquid fuels like ethanol (derived from corn or cellulosic sources) and biodiesel. As contemplated by the Department of Energy, drop-in biofuels are designed to be used as additives or even replacements for liquid fuels like gasoline, diesel and jet fuels, all without requiring modifications to engines or fuel distribution networks.

The United States has expressed interest in biofuels for some time. For example, after a report suggesting the possibility that petroleum-based fuels might not be available for future military operations under certain circumstances, several branches of the U.S. armed forces started trialing biofuels - and helping fund biofuel R&D and commercialization efforts.

Now, the Department of Energy has announced awards of up to $4 million to each of three projects:

Ethanol to jet fuel, with benefits. The Department of Energy chose Illinois' LanzaTech to develop a process to convert ethanol produced from biomass into jet fuel. The process is also intended to produce and capture butadiene, an additional bio-product that can make the process more cost-effective.
Biomass to bio-crude to gasoline and diesel. Research Triangle Institute in North Carolinawas selected to demonstrate the long-term operation and performance of an integrated process to produce a bio-crude intermediate material from raw biomass, and then upgrade the bio-crude into gasoline and diesel.
Biomass to intermediates to gasoline and diesel. Virent Energy Systems, Inc. of Wisconsin was selected to demonstrate yields and scalability for converting biomass into oxygenated chemical intermediates, and then upgrading the intermediates to a hydrocarbon suitable for refining and blending with gasoline and jet fuel.

Vermont dam weathers Hurricane Irene

2011-08-30T16:09:00.001-04:00

Hurricane Irene barreled up the East Coast of the U.S. this weekend, bringing high winds and heavy rain to a broad swath of the continent. About 5 million electricity customers lost power at some point during the storm's progress, with service still off for many consumers. Hurricanes and other storm events place added stresses on our electric infrastructure, resulting in not only power outages but possible dam failure.

In rain-lashed Vermont, utility Green Mountain Power worked to prevent the failure of the Marshfield Dam near the town of Cabot. Located on the Winooski River less than 20 miles upstream from Vermont's capital Montpelier, the earthen Marshfield Dam creates a 400-acre impoundment known as Molly's Falls Pond. Green Mountain Power uses the water impounded by the dam to run a 5-megawatt hydroelectric project.

Irene dumped a lot of water on Vermont. As a result, the water behind the Marshfield Dam rose within 10 feet of the dam's crest on Sunday night -- far too close for comfort. When the impoundment behind any dam gets too full, the dam is at increased risk of breaching; if a dam gets overtopped -- particularly an earthen dam -- this risk of dam failure is even greater. Dam failure at Marshfield could have serious impacts for the people and property downstream in the Winooski River Valley, from Montpelier further down. As a result, Green Mountain Power's emergency plan calls for a large controlled release of water through the dam once the water gets within 6.5 feet of the dam's crest. As a precaution, the utility asked the state emergency management agency to evacuate about 300 households in Marshfield, Plainfield, East Montpelier and Montpelier. Dam safety was at risk.

In the end, the water stopped rising, and then returned to a lower level. (Check out the USGS's streamflow data for the Winooski River near Montpelier.) Although Vermont suffered major damage from Hurricane Irene's remnants, the Marshfield Dam survived this storm.

Demand response, customer-provided grid support

2011-08-26T07:41:00.051-04:00

This summer, the electric grid has largely weathered the increased demand for power during heat waves. Grid operators have a variety of tools to ensure sufficient energy supply to meet peak demands. In recent years, the smart-grid star in the grid's toolkit has been demand response: programs that allow customers to respond to signals about the scarcity of electricity by temporarily reducing their consumption from the grid. This summer, customer-provided demand response has not only kept the lights on, but has also reduced society’s energy costs by reducing the need for the most expensive marginal peaking generation units.

Last March, the Federal Energy Regulatory Commission issued a landmark ruling that demand response should be compensated fairly. In this ruling – Order No. 745 – FERC held that demand resources should be paid at market-based prices when two criteria are met: capability and cost-effectiveness. When demand resources can displace the need for bringing additional generation online, and when doing so lowers our grid costs, Order No. 745 requires organized wholesale energy market operators to pay demand response resources for the full value they provide to the grid.

Now, some regional grid operators are proposing major changes to their demand response programs. While some of these changes are designed to comply with Order No. 745, other changes seek to place new limits on who can participate in demand response. For example, northeastern grid operator ISO New England has asked FERC to approve its proposal to eliminate the demand response value provided by consumers capable of using existing on-site generation to produce power to support the grid during times of crisis.

Decades of federal and state policy have supported investment in distributed generation projects, ranging from micro-combined heat and power (micro-CHP) and cogeneration to small and medium-sized wind, rooftop solar photovoltaic systems and even fuel cells. Distributed generation has a strong history of policy support, but if FERC accepts ISO New England’s proposal to limit behind-the-meter generation’s ability to provide demand response, the region will need other resources to keep the lights on during times of peak demand – new generating units, transmission lines, and substations.

FERC has docketed ISO New England’s request as Docket No. ER11-4336-000, and is accepting public comment through 5:00 pm Eastern time on Friday, September 09, 2011.

Massachusetts may revamp solar and distributed generation interconnection process

2011-08-25T07:12:00.002-04:00

Being able to interconnecting electricity generating units to the grid is almost always necessary. Even islands - literal or figurative - often have their own microgrids to which new generation must be interconnected, but usually the electric grid in question is run by a public utility.

Despite federal and state policies designed to promote the development of solar energy projects and other renewable and efficient distributed generation, many utilities are failing to process interconnection applications within the timelines required by their tariffs. (As I previously wrote, regulators in the Canadian province of Ontario are currently wrestling with this problem as well.) A recent filing by the energy office of the Commonwealth of Massachusetts appears likely to trigger reforms to the process for interconnecting new distributed generation to the grid.

The Massachusetts Department of Energy Resources’s filing consists of a consultant's report commissioned by DOER and the Massachusetts Clean Energy Center, coupled with a formal petition requesting that the Department of Public Utilities open an investigation on interconnection procedures.

Prepared by consulting firm KEMA, the report provides a snapshot of the current interconnection process, as well as offering recommendations for improvements. The report is based on surveys of distributed generation developers and utilities. The report’s key findings include:

Significant Increase in New Distributed Generation: Recent years have brought a significant increase in the volume of applications for interconnection of distributed generation in Massachusetts. The volume of interconnection applications reviewed grew by a factor of 7 between 2004 and 2010 - a significant increase in interconnection requests.
Current Process Can't Handle the Volume: A very high percentage of utility reviews of interconnection requests have missed key deadlines. For example, in 2009, 100% of the interconnection application review conducted under utilities’ standard process exceeded the timeline specified in the utility’s tariffs. Currently, utilities face no penalty for missing these deadlines. As the report notes, “There is no consequence to the utilities for delays, even though there are consequences – often significant – to the DG applicants.”
Interconnection Costs Cause Frustration: While current application fees and witness test costs may be reasonable, the report notes that applicants are generally dissatisfied with the costs of the interconnection facilities upgrades and equipment required by utilities. Disputes over the nature and cost of new and upgraded facilities increase costs, add delays, and further chill distributed generation development through increased uncertainty.

The report notes that these failings come despite significant policy support for distributed generation:

In summary, the meta-message of this report rests at the intersection of several trends. Massachusetts has created a vibrant policy environment for DG, underpinned by one of the best interconnection processes in the country, a process which has generally worked well for most DG applicants since its introduction in 2004. Over the last seven years, however, and particularly under the Patrick Administration, the growth in DG volume has grown significantly.

Yet, our survey showed that 79% of Expedited applicants and 75% of Standard applicants are “Somewhat dissatisfied” or “Very dissatisfied” with a process they describe as long, inconsistent, and “too complicated to comment”. . . .

We define a successful process as one that meets its customer demand with high quality outcomes, within acceptable parameters of time and cost. This review demonstrates that – seven years after its introduction – the current process by which DG is interconnected in Massachusetts is no longer meeting the demands of three-quarters of its customers.

Based on these findings, the report offers recommendations to remedy the system's failure, including proceedings before the State Department of Public Utilities to redesign the interconnection process to be better suited to high-volume penetration of distributed generation.

The DOER’s petition was filed on August 18, 2011. The Department of Public Utilities is expected to respond to the petition by opening an investigation on interconnection along the lines suggested in the report. How that proceeding affects the experiences of utilities, distributed generation owners or developers, and ratepayers remains to be seen.

Maine's offshore wind test sites

2011-08-24T09:31:00.006-04:00

Within the next several years, three sites off the coast of Maine may see offshore wind tests and pilot projects. In December 2009, the Maine Ocean Energy Task Force selected three sites -- waters near the island of Monhegan, Boon Island and Damariscove Island -- as test sites for offshore wind development.

Looking northeast from Griffith Head, Reid State Park, Maine.

Plans to develop these sites remain pending.

The Monhegan site (PDF map) lies about 2 miles south of the island, and runs about 2 miles square near the edge of Maine's state territorial waters. At the Monhegan site, the DeepCWind Consortium, a group led by the University of Maine, plans to develop a scale-model floating platform and test turbine about 2 miles south of the island.

The Damariscove site (PDF map) lies southwest of uninhabited Damariscove Island, about halfway between Damariscove and Seguin Island off the mouth of the Kennebec River.

The Boon Island site (PDF map) lies about 2 miles south of that island, off the town of York on the southern coast near Kennebunkport.

What will the coming years bring to these sites? The Monhegan site may see its first floating turbine deployed in 2012.

Blythe shifts from concentrating solar to PV

2011-08-23T07:32:00.001-04:00

One of the world's largest solar projects may partially shift from concentrating solar thermal to photovoltaic technology. If it happens, this technological shift demonstrates how different technologies compete for market share even within a given project.

Over the past year, I've written several times about the Blythe solar energy project under development in California. Proposed by Solar Trust of America, a joint venture between German developers Solar Millenium AG and Ferrostaal AG, the full-scale project could add about 1,000 megawatts of new solar capacity to the regional grid -- about as much capacity as a nuclear plant, although less capable of producing that full value around the clock. As originally proposed, the Blythe project would rely on mirrors to concentrate the sun's rays to heat water, making steam to run turbine generators.

Solar Millenium has now announced plans to convert the first 500 MW phase of the Blythe project to solar photovoltaics. With this decision, the Blythe project is now on track to follow nearly 1,850 MW more California solar capacity changing from solar thermal to solar PV in just the last year. Observers note that this shift is spurred in part by lower photovoltaic costs as a result of greater market penetration, with solar panel elements falling nearly 50% in cost in recent months.

The Blythe developers have not yet selected a PV panel manufacturer, nor have they specified the technology for a second 500 MW phase of the project.

Massachusetts regulators approve utility's wind contracts

2011-08-22T11:11:00.002-04:00

In most U.S. states, laws require utilities to include a specified amount of renewable power in the energy mix they sell customers. These renewable portfolio standard (or RPS ) laws vary from state to state in their details, but vertically-integrated can often satisfy the RPS by entering into contracts to buy power from specific renewable projects. For example, Massachusetts' largest utility National Grid plans to buy half of the Cape Wind offshore wind project's output to comply with the RPS.

On Friday, Massachusetts regulators approved an array of wind energy contracts proposed by the Commonwealth's second-largest utility, NStar. The state Department of Public Utilities has been considering contracts between NStar and three wind projects:

Iberdrola's 29 megawatt Hoosac Wind project, in the Berkshires of Massachusetts, should be running July 2012, a ten-year deal
Iberdrola's 48 megwatt Groton Wind project near Plymouth, New Hampshire, should be running December 2012, a ten-year deal
First Wind's 32 megawatt Blue Sky East project in Eastbrook, Maine, should be running by May 2012, a fifteen-year deal

While the agreements' pricing remains confidential, some aspects of the pricing are known. NStar conducted a competitive bidding process to select the projects for contracting; NStar's process is said to have emphasized getting the lowest price. It is also public that the three contracts approved on Friday are for fixed prices, meaning that unlike escalating price contracts, the price the utility pays the wind developers per kilowatt-hour will remain flat over the contracts' terms.

August 18, 2011 - new report assesses Texas, SW blackouts

2011-08-18T14:52:00.002-04:00

Last February’s blackouts in Texas and the Southwest disrupted life for millions of electricity consumers. When the weather became unusually cold for the region and an ice storm struck, a number of electric generators suffered outages, and natural gas supplies became curtailed. As a result, real-time wholesale power prices rose to 40 times their previous level, and grid operators were forced to resort to rolling blackouts. Even as the grid struggled to maintain its integrity, policymakers called for an investigation of what happened – and how to prevent a repeat performance.

This week, after six months of inquiry, the Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corporation (NERC) have released a report on the incident. This report – linked here as a 357-page PDF – concludes that most of the electric outages and gas shortages were due to weather-related causes, but noted that proactive steps to protect reliability were lacking.

For example, although many generators did in fact winterize their plants so they could operate in cold conditions, the report concludes that no state, regional or NERC standards required generators to take this step. The report notes that electric outages were generally caused by weather-related mechanical problems that could have been prevented by proper weatherization – measures to prevent frozen sensing lines, equipment, water lines and valves.

The report similarly concludes that the natural gas shortages and outages were mostly attributable to the lengthy cold weather, the resulting and unprecedented high demand for gas, and simultaneous reductions in supply.

Will this report change the way we protect the reliability of our grid?

August 16, 2011 - DOE loan guarantee to Maine wind project

2011-08-16T11:12:00.000-04:00

A wind energy developer has just received a $102 million loan guarantee to support its project in Maine. Yesterday the U.S. Department of Energy lent its financial support to Record Hill Wind LLC for its 50.6 megawatt project near Roxbury, Maine. The project's design includes 22 Siemens turbines and an 8 mile transmission line to interconnect with Central Maine Power's system. Born out of a partnership between Independence Wind LLC and Wagner Forest Management, the project also scored major financial support from the Yale University endowment fund.

Record Hill Wind's federal loan guarantee through the DOE further solidifies the project's financial footing. Department of Energy operates several loan guarantee programs; Record Hill's backstop comes courtesy of DOE's Section 1705 program, which is now ramping down. While the Section 1705 program may be a casualty of the federal budget, DOE's three loan programs have to date offered over $40 billion in support for 42 clean energy projects across the country.