Facebook data center power demand

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

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

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 a project, 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

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

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

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 usage.

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

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?

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

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

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

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

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

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-era electric 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

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

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

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

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

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.