Report on US electric grid physical security

Since a 2013 rifle attack on a critical electric power substation in California, the U.S. electric power sector has generally moved toward greater physical security for critical assets, according to a report published by the Congressional Research Service. But the report says bulk power security "remains a work in progress," and suggests further investment -- and policy reforms -- may follow.

The report published on March 19, 2018 -- NERC Standards for Bulk Power Physical Security: Is the Grid More Secure? -- begins with the premise that securing the electric power grid is among the nation's highest priorities for critical infrastructure protection. It notes that a 2013 rifle attack on an electric transmission substation in California which caused widespread power outages also broadened policy attention from cybersecurity to encompass the physical security of assets critical to the power grid.

In response, Congress enacted legislation to strengthen power grid physical security and to facilitate its recovery from disruption. Section 1104 of the Fixing America’s Surface Transportation (FAST) Act contains provisions to protect or restore the reliability of critical electric infrastructure or defense of critical electric infrastructure during a grid security emergency. The Federal Energy Regulatory Commission (FERC) and the nation's electric reliability organization NERC also took action to develop new reliability standards for the physical security of bulk power critical infrastructure.

But physical security risks may persist. The report references a September 2016 rifle attack on a Garkane Energy Cooperative transformer substation in Utah as illustrating this persistence. The report notes that while it is probably accurate to conclude that the grid is more physically secure than it was in 2013, "it has not necessarily reached the level of physical security needed based on the sector's own assessments of risk.

The report notes Congress's continued concern about the physical security of the electric grid. It identifies possible areas for further policy focus as including "security implementation oversight, cost recovery, hardening vs. resilience, and the quality of threat information."

Meanwhile, cybersecurity has remained a priority. An October 2017 FERC report describing the results of its audits of regulated companies' cybersecurity protection processes and procedures noted that most met the applicable mandatory standards. But earlier this month, NERC fined an anonymous utility $2.7 million for alleged violations of reliability standards in connection with a data security breach, and the U.S. Department of Homeland Security issued warnings about Russian hackers targeting computer systems controlling energy and other critical infrastructure.

Interest in shoring up the security of energy infrastructure and systems -- both from physical attacks as well as cyber threats -- appears poised to drive continued discussions, regulation, and investment.

Will Utah counties fund thorium reactor?

Could a coalition of rural counties in Utah and a startup company develop a thorium-fueled nuclear reactor for electric power and other purposes?

According to its website, the Seven County Infrastructure Coalition is currently comprised of seven counties in eastern Utah: Carbon, Daggett, Duchesne, Emery, San Juan, Sevier, and Uintah.  The website describes the Coalition’s main roles and mission as "to identify revenue-producing infrastructure assets that will benefit the region" and "to plan infrastructure corridors, procure funding, permit, design, secure rights-of-way and own such facilities," with operation and maintenance possibly outsourced to third parties.

Apparently under consideration by the Coalition are energy projects, including a "thorium energy" project and a "hydrogen plant" project.  For example, the "Procurement" section of the Coalition's website includes a Request for Qualifications for Project Analyst for Potential Thorium Energy and Hydrogen Plant Projects, as well as a Request for Qualifications Project Financial Analyst on Potential Thorium Energy Project.

Under the Project Analyst RFQ, which closed August 1, 2017,

The Coalition seeks an individual or team to act as a Project Analyst to advise it and its member counties on two proposed projects, how to evaluate emerging technologies, and the respective project teams. One project is a thorium energy facility for producing electricity, etc. as proposed by Alpha Tech Research Corporation. The second project consists of hydrogen plants to be used as fueling stations for hydrogen/electric semi-trucks as proposed by Nikola Motor Company, LLC.

Responsibilities defined in this original RFQ would include evaluation of the thorium energy and hydrogen plant projects, including an evaluation of "the feasibility and viability of projects in general, as well as the proposed projects, and determine how the Coalition and its members may use their assets to best benefit the public."

According to its website, Alpha Tech Research Corp.'s motto is "Changing the face of nuclear power with clean, safe, molten salt reactor technology."  But little other public information is easy to find on the company.

Thorium is a radioactive element that can be used in a nuclear reactor as a fuel for power production.  It is distinct from the uranium-based fuel used in traditional nuclear power plants.  Some limited research and development was conducted on thorium-based reactors in the twentieth century, but recent projects and all commercial reactors rely the uranium fuel cycle.  Proponents of thorium reactors suggest abundant fuel supplies and reduced weapons proliferation risk compared to uranium, combined with other advantages of nuclear power such as reliable baseload generation with zero carbon emissions.  Some point to Utah's mineral richness as a cost-effective source for lithium, beryllium, and other materials that could be useful in molten salt reactor resign. But crucially the technology, regulation, and business structures necessary to support a thorium reactor may not yet exist.

Fifteen days after the Project Analyst RFQ closed, the Coalition issued another request for qualifications "to seek an individual or team to act as a Project Analyst to advise it and its member counties on a proposed project related to thorium energy. In addition, the Coalition seeks guidance on how to evaluate emerging technologies, and companies or groups proposing projects to the Coalition. The thorium energy facility for producing electricity, etc. is proposed by Alpha Tech Research Corporation." Proposals under this subsequent RFQ are due by 2:00 PM on October 2, 2017.  According to the Salt Lake Tribune, a coalition representative reported, "The coalition’s initial request for qualifications drew no adequate responses by its Aug. 1 deadline."  (Query why not.)

It's unclear how far the Utah counties' efforts can go.  The coalition's stated criteria for evaluating potential projects include requiring appropriate project benefits (such as facilitating needs in rural Utah that would otherwise go unaddressed), as well as avoidance of any "fatal flaws" (such as "obvious non-Coalition sponsor that should take the lead", project success unlikely" and "low perceived benefit compared to cost.")  The coalition is presumably at the stage where it is seeking expert advice to help it evaluate the thorium energy project under these criteria.

In its materials, the coalition emphasizes its expectation to rely on public-private partnerships, in part to allocate project risk to private entities with special expertise in taking those risks.  But developing the first commercial thorium reactor inherently involves a variety of risks -- including developing a technology that works, securing all necessary regulatory approvals, and having business or financial arrangements in place that make the project a success.  These risks could pan out in the counties' favor -- but might not.  A coalition of South Carolina utilities developing what would have been the nation's first new commercial nuclear reactor recently announced a decision to suspend that project partway through construction, following years of delay, billions of dollars in cost overruns.  While a thorium reactor might avoid some of these challenges, others are likely systemic to the state of the nuclear power industry from a technological, regulatory, and business perspective, and would be hard for the counties to avoid. The counties may also have more proximate opportunities to achieve similar goals, including by facilitating or developing renewable energy infrastructure.

At the same time, the coalition deserves credit for thinking proactively and considering its options.  Whether the coalition continues to pursue thorium energy, or focuses on less speculative projects, the coalition's fundamental mission remains "to improve the quality of life through cooperative regional planning, increased economic opportunity, and sustainable implementation."  With the right balance of risk and reward, its evaluation of proposed projects could advance that mission.

Vail Resorts announces sustainability, net zero plan

Vail Resorts, Inc. -- the largest ski and mountain resort operator in the world -- has announced a comprehensive sustainability commitment that calls for "zero net emissions by 2030, zero waste to landfill by 2030 and zero net operating impact to forests and habitat."  According to the company, Vail Resorts' "Epic Promise for a Zero Footprint" will give resort guests and employees "the opportunity to enjoy the natural environment and resources without leaving an impact."
 
Vail Resorts' subsidiaries operate 11 mountain resorts and three urban ski areas, including Vail, Beaver Creek, Breckenridge and Keystone in Colorado; Park City in Utah; Heavenly, Northstar and Kirkwood in the Lake Tahoe area of California and Nevada; Whistler Blackcomb in British Columbia, Canada; Perisher in Australia; Stowe in Vermont; Wilmot Mountain in Wisconsin; Afton Alps in Minnesota and Mt. Brighton in Michigan. The company also owns and operates hotels as well as a real estate planning and development subsidiary.

In a July 25, 2017, press release, Vail Resorts announced its "Epic Promise for a Zero Footprint" sustainability commitment.  Pointing to Whistler Blackcomb's environmental commitment as inspiration, Vail Resorts announced its intent "to go beyond setting a partial emissions reduction target by executing on a more expansive and ambitious plan."

With respect to net zero emissions from operations by 2030, the Vail Resorts plan calls for continued reduction of the company's electricity and gas use by improving operating practices and investing $25 million in innovative, energy-saving projects, such as low-energy snowmaking equipment, green building design and construction, and more efficient grooming practices and equipment.  Among other measures, it envisions purchasing 100 percent renewable energy equivalent to Vail Resorts' total electrical energy use and working with utilities and local, regional and national governments to bring more renewable energy to the grids where the company operates its resorts. As an interim goal, the plan states the company's intent to achieve a 50 percent reduction in its net emissions by 2025, based on 2016 levels.

Other 2030 goals set in the Vail Resorts plan include "zero waste to landfill" (by diverting 100 percent of the waste from its operations to more sustainable pathways) and "zero net operating impact to forests and habitat" (by measures including mitigation, tree planting and forest restoration, and minimizing or eliminating the impact of any future resort development). 

Substation security and the Garkane shooting

As the U.S. strengthens protections for its electricity grid, much of the discussion focuses on cybersecurity -- but physical security is also important, as shown by an attack on a Utah utility's substation.  On September 25, an unknown gunman fired at least 3 shots into a distribution system substation, damaging a transformer and causing power outages.  The incident may place renewed pressure on utilities to secure their infrastructure against vandalism and terrorism.

As reported by the Deseret News, the damage occurred at a substation owned by Garkane Energy Cooperative.  An assailant reportedly shot the main transformer's oil-cooled radiator system, causing the transformer to overheat and fail.  About 13,000 customers lost power across most of Kane and Garfield counties.  A spokesman for the cooperative said damage to the transformer could reach $1 million; repairs could take 6 to 12 months.  The utility has offered an unusually high reward -- $50,000 -- for information leading to the arrest of the shooter.

This is not the first time someone has used firearms to damage utility infrastructure.  Some incidents, such as the 2012 shotgunning of 167 insulating discs on Vermont's transmission system, may be considered vandalism.  Others, like the 2013 sniper shooting of a PG&E substation in San Jose, California, are considered terrorism.  That attack led the Federal Energy Regulatory Commission to implement new physical security protections for utility infrastructure known as CIP-014, through its Order No. 802.

The Garkane incident remains under investigation.  More broadly, it may strengthen calls for further hardening of the utility system against physical attack.  Meanwhile, efforts continue to strengthen cybersecurity protections for the grid.

Alta Ski Area conduit micro-hydro project

Alta Ski Area has proposed developing a micro-hydropower project along an existing pipeline, and hopes to benefit from a streamlined regulatory process.  Federal regulators have made a preliminary determination that the proposed Alta Micro-Hydro Project, in Alta, Utah, satisfies the requirements to be treated as a "qualifying conduit hydropower facility," which would not require licensing under the Federal Power Act.

Alta's proposed project would include a new powerhouse to be built along the existing underground 6-inch-diameter snowmaking water supply pipeline delivering water from Cecret Lake to the Wildcat Pump House, a new turbine/generating unit with an installed capacity of 75 kilowatts, intake and discharge pipes, and appurtenant facilities.  The unit is estimated to generate between 115 and 225 megawatt-hours annually.  There is no dam associated with the project.  Alta presented its micro-hydro project as part of a 2012 request to update its master plan, which the U.S. Forest Service accepted.

Ski areas with snowmaking capacity typically have existing pipelines and water infrastructure, coupled with significant vertical relief.  This can create opportunities to generate electricity using energy harvested from water flowing downhill through a pipeline, particularly if reducing system pressure (like a pressure relief valve) is otherwise needed. 

A 2013 law was designed to help small conduit-based hydropower projects by eliminating their need for a license or exemption from licensing issued by the Federal Energy Regulatory Commission.  Section 4 of the Hydropower Regulatory Efficiency Act of 2013 amended Section 30 of the Federal Power Act.  Section 30 now provides that a "qualifying conduit hydropower facility" -- one that is determined or deemed to meet defined criteria -- is not required to be licensed or exempted from licensing under the Federal Power Act.  These criteria include:

• The conduit the facility uses a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption and not primarily for the generation of electricity.
• The facility is constructed, operated, or maintained for the generation of electric power and uses for such generation only the hydroelectric potential of a non-federally owned conduit.
• The facility has an installed capacity that does not exceed 5 megawatts. 
• On or before August 9, 2013, the facility is not licensed, or exempted from the licensing requirements of Part I of the FPA.

The Federal Energy Regulatory Commission administers this statute.  To start the regulatory process, on May 16, 2016, Alta filed a notice of intent to construct a qualifying conduit hydropower facility.  Alta supplemented its notice on May 20 to clarify that the project "will only operate when there is excess capacity available in the pipeline and when water is hydrologically available", generally after the winter snowmaking season, during spring runoff.  Alta also restated that the pipeline's main purpose will continue to be snowmaking.

Yesterday the FERC issued its notice of preliminary determination of a qualifying conduit hydropower facility for Alta's project.  That notice examines the project relative to each of the four statutory criteria, and then provides the Commission's preliminary determination:

The proposed addition of the hydroelectric project along the existing water supply pipeline will not alter its primary consumptive purpose. Therefore, based upon the above criteria, Commission staff preliminarily determines that the proposal satisfies the requirements for a qualifying conduit hydropower facility, which is not required to be licensed or exempted from licensing.

The notice also sets a 30-day deadline for filing motions to intervene, and a 45-day deadline for filing comments contesting whether the facility meets the qualifying criteria and providing an evidentiary basis.

Other recently proposed conduit hydro projects have been determined to be qualifying conduit hydropower facilities, including a Colorado project using an existing "ditch drop," a Castle Valley, Utah water treatment project, a California wholesale water agency conduit project, and a New Hampshire water works.

Utah conduit hydropower project qualifies

Federal energy regulators have issued a letter determining that a proposed Utah hydropower project meets criteria for development without needing a hydropower license.  Castle Valley Special Service District's proposed Ferron Water Treatment Plant Project would generate electricity using the pressure of water in an existing conduit entering a drinking water treatment plant.  As a result of a determination by the Federal Energy Regulatory Commission, the project can be developed without a FERC hydropower license.

On January 27, 2016, the Castle Valley Special Service District filed with the Federal Energy Regulatory Commission a notice of intent to construct a 6-kilowatt in-conduit hydroelectric net metered system.  The District is a tax exempt municipal government entity that, among other services, provides drinking water to the residents of Ferron City and Clawson Town.

That notice of intent described plans to harness or recover water pressure lost at the inlet to the District's proposed new Ferron Water Treatment Plant.  Water from the Millsite Reservoir would be transmitted to the treatment plant in a conduit owned by Ferron City and the District.  Excess pressure in the incoming untreated water would flow through a pressure reducing valve and turbine hydropower generator.

Under section 30 of the Federal Power Act (FPA), as amended by section 4 of the Hydropower Regulatory Efficiency Act of 2013 (HREA), a qualifying conduit hydropower facility -- one that is determined or deemed to meet defined criteria -- is not required to be licensed or exempted from licensing under the Federal Power Act.  These criteria include:

• The conduit the facility uses a tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption and not primarily for the generation of electricity.
• The facility is constructed, operated, or maintained for the generation of electric power and uses for such generation only the hydroelectric potential of a non-federally owned conduit.
• The facility has an installed capacity that does not exceed 5 megawatts. 
• On or before August 9, 2013, the facility is not licensed, or exempted from the licensing requirements of Part I of the FPA.

On February 2, 2016, the Federal Energy Regulatory Commission issued its notice of a preliminary determination that "the proposal satisfies the requirements for a qualifying conduit hydropower facility, which is not required to be licensed or exempted from licensing."

Following the expiration of comment and intervention deadlines, on March 28 the Commission issued its "written determination that the Ferron Water Treatment Plant Project meets the qualifying criteria under FPA section 30(a), and is not required to be licensed under Part I of the FPA."

As the FERC determination on the Ferron project notes, "Qualifying conduit hydropower facilities remain subject to other applicable federal, state, and local laws and regulations."  But the ability to develop an in-conduit hydropower project without needing a FERC license can give a significant boost to projects with suitable conduit water resources.

Utah oil sands mine slowed

A Canadian company developing an oil sands mining and extraction project in Utah has announced a decision to "reduce the pace of field construction in order to maintain working capital flexibility," based on low oil prices.

Oil sands, also known as bituminous sands or "tar sands", are loose sand or partially consolidated sandstone saturated with a viscous form of petroleum called bitumen.  US Oil Sands Inc. is a Calgary-based company that describes itself as "focused on oil sands exploration and production in Utah."  Its wholly owned United States subsidiary US Oil Sands (Utah) Inc. has bitumen leases covering 32,005 acres of land in Utah’s Uinta Basin.

US Oil Sands' PR Spring Project area consists of 5,930 contiguous acres near the East Tavaputs Plateau in Utah.  According to the company, construction of Phase 1 of the PR Spring Project is approximately 85% complete with costs coming in below budget.  If completed, it would be the first U.S. oil sands mine to enter commercial production.

While the company has not yet entered production, US Oil Sands has described a proprietary extraction process using a citrus-based bio-solvent to extract bitumen from oil sands without the need for tailings ponds.  The company pitched this technique as different from traditional Canadian oil sands production in Alberta, where wastewater management is a controversial environmental challenge.  But the Utah proposal has drawn concern over impacts to groundwater flowing under the Book Cliffs

But the company said it conducted a detailed review of the project "in light of continued low oil prices and the closure of two key contractors’ Utah-based operations."  Specifically, the press release stated, "The low price environment has impacted the Project as two of the Company’s key contractors have closed their operations in Utah and have caused delays to the Project."  Indeed, spot prices for West Texas Intermediate have ranged near $30 per barrel in recent days, with U.S. crude futures falling below $30 earlier this year for the first time since 2003.  The press release also mentions that $10 million in previously-announced royalty financing had not closed, causing the company to explore other options including equity financing.

According to the press release, project work on the PR Spring Phase 1 project will continue at a reduced level, with an expected focus on "critical path items and areas that will lead to the most efficient restart of full construction operations in the future. In spite of delays and increased costs that will occur with restart of full construction operations, the Company is still targeting completion within the original US$60 million approved budget."

How will US Oil Sands survive the low oil price environment?  How will economic, environmental, or other factors affect the fate of Utah oil sands mining?

FERC issues EIS for Algonquin Incremental Market gas project

Staff of the Federal Energy Regulatory Commission have issued a final Environmental Impact Statement for a proposed natural gas transmission project connecting New York and New England.  In that report, Commission staff found that Algonquin Gas Transmission, LLC's Algonquin Incremental Market Project would result in some adverse environmental impacts, but that most of these impacts could be mitigated and reduced to less-than-significant levels.

A marker for the Williams Northwest Pipeline in Arches National Park, Utah.

 Algonquin Gas Transmission, LLC -- a subsidiary of Spectra Energy Partners, LP -- already owns a natural gas pipeline and transmission network running from the Texas Eastern Transmission system in New Jersey to the Maritimes & Northeast system near Boston.

In 2014, Algonquin proposed the Algonquin Incremental Market project.  The AIM project's would provide firm transportation service of 342,000 dekatherms per day of natural gas to local distribution companies and municipal utilities in Connecticut, Rhode Island, and Massachusetts.  Algonquin’s stated objectives for the Project are:

• to provide the pipeline capacity necessary to transport additional natural gas supplies to meet the immediate and future load growth demands of local gas utilities in southern New England;
• eliminate capacity constraints on existing pipeline systems in New York State and southern New England;
• provide access to growing natural gas supply areas in the Northeast region to increase competition and reduce volatility in natural gas pricing in southern New England;
• improve existing compressor station emissions through the replacement of existing compressor units with new, efficient units; and
• provide the additional service by November 2016.

As envisioned by Algonquin, the project will include the construction and operation of about 37.4 miles of natural gas pipeline in New York, Connecticut, and Massachusetts.  The project entails replacing some segments of existing pipeline, extending an existing loop pipeline to increase the system's capacity to ship gas, and installing some new pipeline.  It also includes modifications to six existing compressor stations, modifying existing meter and regulating stations, and the construction of 3 new meter and regulation stations.

Under federal law, Algonquin needs authorization from the Federal Energy Regulatory Commission to construct and operate the AIM project.  Algonquin filed its application to the FERC on February 28, 2014.  As part of the FERC's review process, the National Environmental Policy Act requires the agency to analyze and document the environmental effects of proposed federal actions such as granting Algonquin's application.

In Algonquin's case, that documentation took the form of a Final Environmental Impact Statement issued by the FERC staff today. In the final EIS, FERC's environmental analysts conclude that construction and operation of the AIM project would result in some adverse environmental impacts. However, FERC staff found that most of these impacts would be reduced to less-than-significant levels with the implementation of mitigation measures and plans proposed by Algonquin, along with additional measures recommended by the FERC staff.  Staff pointed to factors including the degree to which proposed AIM project pipeline facilities would be within or adjacent to existing rights-of-way, the planned use of the horizontal directional drill method to cross the Hudson and Still Rivers, which would avoid any direct impacts on these resources, as well as plans to minimize impacts on natural and cultural resources during construction and operation of the Project.

With the final Environmental Impact Statement issued, the FERC Commissioners will consider its staff's recommendations in making a final a decision on the AIM project.  Multiple studies have highlighted the need for up to 2 billion cubic feet per day (Bcf/d) of new pipeline capacity into New England and neighboring markets to improve reliability and reduce the cost to consumers of electricity and natural gas.  At a planned size of 342,000 dekatherms (or 0.342 Bcf) per day, the AIM project is relatively small in capacity compared to other proposed projects such as Tennessee Gas Pipeline Company, L.L.P.'s proposed Northeast Energy Direct Project, which is designed to be scalable up to 1.2 to 2.2 billion cubic feet per day of natural gas capacity.  Which pipelines end up being approved and built will shape the New England energy landscape in the coming years.

Wind to power Microsoft's Texas data center

Microsoft has agreed to purchase energy produced by a Texas wind farm to power its data center in San Antonio.  The announcement, posted on the official blog of Microsoft's Sustainability Development Team, describes a 20-year power purchase agreement with RES Americas under which Microsoft will purchase all of the output of the 110 megawatt Keechi Wind project located about 280 miles north.

The power purchase agreement fits with Microsoft's stated commitment to carbon neutrality.  Since 2012, Microsoft has imposed an internal fee on the use of carbon-based forms of energy; Microsoft uses that fee to make investments in alternative or carbon-neutral energy, such as this power purchase agreement.

The Keechi project will be owned and operated by RES Americas, a subsidiary of British company RES Ltd.  RES Americas currently operates over 600 MW of renewable energy projects, and has a renewable energy construction portfolio that exceeds 6,500 MW and 64 projects, as well as 534 miles of transmission lines.  Its Keechi project is expected to cost $200 million, and will feature 55 turbines expected to produce 430,000 megawatt hours of energy per year.  (To put this figure in context, it could power up to 45,000 homes, or cover between 5 and 10 percent of Microsoft's total electricity consumption.)  Construction is expected to begin in 2014, with the project going operational by June 2015.

Microsoft is not alone in promoting its use of renewable or alternative energy to power its data centers.  In 2012 Google entered into an agreement to purchase the output of a wind farm in Oklahoma to power its Pryor data center.  Apple's new data center in Maiden, North Carolina is powered in part by a solar photovoltaic array and a biogas-fed fuel cell.  eBay has proposed siting a 6 megawatt natural gas-fired fuel cell at its Utah data center.  Whether the data center is powered by on-site distributed generation or buys power from a designated off-site renewable resource, the trend is toward promoting cleaner, greener computing through these arrangements.  These choices may help the companies with cost control and power reliability as well as public relations.

Will large consumers of electricity continue to invest in alternative or renewable electric generation?  If so, will they favor arms-length power purchase agreements with developers of remote projects, or will they rely more heavily on on-campus development of distributed generation?  Will this trend spread beyond the big names so far - Microsoft, Apple, Google, and eBay - to the point where smaller or less tech-oriented companies develop or do similar projects and deals?

  Googa 20-year power purchase agreement (PPA) for wind energy in Texas that will be funded in part by proceeds from Microsoft’s carbon fee - See more at: http://blogs.msdn.com/b/microsoft-green/archive/2013/11/04/microsoft-signing-long-term-deal-to-buy-wind-energy-in-texas.aspx#sthash.4l62oNbo.dpuf

a 20-year power purchase agreement (PPA) for wind energy in Texas that will be funded in part by proceeds from Microsoft’s carbon fee - See more at: http://blogs.msdn.com/b/microsoft-green/archive/2013/11/04/microsoft-signing-long-term-deal-to-buy-wind-energy-in-texas.aspx#sthash.4l62oNbo.dpuf

a 20-year power purchase agreement (PPA) for wind energy in Texas that will be funded in part by proceeds from Microsoft’s carbon fee - See more at: http://blogs.msdn.com/b/microsoft-green/archive/2013/11/04/microsoft-signing-long-term-deal-to-buy-wind-energy-in-texas.aspx#sthash.4l62oNbo.dpuf

eBay OKed for wholesale electricity sales

As customer-sited electric generation becomes increasingly economic, major companies outside the energy sector are entering electricity markets.  Federal regulators this month granted eBay Inc.'s request for authorization to sell electricity at wholesale.  What does this mean?

U.S. wholesale electricity markets are generally regulated by the Federal Energy Regulatory Commission.  Most sellers in those markets are regulated as public utilities - but in recent years, the category of "utilities" has expanded beyond the traditional vertically-integrated utility serving retail customers with electricity.  The growth in this sector has come largely from end-users of electricity who have developed on-site generation to meet their needs - and to sell excess power into wholesale markets.  Recent big-name entries into the wholesale electricity market include Google Inc. and Wal-Mart Stores Inc. - and now eBay.

On September 5, 2013, the Commission granted eBay market-based rate authority.  This approval enables eBay to sell electric energy, capacity, and other products.  As described in the Commission's order, eBay plans to own and operate a 6 megawatt fuel cell generation facility located at its data center in South Jordan, Utah.  In a June 21 filing, eBay described plans to install five natural gas-fueled "Bloom Box" units at the data center to provide power to run the facility. 

eBay's plans bear some resemblance to the fuel cell system Apple developed at its data center in Maiden, North Carolina.  Data centers consume significant amounts of energy, both for processing and for cooling.  In many cases, on-site generation projects offer data centers a way to cut costs while improving their reliability and their environmental footprint.

Maximizing the cost-effectiveness of a distributed generation project requires it to be sized appropriately for the load to be served.  In some applications, there may be little to no excess power available for sale at wholesale to the grid, while other on-site generation projects may be capable of exporting significant amounts of energy to the grid.  With its market-based rate authorization in hand, eBay stands ready to enter the wholesale market with any excess power its Utah fuel cells produce.

Plan for solar on U.S. public lands advances

The U.S. Department of the Interior has finalized its general assessment of the environmental impacts of developing solar electric generation on public lands in six western states.  Last Friday's issuance of a Programmatic Environmental Impact Statement (PEIS) will expedite the permitting of solar energy projects in designated solar energy zones on federal land.

A view of the back a solar panel on public land in the Utah desert.

Part of the Obama administration's plan to encourage utility-scale solar energy development on federal lands, the finalization of the record of decision for the PEIS established an initial set of 17 Solar Energy Zones (SEZs) in Arizona, California, Colorado, Nevada, New Mexico and  Utah.  (Refer to DOI's map to see the general location of the zones.)

These initial 17 zones cover about 285,000 acres of public lands, and were designated based on factors including environmental suitability and access to transmission lines.  The Interior Department projects that if fully built out, the designated zones could be home to up to 23,700 megawatts of solar energy, an amount sufficient to power about 7 million homes.

The approved solar plan also allows a case-by-case evaluation of solar projects on another 19 million acres in “variance” areas outside the designated zones.  At the same time, the plan excludes almost 79 million acres deemed "inappropriate for solar development based on currently available information."

Notably, the PEIS does not pre-approve any specific plan.  Each project proposed in the designated zones will still require its own environmental review and other permitting.  Nevertheless, the solar plan may facilitate significant development of solar energy projects on public lands in the western United States.

US Army solar engine project

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

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

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

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

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

NPS promotes greener national parks

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

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

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

The Green Parks Plan identifies nine strategic goals:

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

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

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

Proposed Long Canyon energy project

Last week the Federal Energy Regulatory Commission accepted for filing an application for a preliminary permit for a pumped storage project in the Utah desert.  In January, Utah Independent Power, Inc. filed for a preliminary permit.  The Long Canyon Pumped Storage Project would entail two dams to store water drawn from the Colorado River near Moab, Utah.  (Here's a topographic map of the general location.)

A water pipe buried in the desert soil in Arches National Park, near Moab, Utah.

Pumped storage projects are one way to store energy.  Electricity that is generated can be converted into potential energy stored in water by pumping it uphill.  That energy, or most of it, can be captured and converted back into electricity on command.

Utah Independent Power's application to FERC for a preliminary permit for the Long Canyon Pumped Storage Project (18-page PDF) provides some details on how the project might work.  Initially, water from the river would be pumped into the lower reservoir.  When electricity is abundant and low-priced, the project would consume electricity to pump water from the lower reservoir uphill to the upper reservoir.  When electricity is scarce or commands a high enough price, the project would release water downhill through turbines to produce up to 800 megawatts of hydroelectric energy.  In a typical pumped storage project, the same pumps used to send water uphill can be used as turbines when the water flows back down.  The owned of a pumped storage project seeks to earn profits by taking advantage of the difference between off-peak energy prices and the prices available during peak demand.

Now that the Commission has accepted the application for filing, the application is open for 60 days for public comment or a showing of interest in the site by a competing developer.  After that period, and after a technical and legal review of the application by Commission staff, the Commission may issue a preliminary permit to the applicant.  A preliminary permit does not authorize the permittee to actually construct anything; rather, it confers first priority of application for a license - what the Commission calls "guaranteed first-to-file status" - while the permittee studies the site and prepares to apply for a license, typically for a term of 3 years.

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.

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?

National park energy use and strategies

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 84.4 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.

April 26, 2011 - Ivanpah solar deals with tortoise impacts

Two weeks ago, I noted Google's investment in the 392 MW Ivanpah solar project in California's Mojave Desert, and how it benefited from $1.6 billion in Department of Energy loan guarantees.  Developer BrightSource Energy started construction on Phase I of the Ivanpah project in October 2010, with two subsequent phases slated for development shortly thereafter.  BrightSource's business plan also includes an initial public offering, which led the company to file an S-1 securities registration with the U.S. Securities and Exchange Commission.

Solar photovoltaic panels above Beaver Mountain ski area near Logan, Utah.

The Ivanpah project has now hit a speedbump in the form of a tortoise.  The desert tortoise (Gopherus agassizii) lives in the Mojave desert, including in the area where the Ivanpah project is proposed.  As a result, BrightSource has apparently stopped work on the construction of Ivanpah's second and third phases.

BrightSource noted in its S-1 filing that "in April 2011, the U.S. Bureau of Land Management, or BLM, advised us that it will require the issuance of a revised biological opinion by the U.S. Fish & Wildlife Service, or FWS, prior to providing permission to proceed with the construction of Ivanpah’s second and third phases".

The Fish and Wildlife Service is reportedly developing that opinion now, which should be finalized over the summer.

March 11, 2011 - powering data centers with renewable energy

What happens when you combine customer choice, voluntary renewable power markets, and electricity-hungry data center?

Data centers house computer systems for things like telecommunications and storage of large amounts of digital information.  I've written before about how much energy data centers can consume: in the case of the National Security Agency's Utah Data Center, estimates suggest up to 65 megawatts of electricity at any given time.  This demand for electricity can drive data centers to locate or relocate themselves in areas of lower power pricing.

Another possibility is for data centers to choose their electricity sources not based on pricing but on other characteristics, such as the sustainability of the power generated.  For example, IT services company Datapipe, Inc. recently chose to buy all its power for its US facilities from renewable sources.  This won them Leadership Club status in EPA's Green Power Partners program.  Datapipe buys almost 56,000,000 kilowatt-hours per year, all of which it now sources from renewable generation.  Assuming they run at an even electricity load 24 hours a day, 7 days a week, that's an average of 6.4 megawatts of demand.  While that's less than the Utah Data Center's anticipated consumption, it's impressive to see a consumer choosing to buy 100% renewable electricity.

February 14, 2011 - renewable energy and transmission needs

As more renewable energy projects are built around the nation, the increase in energy produced - as well as shifts in where that energy is produced - may drive the need for new transmission lines to connect green power to customers.  For example, in New England, these pressures are behind transmission projects like the Northern Pass and the Champlain-Hudson Power Express.  This kind of transmission development raises questions like who should pay for these lines, as well as whether the lines will provide any benefit to the people living in states they cross.

Utah is facing these same questions, thanks to the proposed $3 billion TransWest Express transmission line project.  If built, this 725-mile long 600 kilovolt DC transmission line would connect Sinclair, Wyoming to a substation near Boulder City, Nevada.  The line is designed to transmit energy from up to 3,000 MW of wind projects east of the Rocky Mountains to customers in southern California, Arizona, and Nevada.  Although 429 miles of the transmission line would cross Utah, the project as currently proposed would not include any offramps to connect Utah customers with that renewable power.

 

Utah does not have a renewable portfolio standard (RPS).  RPS programs require utilities to source certain amounts of the electricity they sell to customers from renewable power.  Utah does have a statutory renewable goal of 20% of adjusted retail sales by 2025, but utilities are required to pursue renewable energy only to the extent that it is "cost-effective" to do so.  California, Arizona, and Nevada - the states that will be served by the TransWest Express transmission line - do have RPS requirements, as do most other states in the nation.

How will Utah respond to the TransWest Express proposal?  Is there desire in the state to be able to buy the renewable power that will be winging its way westward through the transmission line?  Can the state obtain any benefits in exchange for permitting the line to cross its lands?