FERC Summer 2016 energy market and reliability report

Federal energy regulatory staff have presented their 2016 Summer Seasonal Assessment to the Federal Energy Regulatory Commission.  The "Summer 2016 Energy Market and Reliability Assessment" presents an summer outlook by FERC's Office of Electric Reliability and Office of Enforcement on electricity and natural gas markets and reliability issues.

Highlights include:

• "low natural gas prices that have resulted from robust production and near record levels of natural gas in storage"
• electric system reserve margins are expected to be adequate this summer, though tighter in Texas
• total U.S. load forecast, when weather-adjusted, is essentially unchanged in recent years, largely due to little to no load growth in commercial and residential sectors
• the total generating capacity in the U.S. has decreased by approximately 2 percent since last summer, primarily due to coal retirements. According to the report, "The factors that prompted these closures include increased competition from natural gas, environmental regulations and an average fleet age that exceeded 50 years old."
• Over 18 gigawatts of new generating capacity will be installed nationwide through the summer, with a majority of these capacity additions coming from renewables such as wind and solar, plus the first new U.S. nuclear unit in over 20 years.
• Organized markets are attempting to manage the growing impacts of renewable generation.
• FERC staff expects natural gas fired generation to remain robust; natural gas fired generation has surpassed coal plant output since July 2015. Meanwhile coal stockpiles are growing due to a decrease in coal generation.
• Natural gas future prices have fallen since last year, though the Boston region's price drop is not significant.  Basis swaps -- financial instruments that represent the natural gas price differential between a specific point and the Henry Hub -- for Boston are priced higher than last summer, "suggesting expectations for greater congestion due to above-normal temperatures and a reduction in capacity along the Algonquin pipeline because of planned maintenance to tie in the Algonquin Incremental Market (AIM) expansion project this summer."

Texas small hydro project loses exemption

What happens to a proposed hydroelectric project takes longer than anticipated to be built, due to difficulties with project financing and severe flooding?  As the developer of a proposed project in Texas recently found out, federal regulators can be lenient up to a point -- but under some circumstances the developer can lose its federal authorization to develop and operate the project.

The A.H. Smith Dam on the San Marcos River in Martindale, Texas was originally constructed in about 1894 to provide mechanical power a cotton gin; later, electric generation was installed, but power production ceased in the 1940s when low wholesale energy prices made operation uneconomic.  Modern hydropower facilities rated at 150 kilowatts were installed in 1984, but were ultimately abandoned.

In 2005, developer Hydraco Power, Inc. applied to the Federal Energy Regulatory Commission for an exemption from the licensing requirements of Part I of the Federal Power Act for its proposed A.H. Smith Dam Project.  Hydraco's project included refurbishing and restoring the operation of the existing turbine located at the dam's powerhouse, installing a new buried transmission line and a water surface elevation gate in the headpond.

On June 2, 2006, the Commission granted Hydraco an exemption for the project.  As a standard condition of exemptions, the Commission retained the right to revoke the exemption if any term or condition was violated.  Among the terms was a requirement that Hydraco file within 120 days a
plan and schedule to install the new transmission line and restore the powerhouse, turbine, and trash racks to operating condition, as well as notice that the Commission could terminate the exemption if actual construction of any proposed or required facility had not begun within two years or had not been completed within four years of the date of issuance of the exemption.

Over the next 8 years, Hydraco filed a series of construction plans and schedules, but never completed the project despite obtaining repeated extensions of key deadlines.  After multiple prompts by Commission staff to file a revised plan and schedule for restoring project operation or an application to surrender the exemption, the Commission noted that Hydraco either failed to respond or responded by stating that it could not estimate a schedule for restoring project operation because project construction, including major component repairs, was on hold due to lack of funds.

After the Commission issued a public notice in August 2014 stating its intent to terminate the project exemption "due to Hydraco’s longstanding violation of exemption Article 10 and its failure to provide a timeframe for restoring project generation", on November 20, 2014, the Commission issued an Order Terminating Exemption. That order found that "Hydraco has only performed minimal work at the project since obtaining its exemption in 2006 and that it lacks the funding to proceed with the necessary component repairs, including construction of the powerhouse interior and generating unit."

Hydraco filed a request for rehearing of the Order Terminating Exemption.  On rehearing, Hydraco asserted that it had reached a financing agreement with a new investor and, consequently, it is ready to perform the work needed to comply with its exemption. Hydraco also objected to the findings that project construction was at a standstill and that Hydraco intended to abandon the project, noting that the Commission should excuse construction delays caused by severe flooding.

Last week, the Commission issued an Order Denying Rehearing in the case.  It first noted that Hydraco had not demonstrated that it now has the money needed to bring the project on line.  Not only did Hydraco not show evidence of a final financing agreement, but the documents showed a source of only half of the funding needed for project restoration.  Second, the Commission noted that Hydraco's recent activities -- regularly inspecting the dam and removing debris from its spillway, trashracks, and grates, securing the site against vandalism and installing lighting, and repairing damage caused by a flood -- are "either maintenance or repair, not project development."  Finally, the Commission articulated its "doctrine of implied surrender", which it applies where the entity responsible for the project has, by action or inaction, clearly indicated its intent to abandon the project, but has not filed a surrender application.

With the exemption terminated and Hydraco's request for rehearing denied, the A.H. Smith Dam project faces an uncertain future.  On the one hand, the site presumably still offers many of the same values that Hydraco hoped to capture -- use an existing dam, with existing generation facilities, to generate renewable electricity.  However, the loss of the FERC exemption means that Hydraco (or any other developer) will have to start the federal hydropower process over if it hopes to redevelop the dam as a hydroelectric generating site.

The case of the A.H. Smith Dam project illustrates a number of themes: interest in restoring existing hydropower infrastructure to generate renewable energy with relatively less environmental impact than newly-built dams, the challenge of securing financing for small hydropower projects -- and perhaps most importantly the value of compliance with FERC hydropower rules.

Southwest Power Pool to expand

The Federal Energy Regulatory Commission has largely accepted a proposal to expand the geographic footprint of the Southwest Power Pool, a regional power market that will soon include a significant portion of the Upper Great Plains.

Southwest Power Pool, Inc. (SPP) was founded in 1941 by a coalition of regional power companies interested in keeping an Arkansas aluminum factory supplied with power to meet critical defense needs.  Since 2004, SPP has been recognized by the FERC as a Regional Transmission Organization or RTO.  Today, SPP organizes and operates parts of the electric power grid in nine states: Arkansas, Kansas, Louisiana, Mississippi, Missouri, Nebraska, New Mexico, Oklahoma, and Texas. 

On September 11, 2014, pursuant to section 205 of the Federal Power Act (FPA), SPP submitted to the FERC proposed revisions to its governing documents to facilitate the decision of three major transmission owners of the so-called Integrated System in the Upper Great Plains to join SPP.  The three proposed member-owners are:

• Western Area Power Administration – Upper Great Plains Region: one of four regions of the United States Department of Energy's Western Area Power Administration. Western is a federal power marketing agency that markets federal power and owns and operates transmission facilities through 15 western and central states, encompassing a geographic area of 1.3 million square miles. Western ’s primary mission is to market federal power and transmission resources constructed with Congressional authorization. The federal generation marketed by Western is generated by power plants that were constructed by federal generating agencies, principally the Department of the Interior’s Bureau of Reclamation and the U.S. Army Corps of Engineers. In the Upper Great Plains Region , or Western - UGP, Western owns an extensive system of high - voltage transmission facilities and markets federally generated hydroelectric power in the Pick - Sloan Missouri - Basin Program - Eastern Division of Western.
• Basin Electric Power Cooperative: serves 2.8 million customers in territories covering approximately 540,000 square miles using nearly 2,100 miles of transmission lines and 70 switch yards
• Heartland Consumers Power District: a public corporation and political subdivision of the State of South Dakota. It provides wholesale power to 28 municipalities in eastern South Dakota, southwest Minnesota, and northwest Iowa, to six South Dakota state agencies, and to one electric cooperative in South Dakota.

These entities proposed to join SPP as transmission owning members, to place their respective transmission facilities under the functional control of SPP, and to begin taking transmission service under the SPP Tariff.  Their stated motivation was increasing market size and thus opportunities for both consumers and producers of energy.

By order dated November 10, 2014, the FERC accepted SPP's proposal.  Together, these new SPP members provide the backbone of the bulk electric transmission system across seven states in the Upper Great Plains region consisting of approximately 9,500 miles of transmission lines rated 115 kV through 345 kV.  The FERC order directed SPP to take certain interim steps, and SPP has announced plans to integrate the three new utilities by October 2015.

Google invests in solar energy projects

Google has announced an investment in six solar photovoltaic projects to its portfolio.  The projects, located in California and Arizona, have a combined electric generating capacity of 106 megawatts.  This deal illustrates the trend of renewable energy investments by data centers and other tech companies.

The projects are under development by Recurrent Energy.  Five are located in Southern California, while the sixth is in Arizona.  Google and investment firm KKR invested $400 million in the projects; Google's share is reportedly $80 million.  The partners will sell the power produced by the facilities to local utilities including Southern California Edison.

Google announced that this represents its fourteenth investment in renewable energy since 2011.  In 2010, the Federal Energy Regulatory Commission granted market-based rate authority to Google subsidiary Google Energy LLC, enabling it to sell power at wholesale.  Google has since entered into long-term agreements to purchase power from wind farms and other renewable generators.

Other tech companies are pursuing similar strategies.  Earlier this month Microsoft announced a deal to purchase energy produced by a Texas wind farm for its data center in San Antonio.  In September, eBay received market-based rate authorization from the Federal Energy Regulatory Commission, allowing it to sell surplus power from its generators to the grid.

For consumers like Google with significant demand for power, developing on-site electric generation or entering into a long-term power purchase agreement can be cost-effective, either by reducing the cost of energy or by reducing its exposure to price volatility.  Investments in renewable energy can also position companies for improved sustainability and "green" their public images.  For these reasons, the trend of tech company investment in renewable energy infrastructure will likely continue for the foreseeable future.

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

FERC report shows investment in natural gas

This week the Federal Energy Regulatory Commission issued its monthly energy infrastructure update covering May 2013.  The report details highlights in expansions of energy assets, ranging from natural gas pipelines to electric generation and transmission facilities.  It provides a monthly snapshot of recent activity, and can be used to spot trends in domestic energy development.  The current report illustrates increased investment in natural gas-related infrastructure, ranging from proposed new liquefied natural gas export terminals to newly installed natural gas-fired power plants.

The iconic U.S Capitol dome, where policies are made that shape energy investment.

Natural gas exports poised for growth.  Last month two facilities to liquefy natural gas for export advanced through the FERC regulatory process:

• Jordan Cove Energy requested authorization to construct and operate four liquefaction trains and storage facilities at a proposed export terminal in Coos Bay, Oregon.  If authorized and built, the project could export up to 900 MMcf per day of liquefied natural gas (LNG).  This gas would likely be destined for Asian markets.
• Golden Pass Products proposed a larger project in Texas.  Along with Golden Pass Pipeline, Golden Pass Products commenced the FERC prefiling process to construct and operate a 2,100 MMcf per day liquefaction facility for export at an existing import terminal located in Sabine Pass, Texas.  The Golden Pass project also includes proposed modification of an existing pipeline system to enable 2,500 MMcf per day of bidirectional capacity to the proposed export terminal.

These projects demonstrate increased interest in exporting natural gas to overseas markets.  The boom in domestic shale gas production has led to low natural gas prices in the U.S.  Domestic pricing is roughly one-third of the price that exporters can get by sending LNG to Europe or Asia.  Whether and to what extent the U.S. will allow exports remains to be seen, but in the interim, developers are scrambling to secure permits for export. 

New electric generation, mostly fueled by natural gas.  Last month a total of 33 new electric generation units came online.  Nearly three-quarters of the newly installed capacity is fueled by natural gas, adding 2,529 MW of new natural gas-fired electric generating capacity.  The new gas projects vary widely in scope:

• The largest, Mitsubishi Corporation’s 850 MW CPV Sentinel Energy Expansion in Riverside County, consists of eight 106.25 MW units.  Mitsubishi’s generation is sold to Southern California Edison under a long-term contract.
• In the middle, Procter & Gamble Company developed a 64 MW natural gas fired project to produce power for its paper products manufacturing facility in Wyoming County, Pennsylvania.
• At the opposite end of the scale, two landfill gas-fired projects came online in New York.  Wehran Energy Corp.’s 4.5 MW Brookhaven facility consists of three 1.5 MW Caterpillar Inc. generators.  The Brookhaven project was also joined by a 1.6 MW expansion of Waste Management Inc.’s Oneida-Herkimer project.

These projects illustrate the diversity of new natural gas fired projects being developed this spring.  The abundance of low-cost natural gas drives interest in the utility scale gas projects, while a desire to capture landfill-produced methane and put it to use as biogas supports the smaller projects.  As a result, natural gas’s share of total installed operating generating capacity grew slightly to 42.56%.  Despite a resurgence of coal as a fuel for electric generation, coal remains in second place in the installed capacity race, representing 28.9% of total U.S. installed capacity.

While each monthly energy infrastructure update represents only one data point, in the aggregate, they paint a picture of the direction of U.S. energy infrastructure development.  Natural gas is squarely in the center of this picture.  Based on consensus projections that natural gaswill remain the most cost effective fuel for decades to come, increased expansion of natural related infrastructure is likely to continue for some time.

Keystone XL pipeline supplemental Environmental Impact Statement

The proposed Keystone XL pipeline took a step forward this month, as the U.S. State Department released its evaluation of the project's potential environmental impacts.  The draft Supplemental Environmental Impact Statement (EIS) released on March 1, 2013 documents the State Department's analysis of the pipeline's impacts to environmental resources based on the currently proposed route.  The EIS is still preliminary, and is now subject to public comment.  Moreover, even a final EIS would not reach any conclusion as to whether the pipeline serves the national public interest, and the project would still need a presidential permit to ship oil across the US-Canadian border.  Nevertheless the draft EIS does suggest that any environmental impacts from the pipeline would be relatively minor.

The Keystone XL project is a proposed extension of an existing crude oil pipeline.  The $7 billion project would run from the Canadian province of Alberta to Texas, delivering Canadian crude to refineries on the U.S. Gulf Coast.  The oil shipped on the pipeline would likely include so-called synthetic crude derived from Canada's oil sands or "tar sands" resources.

The draft EIS (available from the State Department's website) makes a series of findings about the project's potential environmental impacts, ranging from direct impacts along the pipeline's route to indirect impacts like further development of the Alberta oil sands.  As the State Department found in its earlier environmental review, the supplemental EIS found that the pipeline would not have significant impacts to any resources along the proposed project route.

Notably, the draft EIS found that Keystone XL would not be likely to substantially increase the rate of development of the oil sands, nor would it likely increase the volume of crude oil refined in the Gulf Coast.  For example, the draft found that denial of the pipeline's presidential permit would not mean a reduction in oil production in Western Canada or from the Bakken formation; rather, oil producers would resort to other transportation modes such as pipelines to British Columbia or even rail shipment of crude.  For similar reasons, the draft EIS found that the Keystone XL pipeline would not substantively change global greenhouse gas emissions.

Next steps for the Keystone XL project include a 45-day public comment period, after which the State Department will issue a final EIS.  Later this year, the State Department is expected to issue a so-called national interest determination, considering factors including foreign policy, economics, environmental concerns, and national security. This determination will involve consultation with other agencies, including the U.S. Departments of Defense, Justice, Interior, Commerce, Transportation, Energy, Homeland Security and the Environmental Protection Agency.  The final decision whether to allow the pipeline falls to President Obama.

Maine offshore wind projects win federal grants

The U.S. Department of Energy has announced an award of funding to seven offshore wind Advanced Technology Demonstration projects totaling $168 million over six years.  These projects are designed to achieve large cost reductions over existing offshore wind technologies and develop viable and reliable options for the United States.  Waters off Maine will be home to two of the projects:

• Statoil North America of Stamford, Connecticut plans to deploy four 3-megawatt wind turbines on floating spar buoy structures in the Gulf of Maine off Boothbay Harbor at a water depth of approximately 460 feet. These spar buoys will be assembled in harbor to reduce installation costs and then towed to the installation site to access the Gulf of Maine's extensive deep water offshore wind resources.
  
  
• The University of Maine, based in Orono, plans to install a pilot floating offshore wind farm off Monhegan Island.  This project will feature two 6-megawatt direct-drive turbines on concrete semi-submersible foundations. These concrete foundations could result in improvements in commercial-scale production and provide offshore wind projects with a cost-effective alternative to traditional steel foundations.
  

Each project will receive up to $4 million to complete the engineering, site evaluation, and planning phase of their project.  Five other projects were also selected for this first phase:

• Baryonyx Corporation, based in Austin, Texas, plans to install three 6-megawatt direct-drive wind turbines in state waters near Port Isabel, Texas. The project will demonstrate an advanced jacket foundation design and integrate lessons learned from the oil and gas sector on hurricane-resistant facility design, installation procedures, and personnel safety.
  
  
• Fishermen's Atlantic City Windfarm plans to install up to six direct-drive turbines in state waters three miles off the coast of Atlantic City, New Jersey. The project will result in an advanced bottom-mounted foundation design and innovative installation procedures to mitigate potential environmental impacts. The company expects this project to achieve commercial operation by 2015.
  
  
• Lake Erie Development Corporation, a regional public-private partnership based in Cleveland, Ohio, plans to install nine 3-megawatt direct-drive wind turbines on "ice breaker" monopile foundations designed to reduce ice loading. The project will be installed on Lake Erie, seven miles off the coast of Cleveland.
  
  
• Seattle, Washington-based Principle Power plans to install five semi-submersible floating foundations outfitted with 6-megawatt direct-drive offshore wind turbines. The project will be sited in deep water 10 to 15 miles from Coos Bay, Oregon. Principle Power's semi-submersible foundations will be assembled near the project site in Oregon, helping to reduce installation costs. 


• Dominion Virginia Power of Richmond plans to design, develop, and install two 6-megawatt direct-drive turbines off the coast of Virginia Beach on innovative "twisted jacket" foundations that offer the strength of traditional jacket or space-frame structures but use substantially less steel.
  

After the first phase, the DOE Wind Program will select up to three of these projects to advance the follow-on design, fabrication, and deployment phases to achieve commercial operation by 2017. These projects will be eligible for up to $47 million over four years, subject to congressional appropriations.

Electricity and natural gas market links

Concerns over the increasing interdependence of natural gas and electricity markets in the United States have prompted federal regulators to schedule a series of technical conferences on the subject for next month.

In recent years, natural gas has increased its share of the energy mix used to generate electricity.  Usage of coal, historically the dominant fuel used to generate electricity, is declining, while natural gas pricing is historically low.  This shift to increased reliance on natural gas is also driven in part by the growth of intermittent renewable energy resources like wind which may need natural gas to back them up when the wind isn't blowing.

At the same time, investigations into the blackouts and reliability problems like those affecting Texas and the Southwest in February of 2011 suggest that a lack of coordination between the electricity and gas industries may be partly responsible for the outages.

On February 3, 2012, Federal Energy Regulatory Commission Commissioner Philip Moeller issued a letter posing a series of questions concerning gas-electric interdependence.  His questions included what role the FERC should play in overseeing better coordination between the two industries, what regional differences might affect this coordination, and differences in how electricity and gas are traded in their respective markets.

In response to Commissioner Moeller's letter, a variety of stakeholders submitted comments.  Many commenters suggested that significant regional differences exist in both how markets operate and how their coordination could be improved.

As a result, the FERC has scheduled a series of regionally-oriented technical conferences for August:

• Central (generally the areas controlled by Midwest Independent Transmission System Operator Inc. (MISO), Southwest Power Pool, Inc. (SPP) and Electric Reliability Council of Texas (ERCOT)), to be held August 6, 2012, in St. Louis, MO
• Northeast (generally the area controlled by ISO New England, Inc.), to be held August 20, 2012, in Boston, MA
• Southeast (generally the areas controlled by Southern Company, Duke and Progress Energy, TVA, as well as other areas south of PJM Interconnection, L.L.C. (PJM) and East of SPP and ERCOT), to be held August 23, 2012, at FERC headquarters in Washington, DC
• West (generally the Western Interconnection), to be held August 28, 2012, in Portland, OR
• Mid-Atlantic (generally the areas controlled by New York Independent System Operator Inc. (NYISO), PJM and related areas), to be held August 30, 2012, at FERC headquarters in Washington, DC

FERC anticipates that each conference will be organized as a roundtable discussion regarding the sharing of information and communications, scheduling, market structures and rules, and reliability concerns.  The Commission has encouraged those interested in attending a conference to register by July 19, 2012.

Energy projects installed in May 2012

A report released this week by federal energy regulators documents the composition of additions to the U.S.'s portfolio of electricity resources.  The May 2012 Energy Infrastructure Update released by the Federal Energy Regulatory Commission's Office of Energy Projects provides a summary of newly-built and expanded electric generation facilities.  This snapshot of what happened in May 2012 illustrates trends in the electric industry, including a focus on renewable energy and natural gas in project development.

According to the report, 561 megawatts of new or expanded electric generation capacity came online in May 2012.  Of this new installed capacity, the largest share -- 228 MW -- came from wind.  Most of this new capacity comes from a single project, E.ON Climate & Renewables North America, LLC’s Magic Valley Wind Farm I in Texas.  The Magic Valley I project is comprised of 112 Vestas V100 1.8-MW turbines, for a total nameplate capacity of 202 MW.

The second-largest resource class of new generation capacity in May 2012 comes from biomass, with 166 MW of new biomass capacity installed in May.  As with wind, Texas hosts the bulk of this new  capacity.  The largest new biomass project is a 100 MW wood-fired plant built in Nacogdoches County, Texas, by Southern Company, financed in part through a long-term power purchase agreement with Austin Energy to buy the power.

Solar-powered generation provides the third-largest class of capacity newly installed in May 2012.  Eleven new projects came online in May, totaling 149 MW of new capacity.  The largest of these is Enbridge Inc.’s 50 MW Silver State North Solar Project.  This project, located in Clark County, Nevada, is the first utility-scale solar facility built on federal land managed by the Bureau of Land Management.  Its output will be sold to NV Energy under a long-term PPA.

Together, these three renewable resources -- wind, biomass, and solar -- represent 543 out of the 561 MW installed in May 2012. Other fuels like coal and natural gas played a relatively minor role in terms of new capacity installed in May.  Nevertheless, the year-to-date cumulative data shows that natural gas powers the largest share of projects installed in 2012 -- 2,811 MW out of the 6,225 MW installed so far in 2012.

FERC releases report on demand response

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

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

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

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

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

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

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

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

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

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

February 17, 2011 - Texas blackout aftermath

When Texas experienced rolling blackouts earlier this month due to severe weather and disruptions to generation and the electric grid, over one million customers lost power intermittently.  Imposing rolling blackouts on customers is an extraordinary measure rarely seen in U.S. power markets.  Typically, utilities and regional transmission organizations will do everything they can to ensure adequate electric supply for all customers.  So what went wrong in Texas?

That question has been on the minds of electricity customers, and is now drawing increased attention by regulatory agencies.  On February 7, less than a week after these outages, the nation’s electric reliability organization North American Electric Reliability Corporation (NERC) announced a joint investigation in coordination with Texas Reliability Entity, Inc. and the Western Electricity Coordinating Council, to understand exactly what happened and what can be done in the future to prevent such electricity curtailment.  In its announcement of its investigation, NERC noted that it will examine whether the recent shift towards greater reliance on natural gas to produce electricity played any role in the outages.

Now, the Federal Energy Regulatory Commission (FERC) has initiated a staff inquiry into the outages and the restrictions of natural gas and electricity service in Texas and other western states.  This inquiry, docketed as Docket No. AD11-9-000, focused on disruption to the bulk of power system in Texas and Arizona as well as disruptions to natural gas delivery in Texas, in Mexico and elsewhere in the southwest.  Notably, FERC’s order opening this investigation states that this will not be an enforcement investigation; rather, this investigation will identify the problems and gather facts, leaving the decision on whether to initiate enforcement proceedings to a later date.  FERC has designated a staff task force to conduct this inquiry.

Meanwhile, Texas’ main electric grid operator, the Electric Reliability Council of Texas (ERCOT) is taking a look at its own internal procedure with an eye to improving its response to situations such as this.  Over the course of the day on February 2, 82 power plants with the combined generating capacity of 11,000 megawatts went offline.  During the peak of the outage, 80,000 megawatts was offline.  Of these, 59% were powered by natural gas, 40% by coal, and 1% by wind.

We shall soon see what these inquiries find.

February 3, 2011 - ERCOT rolling blackouts over?

Following on yesterday's report of rolling blackouts in Texas: grid operator ERCOT has reported that the need for intermittent power cuts may have passed, although ERCOT noted that scarcity of available generation might again lead to the need for blackouts.  As the storm moves away and life gets back to normal, we're seeing some of the impacts of the blackouts.  For example, the Houston Chronicle reports that the Houston fire department responded to 30 elevator rescues yesterday - 10 to 15 times as many as on an average day.  Rolling blackouts are unpredictable; even if you know the grid operator is imposing them, you might not know exactly when they'll strike.  ERCOT and utilities tried to avoid cutting power to key elements of social infrastructure like hospitals, but anyone who got stuck in an elevator when their building lost power probably didn't enjoy the experience.

ERCOT continues to ask consumers to reduce their consumption of electricity, particularly during times of peak demand.

February 2, 2011 - weather leads ERCOT to rolling blackouts

What happens when bad weather strikes the power grid?  Depending on the storm, and the region, some customers may lose power if distribution lines are damaged.  More serious cases, like when key generators are tripped offline, may lead to more serious consequences.

Groundhog Day 2011 in Texas provides an example of the more serious consequences: power prices rising to 40 times their previous level, coupled with rolling blackouts.  The Electric Reliability Council of Texas, or ERCOT, operates the electric grid and manages the deregulated market for 75 percent of the state: about 22 million customers in areas including Houston, Dallas, Fort Worth, San Antonio, Austin, Corpus Christi, Abilene and the Rio Grande Valley.

Thanks to the weather, apparently there just isn't enough power to go around.  Reports indicate that ERCOT has imposed rolling blackouts after multiple power plants were disabled by a major ice storm.   Rolling blackouts are an extraordinary measure, seen more often in other countries than in the U.S.  When the utility cuts your power, unless you're connected to distributed generation or storage, your lights will go dark.

Beyond the rolling blackouts, the price of energy may lead to other consumer impacts.  Reuters reports that hourly energy prices in ERCOT rose from $50 per megawatt-hour to $2,000 per megawatt-hour, a forty-fold increase.  (Although individual residential ratepayers may not feel that price spike directly, it would translate into paying $2.00 per kilowatt-hour if they did - and large commercial and industrial ratepayers who buy power at wholesale in the market are exposed to these prices directly.)  Sounds like a good time for demand response!

2/22/10

As expected, the federal Surface Transportation Board has received the Montreal, Maine & Atlantic Railway's notice of intent to abandon 233 miles of track in Maine, from Madawaska to Millinocket. Even though this line serves about 20 industrial freight customers, the Railway says it has been losing $4 million to $5 million a year through operating the lines because freight revenue has fallen. The typical freight shipped on the line includes lumber, plywood, logs and wood chips have fallen, all of which are in low demand given the slump in the housing market. If the rail is abandoned, it could cost 750 jobs as increased transportation costs would lead the region's manufacturers to scale back production.

Iran is choosing sites for uranium enrichment plants, claiming it wants civil nuclear power, not weapons.

Distributed generation gets a policy boost, with a finding that widely-adopted rooftop solar might be easier to develop than utility-scale solar arrays, due to the challenges of siting larger projects.

Much buzz today over Bloom boxes, distributed fuel cell arrays about to be announced. Bloom Energy, which raised $400 million in venture capital, holds a press conference on Wednesday at which it is expected to unveil its products. Interestingly, Google already has a 400 kW array in beta-testing operation.

Speaking of Google, FERC granted Google's market-based rate authorization. As someone who works with FERC's market-based rate structure, having filed a number of petitions myself, it is interesting to me to see how the media reports this: as enabling Google to purchase low-cost power. Surely we all want to purchase low-cost power -- what would it take to enable us all to purchase power at market-based rates? Most people would qualify -- no market power, etc.

Some question whether Energy Star really means much for appliance efficiency.

The administration's pro-nuclear news of last week continues to resonate, as Texas evaluates whether proposed new reactors there will receive similar government support.

Six Maine school and university oil-to-wood heating projects will receive more than $3.2 million in federal Recovery Act funds managed by the Maine Forest Service. The Presque Isle office of the University of Maine Cooperative Extension was awarded $16,575 for installation of a pellet boiler to replace the current oil boiler, displacing 1,850 gallons of fuel oil. (The existing boiler is around 10 years old -- are we incenting inefficient replacement of newer equipment while older, less efficient facilities remain?) Overall this project costs an estimated $40,169, with the remainder of the project funded by the Maine Economic Improvement Fund. Regional School Unit 29 in Houlton was awarded $750,000 for conversion of an oil boiler to a wood chip boiler at Houlton High School, displacing 65,000 gallons of the 85,000 gallons of fuel oil used annually by the district. The district uses about 85,000 gallons of oil a year, according to the superintendent. Here, the district will keep its oil boiler, but will rely on the new boiler for heating. Other winners are Oxford Hills High School, the Greenville School Department, Phillips Middle School and Poland Middle-High School. Maine Forest Service Director Alec Giffen said the six projects collectively “will annually avoid the burning of almost 263,000 gallons of oil, recirculate $600,000 in fuel dollars in the Maine economy, and avoid more than 5 million pounds of emissions from fossil fuels.”

More Maine stimulus: EECBG grants to central Maine communities.

2/5/10

Following up on the old elm tree "Herbie" that recently died in Yarmouth, Maine: turns out Herbie was 217 years old. It will be interesting to see what Herbie's growth rings show about how the climate in Maine has changed since 1793.

Here's a logic puzzle for you. Maine : "Saudi Arabia of wind" :: Texas : ________? How about "net loser of jobs in a clean energy economy"? A study by Navigant Consulting commissioned by the renewable-energy group RES Alliance for Jobs, concludes that a federal renewable energy standard of 25% renewable by 2025 would lead to 274,000 new jobs nationwide -- but that under current state policies on renewable energy, Texas would lose jobs while other states like California would be the big winners.

The Obama administration is pushing biofuels. The administration has renewed its commitment to getting the country to produce (and use) 36 billion gallons of biofuels by 2022, a goal originally set by Congress in 2007.