In May, PJM Interconnection announced that it had attracted a record amount of new generation at its recent annual capacity auction, which ensures that electricity supply will meet demand for the period June 1, 2016 through May 31, 2017.  The auction procured 5,463 megawatts (MW) of new generation, thus breaking last year’s record amount of 5,346 MW.  In addition, the auction obtained a record amount of imported power from the Midcontinent ISO (the new name for MISO, reflecting the grid operator’s southward expansion), more than doubling last year’s total. All in all, the auction procured 169,160 MW, resulting in a reserve margin (a cushion for unforeseen events) of 21.1%, or 5.5% above the target.

PJM holds this capacity auction – also referred to as the Reliabity Pricing Model (RPM) – every May in order to obtain sufficient electricity, plus a reserve margin to meet expected demand for power 3 years in the future in PJM’s territory. PJM provides its estimate for peak power use to the bidders who then bid their existing and new power plants as well as energy efficiency and DR resources. Their bid prices are based on the costs to have those resources available for a particular delivery year. The price bid by the final resource that meets PJM’s target establishes the price paid – the clearing price – to all resources in that zone.

Most noteworthy, this time, was PJM’s announcement that the level of demand response (DR) procured in the auction had dropped by about 2,400 MW, after years of continued growth at every auction.  The auction cleared 12,408 MW of DR.  “Limited DR,” which can only be dispatched 10 times a summer for up to 6 hours each time, represented the overwhelming majority (9,800 MW) of the demand-side resource.

Shortfalls Possible

The main reason for the DR procurement decline was considerably lower capacity prices in most of PJM’s territory this year.  For example, the MAAC region, which covers 10 utilities along the Atlantic seaboard, cleared a price of $119.13 per MW-day, a drop from $167.46 per MW-day in 2012.  FirstEnergy, in northern Ohio, and western Pennsylvania’s PennPower cleared a price of just $59.37 per MW-day, compared to $136 per MW-day last year.

According to PJM’s Senior VP of Markets, Andrew Ott, prices dropped simply because supplies were up while demand was flat.  Competition from new natural gas supplies, increased imports from other regions, and less demand for electricity due to a sluggish economy have put pressure on capacity prices.  Another factor affecting the demand for DR has been the higher procurement costs for aggregators, as they look to recruit new potential and often hard-to-reach customers to participate in their capacity programs.

Although the supply of power and reserve margins are good enough to meet the demand for electricity in PJM’s territory and most other regions of the United States this summer, a few areas in the country could be facing severe shortages that will drive the need for DR.  ERCOT in Texas, for example, is dealing with tight reserves with a margin that is 0.85% below its target.  If the state experiences another extreme heat wave like the summer of 2011, ERCOT would most likely face a challenge to meet its peak demand.  Thus, the grid operator is planning to expand its DR programs to increase the current 1,700 MW of DR.  In Texas, DR is seen as the first line of defense to beat the heat.

According to Oklahoma Gas & Electric’s System Watch web portal, more than 140,000 of its roughly 800,000 customers lost power during the second of two Oklahoma supercell tornados on May 31.

Everyone wonders what is going on in the cockpit when the plane is stuck on the tarmac.  In the modernized utility distribution control center, the operators have complete and current situational awareness of tens to hundreds of distribution circuits (OG&E has 1,100 circuits in its service territory), and sometimes more than a million meters.  Like a pilot in the cockpit, grid operators will have stackable monitors, color coded visualization on a GIS-enhanced interface, and the capability to quickly zoom in on alarms and provide intel to assessor, restoration crew etc.  Several such smart grid functions will have been used and useful in the overall effort of scouting, repairing, and managing outages in Oklahoma over the last 2 weeks.

On April 27, 2011, the resilience of Alabama Power Co. (APC) was tested in the most severe weather incident in the state’s history.  The outbreak of tornados resulted in 239 deaths.  Roughly half of Alabama Power’s 1.4 million customers were without power after more than 3,000 distribution transformers and twice as many poles were downed.  Eight distribution substations were either damaged or destroyed and 400 transmission structures were broken.  Yet, it took only 7 days for the utility to restore power.

The Next Generation

More than 10,000 mutual assistance resources were utilized, meaning restoration crews came from other states to help.  The company took a decentralized and mobile command approach; it used 11 staging areas, each equipped with a distribution management system (DMS) to manage remote switching and other operational control.  During less severe storms, APC operators can turn on an autopilot function (known as fault location, isolation, and service restoration, or FLISR) in the DMS to speed up service restoration, saving thousands of customers from sustained outages every year.  The smart utility’s goal is to minimize customer impacts by reducing restoration time when major events occur.  Utilities are looking to information technology / operational technology (IT/OT) integration and increased mobility to assist with outages.

In the event of outages, utilities rely on operational systems to notify customers of causes and estimated restoration times.  Next-generation DMS will be integrated with outage management to provide additional inputs for visualization and decision support to better address impacted areas.

Advanced workforce management (WFM) solutions that enable utilities to forecast, schedule, dispatch, and monitor progress of outage crew have gained increased interest.  WFM is carried out with the assistance of outage management tools that analyze outage reports to determine the scope of outages and the likely location of problems.  An outage management system (OMS) or a DMS compiles information on the times and locations of customer calls, smart meter outage notifications, and fault data from substations and monitoring devices on feeder lines.

Some utilities are reporting that the integration of advanced metering infrastructure (AMI) has given them the capability to reduce outage time by being able to confirm if meters have power or not.  AMI plays out in two different stages of restoration:

• After performing restoration work in a given area, service at all the meters can be confirmed quickly and remotely before crews move onto the next area.
• Individual complaints are followed up on in the wrap-up phase of a large storm restoration effort.

Traditionally there are always a lot of single customer outages that end up being “OK on arrival”, meaning a technician was dispatched with a ticket to restore power only to find out power has already been restored.  By confirming power has been restored via AMI and backing that up with a phone call to the customers, hundreds of truck rolls are saved in large storm events.

Demand-side management must become a significant element of the European energy market if the EU’s ambition to build a low-carbon economy is to be realized.  The latest survey of European smart grid projects by the European Commission’s Joint Research Centre (JRC) points out the importance of this requirement.  Smart Grid Projects in Europe: Lessons Learned and Current Developments (2012 update), a follow-up to a similar study carried out in 2011, notes that a majority of the 281 projects covered focus on “distributed ICT architectures for coordinating distributed resources and providing demand and supply flexibility.”

One of the latest projects to join the roster of demand-side management pilots is the Danish city of Kalundborg.  The fact that Denmark already obtains 30% of its electricity from wind power – and targets 50% by 2020 – is making such projects an increasingly urgent requirement for the country.

Symbiotic System

Kalundborg has a population of around 16,000 within a local kommune (or municipality) of the same name extending to 50,000 people.  Its relatively small size belies the fact that it is the second-largest industrial region in Denmark after Copenhagen.  It is also notable for its long established cross-industry program, Kalundborg Symbiosis.  This program has evolved over several decades as an integrated system for waste recycling within the local industrial system.  Residual products from one industry, such as steam, dust, gases, heat, slurry, or any other waste products, are physically exchanged between enterprises, thereby reducing energy consumption, production costs, and environmental damage.

Smart City Kalundborg is a 3-year smart grid pilot with a budget of $18 million.  Launched in November 2012, the project is led by Danish utility SEAS-NVE, Dansk Energi (Danish Energy Association), Spirae, and the municipality of Kalundborg.  Other participants in the project include ABB, CleanCharge, Clever, Danfoss, Gaia Solar, DONG Energy, Gridmanager, and Schneider Electric.  Smart City Kalundborg will look at the integration of energy management across power, water, heating, transport, and building systems.  This entire system will be based on an open, intelligent platform called the Energy Services Hub.  The Hub will enable diverse participants to make specific energy resources available to the system via a publish-and-subscribe model.  An individual enterprise, water utility, or demand aggregator, for example, could use the platform to offer a specified demand response capacity to grid operators looking to manage fluctuations in power supply or reduce the need for network reinforcement.

The technical and market challenges to delivering such a system at a city scale are significant, of course.  However, the biggest question may be who is in the best position to operate such an Energy Services Hub.  One solution would be a joint venture between a municipality, one or more utilities, and a platform operator, but other models are possible.

Smart City Kalundborg is an innovative approach to deepening the connection between smart grids and smart cities.  While Kalundborg has much in common with other market-focused demand management projects in Europe, it differs in its attempt to include a wider range of city operations, including water management, transportation, and district heating.  Kalundborg Symbiosis has provided a synergistic network for the industrial system; Smart City Kalundborg project could provide a similar network for the local energy system.

The Japanese market for building energy efficiency technologies has been strong for decades, thanks in large part to the 1979 Act Concerning the Rational Use of Energy, the foundation of Japan’s stringent building energy codes.  In the 2 years since the Fukushima earthquake and the ensuing energy crisis – which has caused a 17% increase in the price of energy for non-residential customers of TEPCO, the monopoly utility that serves the greater Tokyo region – demand for energy efficiency technologies in Japan has grown significantly.

In particular, demand for building energy management systems (BEMSs) has grown as much as 30% to 40% year-on-year over the last few years, according to discussions I’ve had with market participants and key industry players in Japan.  Although the concept of BEMSs is mature in Japan, given that it is a requirement of the Act Concerning the Rational Use of Energy, the concurrent timing of the energy crisis and the market availability of software-as-a-service (SaaS)-based BEMS software has led to a surge in its adoption.   (It should be noted that the concept of BEMSs in Japan overlaps significantly with the concept of BEMSs in Europe and North America, though BEMSs in Japan often include additional technologies such as building-to-grid connections, smart meter technology, and others that are often considered part of the smart grid in other regions.)

Driving DR

At the recent World Smart Energy Week at the Big Sight in Tokyo, I was focused on learning more about the adoption of technologies such as building energy management systems (BEMSs), direct digital controls (DDCs), demand response (DR), and other intelligent building products in Japan within the 3^rd Eco House & Eco Building Expo.

I attended several sessions of the event’s Smart Grid Technical Conference, where representatives from organizations such as Itron, NEDO, and Toyota discussed smart building technology in the context of the increased intelligence of the utility grid.  In particular, the increased growth of PV and wind in Japan will continue to drive the country’s emerging DR market, which will expand further through the adoption of smart building technology.  As Taichiro Kawahara of Hitachi put it, “Demand-side energy management in Japan must be promoted through demand-side management and demand response.”

The conference not only explored the application of these technologies in Japan, but also compared and contrasted similar successes and challenges with smart grid integration experienced in Europe and North America.  This perspective is critical for ensuring that the adoption of smart grid technology in Japan unfolds as smoothly as possible and for providing Japanese technology developers with important insights into the market landscape in other regions into which many Japanese companies are looking to expand.  This sort of international forum is critical for spreading market-leading technology – and ensuring that the industry doesn’t make the same mistakes twice.