Leveraging technology to drive energy efficiency and conservation

There seems to be an influx of policy these days focused around reducing energy consumption and demand. One such policy is the Pennsylvania Public Utility Commission Energy Efficiency and Conservation Program or Act 129.   So what can utilities do today to meet these new policy requirements?

There are some simple techniques to reduce consumption regardless of when the load occurs such as

weatherization, LED and compact florescent light bulb replacement, energy star appliances, high-efficiency HVAC equipment, etc.  All of these actions reduce electric consumption, reduce carbon footprint and lower consumer bills.

Another way to meet these requirements is by reducing peak demand which has the benefit of reducing the need for generation and T&D capacity.  Since the last generation to be dispatched typically is the least efficient, there are ties between energy efficiency and peak demand reduction. In addition to the above benefits, energy efficiency does have the added benefit that if a consumer load is 20% more efficient, generally that consumer's contribution to peak demand will also be reduced by approximately 20% depending on the type of loads and the energy efficiency improvements that are implemented.

For utilities without smart meters, direct load control of air conditioners, hot water heaters, pool pumps, and other loads that the utility can control have been around for at least two to three decades.  Peak demand reduction is typically very important for co-ops and munis with power purchase agreements that include a peak demand charge.  Smart meters enable more sophisticated load control programs based on time-of-use rates, critical peak pricing rates, or providing pricing signals to home automation systems with programmable, communications-enabled thermostats and controllers for other loads.  Peak demand reduction does not necessarily reduce consumption, but it does shift demand.  EV charging infrastructure is a good example of a demand response program to avoid having the charging of electric vehicles contribute to system peak demand (there can also be local cluster issues with EVs). 

Volt/var optimization (VVO) is another tool that can be used for both energy efficiency and peak demand reduction.  VVO is typically a two-step process involving correction of power factor by offsetting inductive loads with capacitor banks.  Switching the capacitor banks reduces reactive power losses and flattens the voltage profiles on the utility feeders. This does two things -- it increases power delivery efficiency by lowering the losses (which extrapolates to less generation capacity, less fuel consumption, and lower carbon footprint) and the flatter voltage enables conservation voltage reduction.  With a flatter voltage profile, utilities can lower the substation voltage at the source end of the feeder without causing low-voltage problems for customers at the far end of the feeder.  Lower feeder voltages reduce consumption (at least for constant impedance loads -- not the same for constant power loads) which further improves energy efficiency.  For utilities with rates based on kWhs as measured at the meter, CVR also reduces revenue.  Like the energy efficiency programs listed above, conservation voltage reduction also reduces demand, including peak demand. 

Another example of utility energy efficiency is to deploy low-loss distribution transformers or to implement a transformer load management program (TLM) to make sure that distribution service transformers are correctly sized to minimize losses based on individual transformer load profiles.  AMI data can be analyzed when available to assess transformer loading.   Transformers can also be monitored – Power   

Partners is launching an Intelligent Distribution Transformer that can capture the necessary information.

One growing segment of the market is using VVO as a grid tool to reduce peak demand.   OG&E is an example of this.  By rolling out VVO to 400 feeders, OG&E is on track to avoid building an 80 MW peaking plant.  The business case is often stronger for utilities like OG&E which are vertically integrated and can leverage avoided generation capacity costs.  In de-regulated markets, I think that PUC policy is required for T&D wires companies to implement VVO which has societal benefits but does not necessarily help the bottom line of the wires company.  The ERCOT market in Texas is de-regulated and ERCOT is asking the IOUs to look at VVO for grid-based demand response given the Texas resource constraints -- the question is how will ERCOT and the Texas PUC address compensation for the wires companies in Texas to offset revenue impacts and infrastructure costs?

Regardless of policies like the one listed above, our current resource constraints and the onslaught of coal plant closures are driving the need to reduce energy consumption and demand. At least with the breakthrough of smart grid technology, utilities have a choice in how they are going to deal with the issue.

ABB’s North American smart grid VP reveals market strategies - Abbreviated Interview from January 22nd in Smart Grid Today with Gary Rackliffe

Gary Rackliffe, VP of smart grids, North America, at ABB, explains to Smart Grid Today in an exclusive interview, that ABB’s smart grids is focused on four areas of development: distributed grid management, utility analytics, transmission grid management, and distributed energy resources.  Rackliffe also explains how the recent acquisitions made by ABB integrate into these four areas.

Distribution grid management

Acquisition-focused ABB bought Tropos Networks, last year.  This acquisition gave the firm its own communications platform to reach the devices in the field such as load tap changers; line voltage regulators and capacitor banks for volt-VAR optimization; reclosers; DA switches; and various sensor technology for fault detection, isolation and restoration (FDIR), Rackliffe said.  “But with the acquisition of Tropos, we now have our own wide-area wireless broadband communications that will support distribution grid management.  ABB has an additional advantage from its 2010 $1 billion purchase of the enterprise software and solutions firm Ventyx.  We can offer our distribution management system and SCADA from Ventyx, communications from Tropos, and DA equipment and sensors from our Power Products division.”  In the last two years, ABB also invested $10 million on a “smart grid center of excellence,” a testing lab and demo center in North Carolina, where utilities can verify operations of smart grid equipment before field deployment. 

Utility analytics

ABB is chasing the “emerging markets” of utility analytics and asset management in North America, said Gary Rackliffe.  “We have a contract with AEP to implement an ‘asset health center’ solution for its entire transmission asset fleet, so we are not just talking about this, we are actually moving forward in implementing the solution.  We are combining our asset knowledge, our service base, our experience, performance models and algorithms, and our business intelligence software for the analytics and situational awareness that bridges OT (operation technology) and IT at AEP,” Rackliffe said.  ABB is also reaching “beyond transmission equipment,” when implementing the asset health center Rackliffe said. “At AEP, our primary focus is on high-voltage breakers, power transformers, and substation battery health.  But our medium voltage businesses are also implementing asset health management solutions by expanding the sensor base, service experience base, and the performance models and algorithms to cover distribution equipment – particularly switchgear and outdoor breakers.”   The acquisition of Ventyx helps drive development of this market with enterprise business intelligence and asset management software.

Transmission grid management

ABB views “technology that enables you to better control, manage and operate the transmission grid as part of our smart grid portfolio.” The firm is seeing sustained growth in FACTS (flexible AC transmission solutions) and more applications of its HVDC technology.  In recent months, the firm developed the world’s first circuit breaker for HVDC and built a new $100 million factory for high voltage transmission cables. In the transmission space, “as it pertains to smart grid, ABB is working on the integration of renewables, which tend not to be located near load centers,” Rackliffe said. That means high voltage direct current (HVDC) technology is needed and used.  Offshore wind with longer cables is an example of renewable energy that require HVDC technology.

Distributed energy resources

ABB is integrating software to manage distributed energy resources (DER) and to see how aggregated DERs impact distribution operations and how they can be monetized at the generation portfolio level and/or the energy market level.  DERs include demand response, distributed generation, electric vehicle charging, energy storage, and microgrid technologies.  ABB bought Epyon to provide DC fast charging station infrastructure and Powercorp to provide microgrid solutions with integrated energy storage. ABB in the last two years also expanded its energy storage portfolio to offer battery community energy storage (CES) for the distribution grid.  “An example is a CES project we have with Duke Energy using re-purposed batteries from Chevy Volts,” Rackliffe said.  The unit can deliver 25kWs of power and 50kWHs of energy.  There is high growth potential with energy storage, he added, but we need to get some cost reduction out of the batteries.  “The car manufacturers are helping us with their focus on driving down the cost of lithium-ion batteries,” Rackliffe added. In September, ABB introduced a solar-plant controller and grid interface that allows control of voltage, frequency, real power, reactive power, power factor and ramp-up generation rate.  The company also announced its plans to acquire PowerOne, which offers PV solar inverter systems.

Other major ABB investments

ABB also recently bought Tennessee-based low-voltage equipment manufacturer Thomas & Betts ($3.9 billion) and Arkansas-based industrial motors and generators maker Baldor Electric ($4.1 billion), making the US ABB’s largest market for the first time in the firm’s 130-year history.  The North American market is very appealing, simply due to the sheer size and potential of the market, Rackliffe stated.

The business case for renewable distribution generation

Guest post: Caroline Mason, Commercial Key Accounts Manager

Nearly two months ago, Georgia Power announced plans to triple its solar power purchases, emphasizing the chance to stimulate innovation and research in an area that is promising for the sunny state of Georgia. When I saw their announcement, I was halfway through the first classes of my MBA program, and was developing an understanding of what it means to be a corporation; how each of your decisions must in some way create value for your shareholders.  I wondered how an investor owned utility could sell the economics of distributed energy resource (DER) investments, which include small scale distributed energy storage (DES) and distributed generation (DG), to its shareholders.  A utility’s interest in energy storage seemed fairly logical, but DG resources, often in the form of small scale renewables, would have a tough battle to fight.  Significant advancement in DES is required before renewable DG can be reliably counted on to reduce a utility’s peak generation requirements. Until better DES is available, renewable DG installations will yield lower profits from sales of kilowatt-hours without reducing CAPEX for generation assets. Business cases for DG investment will vary based on a utility’s rate structure and regulatory status, but without the capability to offset generation requirements, utility DER investment will be driven by government activity, often in the form of a monetized penalty.

To get a better view of the potential business case for renewable DG, it is helpful to segment utilities based on the rate structure and regulatory status under which they operate as shown in the chart below.

		Regulatory Status
		Regulated	Deregulated
Rate Structure	Decoupled	Goal: Please regulators Constraints: No penalty for reduced kWH sales	Goal: Compete with other providers Constraints: No penalty for reduced kWH sales
	Coupled	Goal: Please regulators Constraints: Reduced kWH delivered yields reduced profits	Goal: Compete with other providers Constraints: Reduced kWH delivered yields reduced profits

 Effect of regulatory status and rate structure on utility investment decisions
*Blue shading reflects a positive or neutral business case for DG; red text reflects a negative business case

Most readers will be familiar with deregulation, but may not be as comfortable with decoupling, which allows a utility to maintain profitability even with decreased sales of electricity.  Decoupling is generally tied to energy efficiency investments, but it does have significant implications for our discussion. In a market where utility profits have not been decoupled from electricity usage rates (reflected in the two lower quadrants), a reduction in power purchased cannot be recouped through rate adjustments.  Even in markets where decoupling has been implemented, if the state’s utilities are deregulated (reflected in the upper right quadrant), the utility’s generation arm will see no profit adjustment as a result of the state’s decoupled rate structure.  It is only in regulated markets where decoupling is allowed that a utility might be capable of constructing a positive or neutral business case for investing in DG.  In those markets, a utility’s balance sheet could be properly adjusted for any sales lost to renewable DG because its generation, transmission, and distribution assets are included in the same financial statement.

Why is it, then, that we have become fairly accustomed to utility announcements of renewable power purchase initiatives? Having eliminated the ‘carrot’ of increased profitability, we have to look at the ‘stick’ of financial penalties that might sway our utility’s business case.  The most common penalty comes in the form of a renewable portfolio standard (RPS), which regulates the percentage of a utility’s generation capacity that must come from renewable energy.

Returning to our earlier discussion, Georgia is not one of the few regulated, decoupled markets, and they have no RPS penalties in place.  What, then, would cause their investors to accept their announced investment? As it turns out, Georgia Power is attempting to avoid the legalization of power purchase agreements (PPAs), which would allow independent companies to build DG resources on a customer’s site and sell the customer power generated by those resources, effectively bypassing the utility’s relationship with the customer.   While Georgia Power’s business case might not be as straight forward as its RPS influenced counterparts, its investment is still balanced by a monetized penalty, in this case, avoided PPAs. 

  

Looking forward to 2013

2013 has jumped off to a quick start for smart grid and the DistribuTECH conference, at the end of the January, had everyone’s focus.  This event showcased smart grid and grid modernization technologies in the exhibits and during the three-day technical sessions.  ABB had three booths at the event: the main ABB booth, the Tropos booth, and Thomas & Betts booths.  ABB’s Automation & Power World and Ventyx World are to follow in the spring.

Distribution Grid Management will be the leading investment area
My prediction for 2013 is that this year will be the year for investments in the grid part of smart grids.  In particular, the distribution grid will receive much of the focus as utilities work to improve reliability and efficiency.  I think the concept of distribution grid management is gaining momentum as it converges distribution management systems, distribution SCADA, outage management systems, distribution substation automation, and distribution feeder automation. 

Key advanced applications are fault detection, isolation, and restoration (FDIR, also called FLISR for fault location, isolation, and service restoration) that provide self-healing capabilities to the grid to improve reliability and volt/VAr optimization. Volt/VAr optimization combines reducing reactive power losses on the distribution system with conservation voltage reduction to improve efficiency and to reduce system peak demands.  These applications can be managed centrally, with distributed control in substations, or implemented for specific feeders with local control.  Both applications incorporate software, communications, field equipment and apparatus, and sensors.

OT/IT Convergence
This convergence of distribution technologies also includes the integration of operations technology (OT) and information technology (IT).  Distribution grid management leverages more available data and integrates enterprise-level IT systems with the operational systems.  Distribution management systems (DMS) are now integrated into the geographic information system, the customer information system, and the meter data management system.  Mobile workforce management integration to the DMS platform substantially improves outage management and storm response.  Distributed energy resources such demand response, distributed generation, energy storage, electric vehicle infrastructure, and microgrids impact grid operations must be coordinated.  All of these technologies for distribution grid management have driven the need for grid analytics and improved situational awareness, which business intelligence software can offer.

More Grid Analytics – Asset Health
This OT/IT convergence also influences the grid analytics and business intelligence software for T&D asset health management, which is another smart grid investment focus area in 2013.  Aging infrastructure, constrained technical resources, pressure on O&M expenses, compliance requirements, the costs of unplanned outages, and the need for grid reliability are driving investments in asset health management.  For these applications, sensor data, historian data from operations, report data (tests, inspections, and maintenance), nameplate information, and other data sources are leveraged to manage asset health.  Performance models based on equipment expertise and service experience drive asset health by creating actionable information for operations, condition-based maintenance, and life-cycle decision support.  Completing the OT/IT convergence, these actions are then executed by enterprise asset management systems supported by mobile workforce management.

Transmission Investments
I expect to see renewable energy integration drive transmission investment in HVDC, FACTS, energy storage, and wide area monitoring projects in 2013.  These technologies improve grid efficiency and capacity and can provide grid support to mitigate the effects of variable renewable generation.

Distributed Energy Resources
Investments will continue in demand response, distributed generation, and distributed energy storage in 2013.  We will continue to see direct load control demand response, but the industry will also be moving out pilot implementations for dynamic demand response and the other distributed energy resources. I do think that there will be some competition for dollars between demand response on the consumer side of the meter and grid enabled demand response through volt/VAr optimization.  Electric vehicles are selling slower than expected so in the near term, EV infrastructure will be charging stations and demand response applications.  Microgrids are growing for both off-grid and grid-connected applications.  Microgrid control technology enables thermal, hydro, wind, and solar generation to be managed with battery and flywheel energy storage and demand response control of loads.  Improved reliability, integration of renewables, and remote off-grid solutions are microgrid investment drivers.

Washington DC
Smart grids and grid modernization is getting attention again in Washington DC.  The Smart Grid investment grants under the DOE are being executed but the focus of these grants was job creation and advanced metering infrastructure (AMI and smart meters).  The storm response in the Northeast following superstorm Sandy and other recent storms have raised awareness about how smart grids can improve the utility recovery process and also provide improved situational awareness. 

Washington is also asking about legislative models to enable grid modernization to improve reliability, improve efficiency, and to enable renewable generation.  The other issue in Washington is on cyber security. GridWise Alliance, NEMA, and other industry organizations are actively engaging on the cyber security policy discussions.  The big challenge is business case support for grid investments at the distribution level, which fall under individual state public utility commission regulatory oversight.  Regulatory models, de-regulated markets, de-coupled rates, societal benefits, and operating efficiencies are some the challenges that we need to navigate.
  

All in all, 2013 is shaping up to be an exciting year for Smart Grids. 

Security guru Richard Clarke, industry practitioners weigh in on cyber threat

Washington loves a good acronym, and when it comes to cyber security, Richard Clarke has a great one: CHEW.  The renowned national security expert who served three presidents as senior White House advisor spoke last week at ABB’s Western Utility Executive Conference in Pebble Beach, CA, and outlined what he sees as the four main threats in cyber security.  They are, in order: crime, “hacktivism, "espionage and war.

On this last element, Clarke made the point that cyber war was not merely scrambling databases in some faraway computer system, but using digital means to affect the same ends as conventional war, namely “blowing things up.”

That may have sounded a bit hyperbolic, but Clarke offered numerous examples not only of potential threats but of cyber attacks already carried out.  So far, these have been limited to less explosive, but no less effective, results such as the presumably Russian effort to wall off Georgia’s access to the internet and disrupt its banking system during the 2008 South Ossetia war.

Indeed, Clarke noted, breaches are happening every day and he expressed particular concern over the power grid as “the first target everyone talks about because everything depends on electric power.”

He also spoke plainly about what he saw as a widely held impression in Washington that the power industry is “resistant” to dealing with the cyber security issue, seeing it as an invitation to burdensome regulation.

Clarke’s remarks were followed by a panel discussion led by Industrial Defender CEO Brian Ahern that included DTE Energy Division Information Officer Mike Carlen, Commonwealth Edison Vice President of Information Technology Mark Browning, and FirstEnergy Vice President of Distribution Support Steve Strah.

Ahern began by seemingly confirming the Washington consensus, at least in retrospect, by noting that the early days of his company were spent evangelizing the importance of cyber security to a power industry that at the time did not see it as something broken that needed to be fixed.  That was then.

Stuxnet, in particular, served as a wake-up call and now Ahern finds a much more receptive audience in the utility C-suite.  This was borne out by unanimity among the panelists in terms of a) recognizing the threat of cyber attack is real and b) making a financial and managerial commitment to addressing it.

“The cost of doing nothing is far too much,” said FirstEnergy’s Strah.  “Presented with relevant facts regarding cyber security incidents, from a risk management standpoint, we have to take it seriously.”

To be fair, what resistance there is in the industry can be chalked up to the challenge of simply getting a large entity like a utility to embrace change.  This is culture shift on a massive scale, and it will take time.  However, regulators have a role to play, too.

NERC’s current cyber security regime, for example, requires some parts of the utility’s network to be secured while others are not.  That could be problematic.  Ahern said he expects NERC will soon extend its Critical Infrastructure Protection (CIP) requirements beyond the generation and energy management systems it covers today to include all aspects of utility operations.  In the meantime, though, utilities will have to manage their compliance with an evolving standard.

Compliance and security are two different things, however, and as DTE’s Carlen stated, “Security trumps compliance.” 

“We will be compliant,” he said “but being compliant does not guarantee you are secure.”

The three utilities represented on the panel are therefore moving forward aggressively to propagate a culture of security, not simply compliance, across their organizations.

Still, that won’t be enough, according to Clarke.  Given how reliant all industries are now on third party software, he encouraged the executives in attendance to look beyond their own companies and apply the same rigor to their supply chains as they do to their own operations. He described the need to build security into the development process from the very beginning, and cited the financial services industry as one sector that has done this with some success.

Clearly there is much to do on all sides, but government and industry would be well advised to adopt a cooperative approach when it comes to cyber security. 

“Government should be rewarding the private sector for investments in cyber security,” said Ahern, and he pointed out the importance of safe harbor protections so companies can share information about attacks as well as best practices without fear of legal retribution. 

Leveraging each other’s experiences, he explained, is the best roadmap to a more secure power grid.

“Where’s the Big Data?”

Chris Lemay from Ventyx, an ABB company, provides some additional input to the comments I posted in August regarding “Big Data.” He touches on the three “Vs” of Big Data: velocity, volume, and variety from an electric utility viewpoint. Some of the industry experts extend the discussion to four “Vs” or even five “Vs” by including the Variability of the data which is the inherent fuzziness of the data in terms of context and meaning. The fifth “V” is Value which is quite important since Big Data becomes an academic exercise if no value is created.

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In his August post, Gary pointed to the growing trend of utilities investing in Big Data. It’s probably healthy, however, to have a dose of skepticism around all the hype. After all, even 10 million of today’s smart-meters will take a decade to generate over a petabyte of data. Looked at objectively, the sheer volume of data generated by the smart grid is dwarfed by what financial and retail market players experience. That’s where the other aspects of “Big Data” come in to play: velocity and variety.

If you’re familiar with utility control room operations, you already know about data velocity. The electric grid is real-time; supply and demand need to be kept in balance at all times. Traditionally, we’ve managed with a limited amount of SCADA and a healthy contingency margin on supply. However, the intermittency of renewables and moves to shift peak consumption are driving a need for smarter management of the end-to-end grid. Better control systems are needed to manage a greater variety of supply sources, including distributed generation. In order to make more optimal use of the available capital resources, we also need more accurate and more granular predictions of demand, so that supply and demand can be managed together. Although the volume of data exchanged between the various devices on a modern grid may be modest by “Big Data” standards, the requirements for speed and accuracy of analysis are very demanding. 

Utilities are also very familiar with data variety. This is especially true if you wander out of the control room and into the field. The data utilities have about their assets is so varied and scattered that gathering it all together for a complete picture of the health of each asset is a daunting task. The first problem is that most utilities have many silos of information. One example is that information collected by operations about assets isn’t usually available in the maintenance department and vice-versa. Through consolidation, many US utilities also have geographical or organizational silos of information that make it difficult to get a consistent view of asset performance in different parts of the enterprise. Another source of data variety is a by-product of the fact that most grid assets have a long lifetime relative to the IT assets collecting and storing the data today; it is likely that there is much less data available on assets commissioned 30 years ago than those installed in the last decade. Furthermore, as sensors on assets and in the grid are added or upgraded, they produce a richer variety of information about these long-lived assets. Utilities need IT systems that are flexible enough to handle these changing sources of data, and are also extensible so that they can also handle less structured data such as observations recorded by technicians in the field, and even images taken of assets over their lifetime.

Writing in the October 2012 issue of the Harvard Business Review, Andrew McAfee and Erik Brynjolfsson state that they are “convinced that almost no sphere of business activity will remain untouched by this movement.” Although the “Big Data” needs of utilities are somewhat different than those of other industries, I believe it would be naïve to think that the increases in data volumes, velocity and variety will not transform their business practices in a significant way. Putting in place the new technology and adopting the new processes to take advantage of this revolution in data acquisition and processing is just one more component of the smarter grid.
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Virtual tour of ABB's Smart Grid Center of Excellence

The ABB Smart Grid Center of Excellence (COE) located in Raleigh, North Carolina, provides utilities a single point of contact to leverage ABB's proven expertise as a worldwide Transmission & Distribution (T&D) Operations Technology (OT) and Information Technology (IT) system provider. The COE displays many of the products and solutions from ABB's smart grid portfolio and allows utilities to get engaged with live functional demonstrations of cutting-edge smart grid technologies.

Watch the virtual tour below to see what the ABB Smart Grid Centre of Excellence has to offer. For more information about the COE or to schedule a live tour, visit the COE web site or contact us at sgcoe@us.abb.com.