Just last month I attended my 19^th CS Week event in Phoenix focused on educating and supporting utilities in the customer experience lifecycle. The event has transformed over the years from one being focused on only the Customer Information System (CIS) to one focused on Analytics, Billing & Payments, Contact Center, Credit & Collections, Digital Customer Engagement, Field Services, and Strategies & Management. This year I noticed a distinct theme around the customer experience and where they are at.

Some, like investor-owned utility American Electric Power (AEP), focused on personalizing the experience for their customers. AEP is doing this with the help of Oracle’s cloud-based CRM and integrating it to AEP’s on-prem based CIS known as MACS (really a legacy Customer/1 CIS). Others, like cloud-based platform company SEW (Smart Energy Water), are espousing the benefits of meeting your customers where they are. The belief is one where the customers are going to mature at their own pace and that pace may not line up with where the utilities are or even plan to be. Therefore, one must plan to meet those customers whether they are using social networks, a mobile app, SMS, or a phone call.

Not to detract from the event’s original roots, the CIS had some activity of its own. Hansen, an Australian company that had acquired US-based CIS application Banner showcased its new upgraded version BannerCX. For years there has been speculation about whether Banner clients would get investment into the product to create new versions. Hansen has done just that and released a new version available in on-prem and cloud versions for existing and new clients.

Columbia-based Open International recently won a new CIS client in the US. Ft. Collins Utilities, a part of the City of Ft. Collins, Colorado, signed with Open International and integrator Milestone Utility Services to implement a new CIS that serves not only traditional utility customers, but also the City’s new broadband business. Historically, telecom services such as broadband are billed via a separate system. Open International has a Telecomm background and therefore has architected its CIS offering to bill utility and telecom services in the same application. Ft. Collins Utilities plan to meet their customers where they are by offering an application that can handle multiple needs of the customers.    

DC Water won an award for the Best CIS Implementation. The effort, known as Project Triton, included VertexOne for the customer portal, mobile customer app, systems integrator, and managed services provider, SAP for the core CIS: Customer Care, Billing and Collections, Confluence Group for planning, scheduling, dispatching, and mobile work management, KUBRA for bill payment and presentment, and AAC for evaluation, selection, contract negotiation, project management and testing. The project took 12 months and cost $46/customer for the CIS when similar projects run $75-$125/customer.

Direct Energy and HCL co-presented an outcome-based model that they are using together where the scope includes Contact Center, Billing, Back-Office, and Credit & Collections business services as well as supporting Applications and Infrastructure Services. While outcome-based models are gaining traction, I found the artificial intelligence piece of the preso quite fascinating. HCL uses a chatbot known as “Ava.” Ava is a cloud-based solution for communicating with customers, is trainable and utilizes advanced NLP functions, and can integrate with CRMs, payment gateways, and most other 3^rd party systems.

PPL co-presented a collections management strategy with service provider WNS. Working together, the utility devised a statistically sound approach that utilizes early risk identification mechanisms, dynamically segments customers that ultimately results in a propensity to pay model. Using the new model PPL realized a doubling in its same day dollars propensity to pay.

XCEL Energy and Reliant presented with Google on work they are doing to bring AI via smart speakers into their customer interaction experience. Smart speakers are relatively new generally but appear to have a much higher technology adoption rate than the Computer, Color TV, Internet, Smart Phone usage, and even Social Media usage. According to Google, voice is becoming the “new normal.”  With 1 billion devices in the market, Google Assistant is focused on mass personalization and personalized engagement with your customers. Yes, your customers. Google is working with foundational partners XCEL and Reliant for bill availability & payment (today), usage report and proactive alerts (coming soon), and send bill (in consideration). Google also is looking to recruit more utilities to participate in its Google Assistant endeavors. Talk about meeting customers where they are with a personalized experience.

These are only a few of the interactions I had in Phoenix at CS Week. There are many others not mentioned here that are doing transformational things in the utility customer service space. I would like to thank Rod Litke, John Sild, and the many staff members of CS Week in working to put together such a great annual event. I hope to see many of the industries’ participants next year in Ft. Worth.

I was asked recently by a vendor in the market if the cloud is “real.” The reason for the question was to determine if it is time to focus a service offering for utilities in the cloud, on-prem, or both. If I were to base my response on the various conferences and market speak in the industry lately, the obvious answer would be a resounding “BOTH!” But before we jump to the easy answer, let’s look at the cloud and where the various offerings are for utilities today.

First, the cloud is not new. One can argue that service providers to the U.S. electric cooperative market were early versions of cloud services in the mid 1960’s. Central Area Data Processing Cooperative (CADP) and North Central Data Cooperative (NCDC) both served electric and telecommunication cooperatives with information processing services and accounting and billing software. In 2000, they both consolidated and formed Lake St. Louis-based NISC. Today NISC provides services to over 800 energy and telecommunication utilities in all 50 states related to accounting, customer care & billing, cyber security, engagement, operations, and technical services. In 1976, Atlanta-based SEDC was formed by a group of Electric Membership Cooperatives. It provides services to over 500 distribution utilities in the U.S. related to CIS/Billing, FIS, financial services, mobile work force management, GIS and engineering, document imaging, IVR, work management, cybersecurity, and advanced visual analytics.

This year I have attended several events such as EUCI’s Billing and Payments for Utilities, DistribuTECH, IEEE PES T&D, and CS Week. One thing I have noticed is the increased marketing of cloud services for utilities. One example that appears to be just plain old outsourcing but could someday be called a cloud service was Entergy’s decision to move a good portion of its back office billing exceptions offshore. It has resulted in reduced costs and someday could migrate into AI type solutions where machine learning and robotics automate the exception handling process. Another example included Liberty Utilities use of service provider Fiserv for receiving data, processing, and mailing bills through to various presentment options and remittance. This accelerated revenue collection for Liberty while reducing costs.

In some more applicable examples to cloud directly, Washington DC-based, DC Water, selected Vertex to provide a SAP-based CIS/Billing platform provisioned as a cloud service. The effort included other cloud-based apps such as a customer portal and mobile app, mobile field work management, electronic bill presentment and payment, and integrated to other cloud and on-prem solutions. The decision took 18 months to make but once made, DC Water implemented in 12 months utilizing an agile methodology with multiple sprints. New York-based, ConEd, employed a hybrid cloud strategy when undertaking a Digital Customer Experience transformation project. The effort included the website, a mobile application, customer engagement, chat features, web survey solution, and a preference management center. Pros and Cons were evaluated for on-prem vs cloud vs a hybrid approach. ConEd chose the hybrid approach where the low volume components requiring more security control would be hosted on-prem while the high volume components or components needed only infrequently would be hosted on the cloud which offers scalability, flexibility, and high availability.

It seems that only a few years ago many of the vendors serving the utility industry were skeptical if not fully opposed to cloud services. Now, many of those same vendors have a cloud offering or are working to offer a cloud alternative to existing on-prem. The utilities themselves are reaching a point where nearly half of the RFPs issued include a cloud alternative. While we may never get to a point where we serve the industry completely via cloud, I’d say that the forecast is partly cloudy.

It was February 5^th, 2003, and I was attending my first DistribuTECH in Las Vegas.  Pennwell, the organization that owns and operates DistribuTECH, boasted approximately 3,500 attendees with a record of 200 exhibitors.  As I walked the exhibit floor, I almost felt overdressed wearing my blazer and slacks since the exhibitors were mainly from the field demonstrating transformer, recloser, and substation technologies.  I recall nearly losing my lunch as a recloser demonstration occurred next to me.  Some of the newest technology on the floor was related to automated meter reading (AMR), which were enjoying record sales in 2003.  Also, Indus was acquiring the Global Energy and Utility Solutions (GEUS) unit from Systems Computer and Technology Corporation (SCT).               

Earlier this year I made my way back to DistribuTECH in San Antonio.  This time, the show boasted 13,500 attendees with over 520 exhibitors.  I felt right at home as the exhibit floor now seemed to be dominated by blazers and slacks.  Not to be forgotten, the transformer, recloser, and substation technology vendors were still there, but the information technologies from a modernized grid were owning the exhibit floor. 

The principles of yesterday’s electrical grid date back more than 100 years.  Originally designed to move power from centralized supply sources to fixed, predictable loads, the grid has served a growing nation well but brings with it some structural weaknesses.  The system is expensive and labor intensive, hard to expand, and prone to service disruptions and outages.  Furthermore, because of its radial design, the grid has historically been hard pressed to integrate off-grid, distributed assets such as solar, wind and other renewable sources.

A Modernized Grid seeks to upgrade this system by using intelligent technologies, much of which I witnessed on the floor in San Antonio recently.  This new grid provides utilities with a real-time roadmap of their assets and two-way communications with their customers.  AMR has become AMI or advanced metering.  Forget hiring helicopters or service providers for line inspections.  Those are now done by drones.  The new grid improves operational efficiencies and service to customers, lowers costs, and allows the integration of distributed assets.

A few years ago, I led a survey of North American utilities to seek where their priorities lie.  The digital utility came in fourth as it was still in its infancy as a concept.  This year at DistribuTECH, I must say that the digital utility was alive and well.  From vendors pitching a digital grid to utilities sharing how they are handling the digital transformation, it was amazing to see how far the industry has come in such a short time.  Many utilities have begun their journey with a digital customer experience, something that the industry did not start but instead has been brought to by the customers themselves.  Now with the communication and information technologies that have arrived since 2003, we have seen the grid go from dumb, to smart, to intelligent, and eventually just modernized.  And as the customers go digital, the grid goes digital, and eventually the utility goes digital.

I am starting to feel quite old as I reminisce about attending a grid conference where I should have been in jeans and boots (2003) when AMR was one of the newest technologies being showcased to where the industry has gone with integrating small, mid, and large power sources on a grid that was not designed to handle multiple sized intermittent generation in various places.  I am going to save this small article and read it in 2033 when I attend DistribuTECH to compare how far we’ve come as an industry.  And speaking of industry conferences, I hope to see you in the Mile High city of Denver next week at IEEE PES T&D.    

Two weeks ago, I had the benefit of attending the 21^st Century Energy Transition Symposium held at Colorado State University in Fort Collins, Colorado.  Originally designed to discuss natural gas development, safety, technology, and policy, the symposium, now in its seventh year, has transformed to discuss the transition from more traditional forms of energy to new, renewable forms of energy.  The highlight of the event was a Governor’s Lunch Keynote Panel which included three sitting governors and one former governor.         

Moderated by former Colorado Governor Bill Ritter, the Panel included current Colorado Governor John Hickenlooper, Montana Governor Steve Bullock, and Wyoming Governor Matt Mead.  The sitting Governors came from both political parties but had one thing in common, all came from energy producing states.  

Governor Mead reminded the audience that Wyoming is the largest exporter of energy producing coal, uranium, and wind energy.  Throughout the panel the three sitting governors held friendly arguments over who had the “best” wind.  Wyoming’s number one industry is energy while its number two industry is tourism.  Home to the nation’s first national park, Yellowstone, Governor Mead acknowledged that we must take care of the environment, and we should not be afraid of where science leads us.

Governor Bullock, operating in the conservative coal state of Montana, boasted 28% of the nation’s coal reserves and 8% of the world’s coal reserves.  Despite a heavy coal industry in the state, Governor Bullock expressed the need to address climate change and to meet the climate challenges with technical innovation.  With a population of approximately one million and annual visitors to the state of 12 million, Governor Bullock shared that Tesla had put six charging stations in Lima, MT, population 224.  He surmised that since there were probably not six Teslas in Lima, or even in the state, that they were placed there strategically along I-15 to allow quick charging for those travelling.

Colorado Governor Hickenlooper spoke of a new future where wind energy costs had dropped by two-thirds in the last five years and solar costs had dropped approximately 80% in the last five years.  While emphasizing the importance of the future vision, he counter-balanced it with the reality of keeping price and reliability in check for the existing energy sources.

Bottom Line?  The three sitting Governors are from different political parties, yet they share similar outlooks on energy.  We need to keep our existing energy sources reliable and price competitively while investing in future energy sources.  None were solely pro coal, and none were solely pro renewable.  A balanced approach seemed to dominate the panel.  Now these Governors may not be representative of their colleagues in other states.  They are all from mountain west states that produce energy, and they also preside over some of the most beautiful places in the United States.  Former Governor Ritter tried to sum it up and give each Governor a “win.”  Wyoming has better wind, Montana has better transmission, and Colorado has better skiing.  Speaking of skiing, the resorts are opening.  Hope to see you on the slopes soon!     

A few months ago, I had the pleasure to attend EUCI’s seventh annual Customer Information Systems (CIS) for Utilities event in Washington DC.  Hosted by Exelon, the event brought together small to large utilities delivering multiple commodities from electric to gas to water.  One of my favorite sessions at this event is the open vendor panel discussion with multiple vendors taking questions from the utilities in the audience on the state of customer service in the utility industry and where it may be heading.  A question late in the panel grabbed my attention as it pertained to service levels and how they may have changed from in-house to cloud operations.

The vendor panel consisted of AAC Utility Partners, Vertex Business Solutions, Oracle Utilities, and West Monroe Partners, and it was moderated by yours truly.  Now you know why it’s one of my favorites.  Every year I try, to no avail, to get a “chair throwing” argument reminiscent of the Jerry Springer talk show fight that made chair throwing famous!  Over the years, I have not been successful in getting SAP and Oracle to fight, in getting small CIS vendors like Itineris to fight with behemoth Oracle, or getting in-house license providers to fight with software-as-a-service (SaaS) providers such as Vertex One.  Therefore, I have relegated the questions to the audience, and it has been quite an evolution as the audience, consisting of many utilities, asks the vendors and consultants, some very good, pointed questions.  The one that came as we were about to break for a cocktail reception pertained to service levels in utility customer service and if those service levels had changed as the industry experiences a move towards cloud-based, or outsourced, solutions.        

This question not only resonated with the vendors and consultants, but it also got me going as I have been tracking service levels and service level agreements (SLAs) over the years.  About 15 years ago, post Y2K, many utilities had just replaced their CIS and were running in-house licenses.  The CIS’ that were outsourced were focused mainly on the unregulated retailers in states or provinces that had deregulated in North America.  There was an emphasis put on quality of bills produced.  This meant checking the bills for errors.  If the CIS was operated in-house, this was known as quality control where a specific group would randomly pull bills from each billing cycle and check them for accuracy.  If the CIS was outsourced, a similar process would take place, although it would be called a contractual service level.  The target would be somewhere greater than 95% accuracy with most around 99% accuracy.  For those that had outsourced, there would be additional service levels like on-time billing, summary billing timeliness, accurate meter-reading, usage sent to distributors or retailers (for unregulated market participants), exception resolution, estimated accounts, and no-bills. 

Post Y2K, the industry did not have a “cloud” per-se, instead it had “outsourced services.” Today, with the arrival of the “cloud,” many utilities, regardless of the regulated aspect of the market they operate in, are entertaining cloud services.  These can range from what was previously outsourced services such as billing, contact center, print, payment processing, etc. to true new cloud services such as storage, application hosting, and customer relationship management (CRM).  These new cloud services come with a new set of service levels.  Storage and application hosting come with service levels such as up-time, disaster recovery, and update windows.  For those of us with smartphones, how many times are your apps updated?  Much more than we’d like to be sure.  In a new application hosting cloud environment, it is critical when the apps are updated.  For instance, the ability to hold off on app updating during storm outages or peak times such as light up season for gas utilities or heat waves for electric utilities.   For the CRM, customer satisfaction and first contact resolution are increasing in importance.  Some cloud-based CRM providers are also beginning to track channel shift where the goal is to move customers from more expensive channels like a physical phone call to a less expensive channel such as a smartphone app or increased IVR containment (keeping the customer in the IVR to resolve an issue rather than speaking with an agent).

One fact that the panelists all agreed on was that utilities with sourced operations have more service level tracking and accountability than those with in-house operations.  This is not to downplay in-house operations, it is just a fact that sourced operations have contractual obligations to serve at specific service levels, and there may be ramifications for missing those service levels.  With the increased adoption of cloud-based services comes new service levels as we interact with customers via differing channels.   

Last month I attended the 41^st CS Week in Ft. Worth, Texas. CS Week is the premier annual educational and customer service conference serving electric, gas, and water/wastewater utility professionals across North America and around the world. What caught my eye at CS Week was a presentation given by Gartner VP and Distinguished Analyst Dr. Zarko Sumic on The Impact of IoT on the Future of Utility Customer Systems. Dr Sumic made a statement that “your Customer Information System (CIS) will have to talk to a digital assistant in the near future.” Did I hear that right? My CIS will need to “talk” to Alexa, Google Now, Siri, Cortana, and the like? Now there’s a cool integration that may start to replace not only a phone call, but also a number of customer self-service channels.

The CIS in the utility space has had a long and winding road when it comes to customer service. Many years ago, the CIS itself was a tool used by customer service agents in a traditional call center. Then customer self-service began to make inroads via Internet portals. The ability to inquire about a bill or bill amount online was quite innovative at the time. Call centers themselves began to automate via the interactive voice response (IVR) unit, starting with simple touch tone, to “press-or-say”, to directed dialogue, to natural language functionality. Some of the natural language functionality of today in IVRs is beginning to look a lot like the digital assistants. However, the IVR exists at the utility or service provider’s call center and the digital assistants belong to the customer.

It makes perfect sense that digital assistants will start to talk to the CIS. Nearly a year and a half ago, Amazon announced the ability for Alexa to support “If This, Then That” (IFTTT) trigger commands. This is an important milestone in providing customer service as IFTTT is a third-party service that automates how devices, apps, and websites work with each other through rules. Sounds a lot like the API’s used when integrating to the CIS.

Utilities and service providers have made great progress over the years taking a standard call center and converting it to be an omni-channel contact center. Not only can customers call for customer service, they can also text, e-mail, chat, utilize a portal or app on their smart phone, or use the IVR instead of talking to a person. Here is where yet another game-changer enters the space.

In March of this year, Amazon Web Services (AWS) announced Amazon Connect, a cloud contact center as a service offering. Salesforce quickly followed announcing that it is collaborating with AWS to integrate Service Cloud Einstein with Amazon Connect. The two announcements extended the global strategic alliance between AWS and Salesforce helping simplify and expand how customers capture, analyze and act on data. They also detailed how customer service representatives could utilize the “as-a-service” contact center to help customers, yet I wonder how long it will be before the customer service reps are being replaced by Alexa, or natural language IVR type functionality. GE Appliances have already started using AWS Connect for contact center services.

Are we there yet? No. But as Dr. Sumic suggests, this will happen in “the near future.” The key will be standardizing a set of commands, or IFTTT type trigger commands so that differing digital assistants can get the same results. Whether a customer uses Siri, Cortana, Alexa, Google Now, or others, they can still find out how much electricity they have used this month, or how much the bill may be at end of month, or other questions they may have. What an exciting time we live in.

Jon Brock is President of utility and energy advisor Desert Sky Group, LLC.  He can be reached at jbrock@desertskygroup.com 

A few years back I was offered some annual cash from the local electric utility to allow them to cycle my air conditioner during peak loads in the summer. I instead opted to install an attic fan and just not run my air conditioner in the summer. Now for those of you who know me, I obviously do not live in Houston. Not running the air conditioner in Houston is NOT an option. I live in the Mile High City of Denver where an attic fan is a legitimate alternative to typical demand response programs in the summer. My local electric utility uses Opower to send customers reports on how they are performing usage-wise month-to-month. My attic fan catapulted me into the Rockstar status of beating the neighborhood on usage. “Mission accomplished” and in the process, helped my local utility with those peak periods without them having to “pay” me.

Oracle announced last May that it would be acquiring Opower for approximately $532 million, positioning the acquisition as enabling Oracle and Opower to become the largest provider of mission-critical cloud services to the utilities industry. Now, Opower is not just a “cloud provider” of services. Instead, it specializes in collecting meter reads from utility end customers to provide analysis on usage and compare that usage to a geographical area, say a neighborhood or zip code. It started as a paper-based solution by adding its analysis into a current bill or sent as a separate paper document. A utility did not have to have AMI for the solution to work and be effective. Over the years, it became apparent that it needed to provide digital solutions in addition to its paper-based solutions. Hence, the drive to cloud-based services and the obvious strategic link with Oracle.

One year later, Itron announces it is acquiring demand response provider, Comverge, for $100 million. Comverge, like Opower, did not start as a cloud solution. Instead, it started as a “hardware oriented” demand response provider. In recent years, it has changed its model to focus on software and services. One of its more popular services is the “Bring-Your-Own-Device” program where the customer provides its own device, such as a smart thermostat, to interact with Comverge software providing demand response services. PNM and Entergy Arkansas recently signed up for programs that offer “Bring-Your-Own-Device” features. Itron plans to use the acquisition of Comverge to enable utilities to better integrate distributed energy resources and optimize grid performance and reliability.

So what does this mean for Demand Response/Energy Efficiency markets? A couple of things. First, it appears that the market leaders are getting acquired by other market players looking to expand offerings into Demand Response/Energy Efficiency. Oracle and Itron have taken out two of the arguably top leaders in the space. Secondly, the markets are heading into a “Cloud” or “As-A-Service” direction. Instead of doing hard-copy reports or installing specific hardware and managing that hardware, we are beginning to see cloud solutions emerge that enable end consumers the ability to shed load or operate more efficiently. Regulators in some states are beginning to recognize the value of cloud-based solutions and are beginning to entertain allowing return on those services. Historically, the utility had to capitalize via investing in an asset to allow for recovery. Energy Efficiency poses a problem in this equation as it is many times being provided as a service and not as an invested capital asset. It also encourages less use of the product that utilities are selling. I would expect to see more acquisitions of Demand Response/Energy Efficiency companies and expect to see them transition to a cloud-based service offering as opposed to the traditional hardware required offering. Also, for those who are interested in utility customer service, I hope to see you next week in Ft. Worth at CS Week 41.

I recently spent some time with two entrepreneurs in the energy industry, Gary Boese and Patrick Kelly. Gary and Patrick have built an online marketplace for the utility and energy industries to buy/sell goods and services and even help each other out in a storm situation. The marketplace is known as Ecapiter. I trust you enjoy reading this interview.

Jon:  Please give us a background of yourselves and tell us what Ecapiter is about.

Patrick:  Gary and I first met back in 1980 and our careers have tracked fairly closely since.  We’ve devoted almost all of our careers to delivering solutions of one type or another, in the form of software and/or services, to the utility industry.  We’ve cut our teeth on CIS applications and services which has given us a good insight into all aspects of a utility’s operation and the challenges it faces on a daily basis.

Gary:  In addition to the above, Pat and I spent quite a few years leading software sales and support organizations in the international community.  Both of us have lived and worked abroad and been involved in managing direct sales organizations and managing local agents.

Jon:  Sounds like deep experience in the utility industry.  Tell us a little bit about what your venture is right now and why it is important.

Patrick:  Ecapiter was formed to provide utilities around the world a convenient forum in which they could buy and sell assets that are excess to one utility and required by another.  This allows them to sell and buy at the best possible price.  According to utility executives with whom we have visited, today’s business environment requires more cost awareness than ever.  Therefore, we feel Ecapiter will quickly become a valuable service to the industry.

Jon:  What is the business model around assets in the utility industry?  Obviously, we’re a very capital intensive, asset intensive industry.  What is the basic model of Ecapiter?

Patrick:  Based on our relationships and experience in the industry we became aware of the concern about the billions of dollars tied up in stranded assets (material and equipment no longer required). This was a result of regulatory reform, mergers and acquisitions and advances in technology.  We didn’t see any avenue being provided to facilitate the sale of these stranded assets on an industry-wide, world-wide basis.  Of course , in other parts of the world, there is a shortage of certain types of assets that are needed to build infrastructure and our concept really is based upon the idea that we can help these countries buy the assets they need at the best possible price.

Jon:  So, Ecapiter has an international or global reach or is it going to start in a specific geographic area?

Patrick:  We certainly plan on establishing a significant presence in North America to create a viable service and then extend into other countries as the demand dictates.

Gary:  We think we may be drawn into the international market by companies that have contracts in other countries and see what we are providing and work through us to obtain the assets they need at a reduced cost.  It was also interesting to discover that NRECA has projects underway in some of the emerging countries where they are assisting utilities expand their infrastructure. 

Jon:  That’s interesting you bring up NRECA.  Can you talk more about your target customer at the utility?  Are you looking investor-owned, rural electric, municipal and also commodities (electric, water, gas)?  What’s the scope of your client base?

Gary:  We see all types of utilities using this service.  Due to the environment described earlier and the aging infrastructure in the water and natural gas industries, it is estimated that trillions of dollars will be spent over the next thirty years to expand and refurbish this infrastructure.  Our scope includes all three types of utilities whether IOUs, munis or co-ops.

Walk me through what a utility does to sign up.  Let’s say that they have extra assets or they are looking for something.  What’s the process?  How do they go about using your service? 

Patrick:  In order to list or buy assets you must be a member.  Membership is free and is required in order to limit users to utility personnel and to appropriate contractors.  The first step is to submit an application for membership which is available on the Ecapiter website.  Upon notification, you are ready to participate in the process of listing or buying assets.  Ecapiter personnel are available to assist in the process as required.

Jon:  Who is responsible for the delivery?  Let’s say that someone lists and someone buys.  Who is responsible for the delivery of the assets?

Patrick:  The sellers are obviously responsible for having the assets available for transporting but the buyers are responsible for the transportation and receipt of the assets.  Most utilities have a relationship with resources to accomplish this but we are in a position to help them by referring them to appropriate people when necessary.  For large, complex projects (i.e. substations, generating plants) we can provide referrals to people who specialize in disassembling or deconstruction and shipping this type of equipment. 

Jon:  So, if I’m a utility, who is the actual user?  Is it a procurement department or could it be into a construction department or field service type job role?

Gary:  It could be any or all of the above, Jon.  It is more a function of how the utility is organized to accomplish and control these tasks today. 

Jon:  And I’ve also noticed that on your website you have an area for disaster recovery listings.  Can you talk a little about disasters and disaster recoveries?

Patrick:  Unfortunately, disasters come in all shapes and sizes and are something that each utility experiences.  What we want to do is provide each participating utility the opportunity to list assets that they would make available for sale to a utility that has gone through a disaster.  For example, a utility can go into the Disaster Recovery section of the Ecapiter website and list assets they may have planned for an upcoming construction project but would sell only if a fellow utility has experienced a disaster and needs help.  This provides participating utilities an opportunity to quick access to critical material and equipment.

Jon:  Certainly sounds like a novel concept.  I’m not sure I’ve seen something like this in the marketplace.  Have you got any competition or is there anyone like this doing an exchange in the market?

Gary:  The only service that we have found that is similar is not dedicated to the utility industry.  The service they offer is diluted as a result of trying to be all things to all people.  Our purpose in life is to serve the utility companies.

Jon:  So this is not overstock.com then.

Patrick:  Exactly

Jon:  Very good.  This has been very beneficial and I trust our readers will enjoy reading this.   Your website can be found at www.ecapiter.com.  I want to thank Gary and Patrick for joining us.

Patrick:  We certainly appreciate the opportunity to visit with you, Jon.  The only thing I would like to add is we certainly would welcome inquiries.  Anybody that has questions can certainly call us.  Our toll free number is listed on the site.

This last week I was reading the USA Today and noticed a customer satisfaction article focused on the airline industry. According to the article, “as an industry, airlines received the fourth-worst score in the American Customer Satisfaction Index (ACSI) rankings of customer satisfaction. Only pay TV, social media companies and Internet service providers rank lower. Even wireless carriers and car dealers rank higher. That may not be an indictment of the industry, but it does indicate a lot of room for improvement.” I wondered where the ACSI had the utility industry ranked, so I visited their website. Apparently utilities rank better than the airlines industry as well. They also rank higher than cellular and landline telephones, health insurance, Internet news/information, and subscription television service (cable or satellite). Being so close to an industry can sometimes skew one to be more critical of that industry. I myself am guilty of being critical from time to time of the very industry I am a part of. However, when compared to other industries, we don’t look so bad after all.

I started to reflect on why the utility industry is not so bad on customer satisfaction when compared to other industries. The answer can be found at the annual AGA-EEI Customer Service Conference held in San Francisco, CA just last week. Attended by 400 registrants representing the gas and electric utility industries (particularly the investor-owned utilities), the key components of the conference included the call/contact center, credit & collection, billing and payment processing, meter reading, field service, revenue protection, and low income/at-risk customers.   

Allow me to give a summary of a few of the presentations given in San Francisco that offers a glimpse of why utilities can be seen as leaders in customer service. When focused on one of the key touch points for consumers, the call center, Central Hudson Gas & Electric presented on unifying customer communications for outages. Central Hudson has spent the last few years building multiple communication channels and making some of them interactive for consumers when it comes to outages. The channels they utilize include the call center, IVR, website, mobile app, e-mail, and SMS text. The SMS text functionality allows consumers to send various commands in to report outages and check the outage status. Many analysts covering the industry have reported that outages and outage communications are key in customer satisfaction and as such, Central Hudson is receiving top rankings on customer satisfaction.

Although the AGA/EEI conference focuses on investor-owned utilities, a cooperative utility made an interesting presentation on outage communications. South Central Power Company partnered with Twenty First Century Communications to create outbound message campaigns that utilize phone, e-mail, SMS text, Twitter, and Facebook. The outbound messaging also targets meter change-outs, tree trimming, and planned outages in addition to unplanned outages. Customer satisfaction with the outbound messaging was 89% or greater for all notification types. In short, South Central Power experienced significantly greater customer satisfaction when providing proactive communications for planned and unplanned events.

Gulf Power, part of the Southern Company, presented on its partnership with iFactor on outage communications. Again, providing a number of communication channels was key to success. Gulf Power utilizes an outage map at MyGulfPower.com, the call center, a mobile outage app available at the Apple Store and GooglePlay, e-mail, and SMS Text. Gulf Power’s implementation team included resources from marketing, customer service, customer operations, public affairs, corporate communications, district management, and distribution operations.  Including these departments mitigated the risks involved with the program rollout.

PPL Electric Utilities partnered with JD Power to present on proactive outbound outage communications. PPL started with what it called the new age of “Meteorological Mayhem,” or more specifically, tornadoes in May 2011, hurricane/tropical storms in August/September 2011, “snow-tober” in October 2011, and Superstorm Sandy in October 2012. Outbound messaging at PPL was done via e-mail, voice, and SMS text. PPL experienced an ice storm in February of this year that affected 70,000 customers and sent 67,422 total messages for (7,927 e-mail, 25,664 voice, and 33,831 SMS text). As a result, customer satisfaction with overall communication during outages has increased from 64% in May of 2011 to 79% for Superstorm Sandy in October 2012, to 85% for the ice storm in February of 2014.       

With the weather becoming more of a factor in our industry, as PPL would call “Meteorological Mayhem,” focusing customer service not only on operational excellence (reducing outages and outage durations), but also proactively communicating with customers via a variety of channels, will increase customer satisfaction. I have only touched on one area of the AGA/EEI Customer Service conference held last week in San Francisco and therefore have not done it justice, but compared to other industries, customer satisfaction is alive and well in the utility industry.

This article has been re-printed with the permission of Global Renewable News.

Last month an article in the Concord Monitor caught my eye as it focused on the Northeast United States starting to entertain hydro power from Canada to help solve demand spikes in the winter (source: http://www.concordmonitor.com/news/work/business/11309672-95/new-england-seeks-to-tap-canadian-hydropower). It reminded me of an event I attended last year at the NARUC (National Association of Regulatory Commissioners) summer session in Denver, Colorado. One evening I was invited to a reception at the Canadian Consulate in downtown Denver along with many state, provincial, and federal regulators from both the US and Canada. The theme of the evening was energy imports and exports between the two countries, specifically electrical power and not so much the controversial pipeline from Alberta to Texas.

As the night progressed, it became apparent to me that this was not necessarily about electrical power and the transmission between the two countries, but mainly about hydro power as a renewable resource that could be shared between the two. Granted, based on 2009 data from IEA, the US generates approximately 7 percent of it electricity from hydro power while Canada generates 60 percent.  Some interesting facts shared by the Canadian Hydropower Association included:

Canadians many times equate hydro with electricity as evidenced by their own electric utilities such as BC Hydro, Manitoba Hydro, Hydro One to name a few. They also have a unique structure not found in the US where a province can own and operate the utility. Know as “crown corps,” these utilities are usually large and focused on the distribution of electricity, although some do generate as well. Using hydro-generated electricity as a resource that can be transported across country borders became a topic of the evening. A few of the benefits discussed were:  

• Canadian hydropower offers competitive and reliable long-term electricity prices because it is not subject to volatile fuel prices
• For every dollar the US spends on Canadian energy, the US receives back 91 cents from the products that Canadians buy from the US
• Canadian and US hydropower together, help avoid approximately 350 million tones of CO2 emissions per year
• Each Terawatt Hour of Canadian hydropower exported to the US displaces between 500,000 and 1,000,000 tonnes of CO2
• Hydropower helps integrate new renewable electricity such as wind and solar in both the US and Canada to further address climate change
• Half of undeveloped Canadian hydropower potential alone, could power all light duty vehicles (LDVs) in Canada and approximately 25% of the US LDV fleet, if the vehicles were all plug-in hybrid electrics
• Canadian hydropower is currently less than 1% of US electricity supply

It is not uncommon for hydro to get lost in the renewable discussion when solar and wind is the main focus of many regulatory discussions. However, according to a pamphlet distributed by the Canadian Hydropower Association, the US National Academy of Sciences has found that emissions from the construction and operation of a hydropower facility are comparable to other renewable such as wind power and many times less than natural gas. An argument exists that hydropower is also good for the economy and job creation. To state a specific example, BMW recently chose to build its advanced carbon fiber manufacturing facility in the US Pacific-Northwest specifically because the region is serviced by clean, renewable, and competitive hydropower.

Speaking of the economy, one statistic that was not discussed but I am sure of its relevance in cross-border spending is the percentage of retail sales that are about to occur on Black Friday when Canadians invade the US to shop for deals. While not sold on any one fuel source alone, whether it be coal, gas, nuclear, hydro, solar, wind, or other, I do believe that hydro has a role in achieving a healthy mix of generation in the near term and the future. Canadian hydro does have an appeal for their neighbors to the south.

A few weeks ago I attended the Billing for Utilities event in Orlando, FL hosted by the Orlando Utilities Commission and orchestrated by EUCI. At the event I had the pleasure of moderating a panel of utilities focused on practices and issues in utility billing specifically in the U.S. utility industry. Represented on the panel was Portland General Electric, Peoples Natural Gas, Georgia Power (Southern Company), and TECO Energy. The panel addressed questions from myself and the audience, made up mainly of utility attendees.

This event was the 12^th annual focused on utility billing for EUCI and as such, the topics and issues discussed centered on the customer information system (CIS) and the billing function at the utility. EUCI has recently split this event into a Canadian event (held in Toronto this last January) and a U.S. event held in Orlando. Hence the issues were coming from a U.S. perspective. I kicked off the session by asking the panelists what the biggest challenge they currently face is. The panelists agreed on two major concerns. Those being the aging workforce and a lack of IT support. Mind you there are no IT resources on the panel or even in the audience for that matter. So this concern is coming from the business, more specifically the customer service department of the utility. The aging workforce worried the utilities not only because of their own departments losing skilled and seasoned resources, but also because the IT departments in their respective utilities were losing key resources.

For years the aging workforce has been an issue in all industries, not just utilities. The U.S. is not alone in this predicament. In fact, even with dire warnings and statistics pointing to the decrease in the workforce aged 15-64, Europe and parts of Asia actually appear to have it worse than the U.S. Now the effects of the aging workforce is impacting the business. And to bring this back to the Billing topic, many utilities have been successful in the last 5-10 years extending the life of the CIS. However, the day of reckoning is arriving as the skilled resources required to maintain the CIS and build interfaces to new applications and fill new requirements begin to retire. Some of these resources are business-based but most are IT resources.

The audience asked many follow-on questions related to the utility CIS/Billing application including pre-pay services, consumer engagement, and credit/collections. But the last question was the most telling. If you had an unlimited budget and guaranteed regulatory approval, what would you do? Acknowledging the obvious “dream world” background scenario, the grinning panelists took the answer straight back to their two main concerns. They would replace their aging CIS with plenty of knowledgeable and skilled IT resources. They heard earlier in the day how that project could run anywhere from $55-$125 per customer based on jurisdictional complexity, number of applications, and number of customers. Most in the industry are well aware that CIS replacement projects are large risky multi-year endeavors that sometimes claim careers and require plenty of up-front planning and integration expertise. For most that comes in the form of integrators in the industry but also requires plenty of business and IT staff internal to the utility. I am coming to the conclusion that based on the aging workforce beginning to move from talk to reality via retirements and the lack of available IT resources, utilities are going to have a challenge when the duct-taped (successfully mind you) CIS needs replacing.

Granted the nature of the event (Utility Billing) dictated the answer. I am sure at a distribution event I would have heard “underground the entire distribution network with the latest smart grid technology” or at a generation event “replace my coal generation with the latest hydro, nuclear, natural gas, or even renewable facilities.” But when you are focused on utility billing, business and IT resources are key elements for success. And they are aging just as fast as the distribution, generation, or construction engineers.

At the most recent Smart Grid RoadShow/SmartGrid Canada event, an invite-only reception for utility executives was held in downtown Toronto at the Turf Lounge. Sponsored by Schneider Electric and attended by over 50 of the industries’ brightest thought leaders, Toronto Hydro’s VP of IT & Strategic Management Robert Wong addressed the crowd. I caught up with Mr. Wong recently and interviewed him based on that evening, specifically focusing on where he believes the smart grid is heading. I trust you enjoy this interview with one of Ontario’s leaders in the utility industry. This interview is re-printed with the permission of the Smart Grid RoadShow.

Jon T. Brock

Jon Brock (JB): Some call it the smart grid. Some call it grid modernization. Whatever it is called, please describe what Toronto Hydro has done in recent years to bring its distribution grid into the future.

Robert Wong (RW):

Toronto Hydro was one of the early adopters of the so-called smart grid.  In response to the Ontario government’s energy policies, Toronto Hydro initiated the first large-scale deployment of smart meters in Canada. It was also the first to implement Time-of-Use rates in the province through its installation of an operational data store to house smart meter data and reconfiguration of its Customer Information System (CIS) to enable the new market rules.

Beyond the AMI aspects of a smart grid, Toronto Hydro has deployed new technologies and equipment on its distribution grid.  Monitors have been installed on many distribution transformers to track loading patterns and reconcile loads of individual customers against that of the transformer to identify any discrepancies.  State-of-the-art line sensors (power line monitors) have been installed on distribution feeders to collect power quality and performance data, and provide new insights to improve grid operations planning and efficiency.  Toronto Hydro has also embarked on distribution automation initiatives to move towards more decentralized control of logical segments of the grid and “self-healing” technologies to restore power faster and more efficiently and safely. In keeping with the culture of energy conservation in the province, Toronto Hydro has led the way with the implementation of demand management technology to allow the utility to control customers’ air conditioning units and pool pumps during high demand situations.   Furthermore, with the growing number of electric vehicles (EV) on the roads, the company has installed separate smart meters for a number of EV customers on a pilot program to individually monitor the potentially disruptive impact of EV charging on the distribution grid.  The findings so far have been very compelling and will inform the utility on future planning strategies.

A couple of other areas where Toronto Hydro is moving forward on are the construction of a new sub-station and the installation of electricity storage technologies.

What’s unique about the new Copeland TS is that it is located in downtown Toronto (next to the CN Tower) and will be totally underground – the second of its kind in Canada.  It is being built to relieve loading on the existing nearby sub-stations and to create new capacity to meet the increasing electricity demand created by the recent explosion of high-rise residential developments in the downtown core.  There is more than double the number of high-rise developments in Toronto than in any other city in North America.  Obviously, the new sub-station will be constructed with the latest smart grid technologies as well as the technical requirements for a large electrical installation in a subterranean environment.  The Copeland TS is scheduled to be operational at the end of 2014.

Earlier this year, Toronto Hydro installed the first urban Community Energy Storage (CES) unit at a local community centre/arena.  This storage unit will help alleviate stress on the grid during peak times and also provide power to connected homes in the area in the event of a power interruption.  It has built-in intelligence that can independently monitor grid conditions and respond appropriately by taking in electricity during off-peak times and releasing power if needed.  Some of the other potential benefits of CES are the elimination of the need for diesel back-up generators, the smoothing of voltage levels for commercial and industrial customers who may have sensitive equipment, and the integration of renewable technologies such as solar panels and electric vehicles.

Probably the most important aspect of building and operating a smart grid is the data that is generated and collected by the smart grid components.  In this regard, Toronto Hydro has developed and implemented some analytical tools and applications that make use of the data and transform it into useful information to assist the grid operators to better manage the grid (Outage Management System), the Engineers to develop better asset replacement and maintenance plans (Feeder Investment Model Analytics, Health Index Calculator), and the customers to better manage their electricity usage and costs (PowerLens^TM Energy Calculator online application, PowerLens^TM Time-of-Use mobile app).

Another thing that Toronto Hydro has started to work on recently is the upgrade of its telecommunications network.  What makes a smart grid “smart” is the ability to communicate vast amounts of information from the field back to the office in real-time or near-real-time basis.  To enable this, a modern telecommunications network that can deliver the business and technical requirements (failover tolerance, availability, latency, and bandwidth) for each individual component of the smart grid is critical.  To deliver a modern but cost-effective network, the company is deploying commercially available technologies and services such as fibre-optic network using Coarse Wavelength Division Multiplexing, Ethernet/IP, and commercial cellular. The upgrade of this telecommunications plant will be done in coordination with the upgrade of the distribution grid to ensure proper alignment and with the objective to select the most cost-effective and viable options for each component of the system.

JB: When implementing a smart/modernized grid, old school silos need to be broken down. Please speak on the IT/OT integration that must take place and how Toronto Hydro has addressed the IT/OT issue.

RW:

With the introduction of “smart” devices and equipment in the traditional distribution grid, the convergence and associated conflicts of IT/OT are inevitable.  IT now plays a much bigger role in the area of grid operations.  Electrical equipment and devices that were once electro-mechanical in nature are now largely IP-enabled.  IT is now expected to manage the data, information, analytical tools and even the telecommunication systems required by the smart grid as part of its service offerings. However, the environment in which these smart assets reside (distribution grid, sub-stations, transformer vaults, poles, etc.) is very different than those of traditional IT assets (data centres, telephone closets, etc.). This leads to the dilemma of having to decide and delineate who should be responsible for what aspect of the maintenance and support of the smart grid – IT staff or operations staff?  This also imposes the need to expand the skill sets of each type of resource.  To that end, as part of Toronto Hydro’s certified in-house electrical apprenticeship line school program, it has enhanced its Sub-station Technician program to include additional technology training to meet this new skills requirement created by the advent of the smart grid.  As well, we have seen that IT has now taken on more responsibilities related to the smart grid, such as support and management of the utility telecommunication systems, AMI systems, DMS/OMS, SCADA and SONET.  The traditional lines of separation between IT and OT are becoming blurred and have forced IT and OT to work much more closely together and come to agreement on new roles and responsibilities.

The convergence of IT/OT has also forced the company to look at the relationships among the various OT systems from a more holistic point of view.  Because of the much tighter integration now required of the individual systems as a result of the business process dependencies associated with them, operational and planning decisions can no longer be made in isolation. There is now a critical need to ensure that the technical standards and functionality of each component of the overall smart grid are established in the context of the larger ecosystem and to acknowledge the requirements of the other individual components to ensure compatibility and overall effectiveness.  Planning, design and implementation of the smart grid must start at the macro level, involving cross-functional teams of business and technical experts from the areas of grid planning, grid operations, customer care, IT and telecom.  An example of this more collaborative approach is the Smart Metering Task Force that was established to perform planning activities to establish a roadmap for the future upgrades and enhancements to Toronto Hydro’s smart grid infrastructure which includes not only AMI, but also the OT aspects of grid operations both in the field (SCADA RTU’s) and in the work centre.

JB: How important are customers in a smart/modernized grid world?

RW:

In a smart grid world, the management and servicing of customers become much more demanding than in the past.  Customers today are more sophisticated as a result of the proliferation of technology in business, and the modern world in general.  Huge amounts of data are created and collected everyday and businesses are offering new and innovative services to customers exploiting the vast amounts of data that are now available.  Customers, in return, are now expecting and even demanding more and more services and greater access to data and information.  The electrical utility industry is not immune to any of this, especially when the industry has been undergoing a bit of a renaissance in the last decade with the introduction of the smart grid and other developments such as rising electricity prices, time-of use rates, energy conservation, demand response and management, renewable energy, electric vehicles, mobility, and smart homes and appliances.

Utilities today must modernize their customer service models to provide greater value-for-money and an enhanced customer service experience.  They must develop and offer new ways for customers to interact with the utility on their own terms, through their own choice of preferred media (telephone, e-mail, website, Twitter, Facebook, etc.) and when they desire to do so (business hours, evenings, weekends, holidays).  Customers depend on and expect their utility to help them manage their electricity usage and costs by providing innovative tools and personalized information.  They expect their utility to assist them in conserving electricity by offering conservation (CFL Recycling, Fridge/Freezer Pickup, Heating & Cooling Incentive, etc.) and demand management programs (PowerShift^® Program, peaksaver PLUS^®).  And they expect their utility to provide timely and accurate power outage and restoration information when the power goes out in their homes so they plan accordingly to deal with the outage.  Moreover, customers look to their utility to help them understand, in clear common language, the many complexities of today’s electricity industry so they can make more informed decisions.

JB: Looking to the future, how will an optimal smart grid look in year 2030?

RW:

In 2030, an optimal smart grid will be one that is comprehensive, efficient, reliable and secure.  There will be end-to-end system integration right from the customer’s smart home appliances to the smart meter on the house to the AMI system to the Customer Information System (CIS) to the electronic bill and to the customer self-serve web portal applications.  There will also be full integration from the intelligent devices on the distribution grid to the “intelligent” command and control systems that will automatically operate the grid to restore power and isolate a fault in fractions of a second to the Outage Management System (OMS) that pinpoints the outage and provides information for expedient dispatching of work crews to perform repairs to the grid and precise outage information that will be proactively pushed out to customers to notify them of the problem and provide an reliable estimated time of restoration so they can make appropriate plans.  As well, there will be end-to-end integration from the various smart grid devices to the Distribution Management System (DMS) to assist the grid operator to configure and optimize the grid for greatest operating efficiency and provide performance data to Engineering analytical tools to gain greater insights into the health of the grid and point out areas for enhancements through targeted asset investment or maintenance programs.  This optimal smart grid will drive future business processes across all areas of the entire utility and change the way a utility will operate.

An optimal smart grid in 2030 will be one that is heavily computerized and largely operates on its own through sophisticated software applications.  Utility workers will play a much lesser role in the day-to-day operations of the smart grid but instead will devote most of their time maintaining the back-office systems that run the smart grid and analyzing the data produced by the smart grid and making business decisions based on it, including refinements to the algorithms and Engineering models to continually enhance the performance of the smart grid.  The optimal smart grid will have an impact on the electrical utility industry (unmanned sub-stations, remote monitoring and operations) much like the way computerized trading has affected the trading of stocks in the financial markets industry or how robotics and computerized control systems have changed the automotive manufacturing industry.

JB: What has to change to enable an optimal smart grid in year 2030?

RW:

A number of changes have to happen in order to enable an optimal smart grid in 2030.  First, there must be convergence of technical standards, especially as they relate to communications protocols, to improve interoperability of smart grid components and enable full end-to-end integration of systems.  Utilities, working in collaboration, will have to drive this convergence of standards.  Having common standards will stimulate development of smart grid equipment by manufacturers and lead to their commoditization.  This, in turn, will accelerate the implementation and maturation of the smart grid by electric utilities.

Utilities will also need to greatly improve the completeness and accuracy of all the data relevant to the smart grid.  In order for an optimal smart grid to work effectively and efficiently, it must have complete and accurate data.  Furthermore, the computing systems that run the smart grid must also be reliable, bug-free and secure.  The electricity power system is a critical infrastructure and if it is to be “computerized” as defined by an optimal smart grid, the underlying computing systems must be of a quality level much higher than other business computing systems.  They must meet Engineering standards of quality, performance and security.

Because a defining feature of an optimal smart grid is the real-time capabilities of the various components to communicate data and control the grid, the enabling telecommunications systems must be robust, fast and highly available.  Utilities must ensure that their utility telecommunications systems keep up with the technical requirements of the smart grid components as defined by the business requirements related to the operation of a smart grid utility in 2030.  Investments must be made in the utility telecommunications systems to achieve this level of required performance.

Lastly, as with the introduction of any new technology or business process, it requires the user to adapt and make changes in how they conduct work.  Successful change management of utility worker perceptions around acceptance of smart grid capabilities will be critical to the adoption and expansion of the smart grid.  Utilities will have to allay employees’ fears that their jobs will be rendered obsolete by computerization and automation of the smart grid and, instead, accept that in the future they will have to work even more closely with these computerized systems. An overall culture shift in how utility work will be done in the future must happen.

Jon Brock is President of Denver-based utility and energy advisor Desert Sky Group, LLC. He can be reached at jbrock@desertskygroup.com

Last week I attended Smart Grid Live, not to be confused with Saturday Night Live, which is an event that focused on actual smart grid technologies at utilities. Located in beautiful Ft. Collins, Colorado, the event focused on live demonstrations of the smart grid technologies in use at various utilities around the globe. In addition to the demonstrations, which were a breath of fresh air, the event focused on the advancement of the smart grid today, namely educating consumers.

Much attention has been recently paid to consumer engagement and education with smart meter issues resulting in opt-out plans for several states. With the advantage of hindsight, the industry is now claiming that consumer education is the way to go. Had we educated our consumers on the benefits of smart grid before rolling out smart meters, we may have avoided some of the issues we are facing today. Others are arguing that simplification in the form of set-it-and-forget-it type technologies are the way to win over the consumer. Yet others argue for consumer engagement as something utilities have not historically done but need to do now and into the future. In reality, smart grid education involves all of the above.

The Ft. Collins event was a production of The Center for Smart Grid Advancement, an initiative led by smart grid solution provider, Spirae. Something I have not witnessed before at an event was the education program held for local high school students. On the final day of the event approximately 200 high school students from Ft. Collins area high schools attended dedicated sessions to shed light on the smart grid and the utility industry in particular. The students were greeted by U.S. Senator Michael F. Bennet’s office followed by a smart grid workshop that taught how various energy sources will communicate with homes, cars, and businesses to meet the energy needs of the future through a smart grid simulation. After the workshop, the students participated in a career panel to discuss academic options and career paths with local leaders from Colorado’s top smart grid businesses and utility companies such as Xcel Energy, the University of Colorado, Spirae, and Mycoff, Fry & Prouse.

At a press briefing during the event, the importance of education was discussed. Various industry stakeholders agreed that reaching kids in middle school, high school, and college is critical for future success of the smart grid. In fact, Spirae has partnered with Colorado State University on a smart grid lab in the City of Ft. Collins. The University of Colorado has started a new program called the Digital Energy program that brings together I.T., Telecommunications, and Engineering to focus on integrating telecommunications into the electric power grid. Both universities were well represented at the event as well as the Smart Grid RoadShow recently held in Vancouver and hosted by BC Hydro.

Changes in the industry require a new skill set. It is no secret that all industries are suffering from an aging workforce globally. It strikes me as odd lately to hear the woes of unemployment rates while some companies have jobs going unfilled because the lack of a trained workforce. Educating youth not only on the smart grid but on the occupations that will be required by a modernized grid will be a key to success and future growth. To hear what our future President believes is the key to economic success, I urge you to tune in to another Colorado university (the University of Denver) this evening for the first of three Presidential debates. Hopefully someone will ask about the training of a new workforce.

Jon Brock is President of Denver-based utility and energy advisor Desert Sky Group, LLC. He can be reached at jbrock@desertskygroup.com

1. Environmental issues
2. Technology factors
3. Regulatory concerns
4. People skills
5. Macro-economic factors
6. Market factors

1. Embraced greater openness and excelled at executing tough change.
2. Strongly differentiated through better data access, insight, and translation into actions.
3. Were more likely to partner for innovation, disrupt, and derive revenue from new sources.

Re-printed with permission from Metering International:

Recently I was asked to present on net metering and net billing utility efforts in the United States (US). I was to present to a group of Caribbean utilities that were interested in the topic. Of course I had to accept this burdensome task as I was heading from a utility in snowy Canada.

Utilities in the US are beginning to incent consumers to generate power and either use it or sell it back to the utility. According to the DSIRE database maintained by the U.S. Department of Energy, the Interstate Renewable Energy Council, and NC Solar Center, 43 states plus the District of Columbia and Puerto Rico have adopted a net metering policy and 3 states have adopted a voluntary utility program around net metering. In fact, I learned that in the state where I reside I could put solar panels on my roof and net meter those panels whether my homeowners association likes it or not due to the policy in the state. There is no limit to the amount of power I am able to generate and use or sell back to the utility.

Not only are the states beginning to implement these policies for customers, but they are also starting to experiment with how they might improve reliability. For instance, SDG&E has received $10 million from the US Department of Energy and the California Commission to experiment with a microgrid project. Called the Borrego Springs project, the southern California desert community effort will tie rooftop solar to battery storage units that are designed to survive a system wide outage. In theory it should be able to run on its own. If proven, it will be a step towards making the grid more resilient.

SDG&E has one of the highest penetration rates for solar rooftops. On January 17th, 2012 SDG&E filed with the CPUC for approval of a new innovative proposal called connected…..to the sun. The proposal is intended to complement rooftop solar and includes two different pilot programs that would give all SDG&E customers options to buy solar power even if they do not own a home, cannot afford a solar investment, or do not have the ability to put photovoltaic panels on their roof. Customers could choose to buy all or some of their energy from solar projects located in SDG&Es service territory or negotiate directly with a local solar provider.

Couple this with recent research that Desert Sky Group has conducted on new functionality that utilities in the US are preparing to deliver around dynamic pricing of electricity, distributed generation, and rooftop solar, and one begins to see a world where net metering and the associated net billing that must accompany it are becoming a reality. What is the end result that the industry is trying to achieve? The industry is trying to incent consumers to generate renewable energy and by doing so, helping to reduce peak demand. Can there be multiple ways to achieve the same desired result? This is what I found when presenting to a group of Caribbean utilities.

Despite the movement of US utilities towards net metering and net billing, many Caribbean utilities are encouraging something called the renewable energy rider (RER) instead. During a presentation by the Barbados Light & Power Company, I learned that net metering does not necessarily have to be the tool to encourage consumer generated renewable energy. Barbados is a Caribbean island with approximately 123,000 customers, a peak demand of 167.5 MW on sales of 934 GWh (in 2011). All generation is oil based (mostly diesel). The utility has a fuel clause adjustment (FCA) that is a direct pass through of all fuel costs used in production of electricity. Since the FCA has increased from less than 10 cents/kWh (USD) to over 20 cents/kWh (USD) over the last 3 years, the FCA now makes up approximately 60 percent of the consumers bill. Several of the consumers on the island have installed off grid PV and micro-wind systems. Some have installed and others are considering grid connected systems.

Have you ever heard of a FCA making up 60 percent of the bill? This got my attention. With this data as a background, Barbados Light & Power presented its case for the RER as opposed to net metering. The utility introduced the RER on a pilot basis in June of 2010 and it was limited to 200 consumers. Systems were limited to 5kW for residential consumers and 50-150 kW for commercial consumers and are available for PV and wind systems. The RER is calculated based on avoided cost of fuel. The RER pays participating customers a credit of 1.8 times the FCA for a minimum of 15.75 cents/kWh (USD). The money paid to consumers through the RER is included in the calculation of FCA. A meter is placed on the output of the renewable generator to measure energy produced so the full generation requirement for the island would be known (even though Barbados Light & Power may not be purchasing all).

Barbados Light & Power went on to demonstrate why the RER is preferable to them and other island communities as opposed to net metering. To summarize, the benefits to the utility included the utility getting full base revenue from all energy delivered, the utility benefits from avoided demand and avoided maintenance costs, there is no impact of payments to customers on the utilitys revenue, reduces reliance on oil, and it helps to achieve the renewable objectives set by the government and regulator. The downside included an additional meter being set as opposed to a bi-directional net meter.

For the consumers the benefits would include payments going to the renewable generator no impacting the price others pay for electricity since the payment is based on avoided cost. There was much concern over raising base rates for all on the island to implement a renewable energy architecture that only a few could afford. Other benefits included reduced reliance on oil and a reduction in the carbon footprint for society. In the future Barbados Light & Power will begin to implement time-of-use rates for consumers which will incent usage behaviors during certain times of the day.

So when you go to turn on your light, do you know if the electricity is coming from coal, gas, diesel, nuclear, solar, or a wind source? Probably not but the end result is the same – the lights come on. The point being to achieve a goal of consumers generating electricity via renewable resources, there can be multiple ways to achieve that goal. Some are going the net metering/net billing route and some are going the renewable energy rider route. I continue to learn from others in this ever-changing and evolving industry.

Reprinted with permission of the Smart Grid RoadShow

I recently had the good fortune to interview a smart grid thought leader, Robert Wilhite III, Global Director Management & Operations Consulting for DNV KEMA on issues related to the smart grid, DNV KEMA’s new interop lab, and what an optimal smart grid may look like in the future. Rob will be joining myself and other industry luminaries at the Smart Grid RoadShow to be held April 23-25, 2012 in St. Petersburg, FL. For now, I trust you enjoy this interview with Rob.

Brock: Last year DNV KEMA announced a Smart Grid InterOp Lab for testing compatibility of next generation smart grid technologies. What can you tell our readers about that lab and the role it plays in the developing smart grid?

Wilhite: We are thrilled to have continued DNV KEMA’s global leadership role for testing, certification, and risk management by opening DNV KEMA’s Smart Grid Interoperability Lab (SGIL) and its supporting network in October 2011. While the SGIL is the first such facility opened in the U.S., it does fit in nicely with DNV KEMA’s portfolio of labs in existence in both the U.S. and in Europe. This includes the following facilities:

· DNV KEMA PowerTest lab: http://KEMA.com/services/testing/hmv-components/labs/Powertest.aspx

· Smart meter calibration and testing lab: http://KEMA.com/services/testing/calibration/Default.aspx

· FlexPower Grid lab: http://www.KEMA.com/services/ges/smart-grid/flex-power-lab.aspx

The SGIL, co-located at the Duke Energy Envision Center in the Cincinnati area and at the existing DNV KEMA-Powertest lab in Chalfont, Pennsylvania, allows utilities to perform tests that are based on their smart grid design. Tests can be performed based on the particular use cases that they will be exercising in the real world, and on the ability to examine and optimize a myriad of possible options with the rigors of formalized test methods. Because there are no universally-adopted performance standards for these operations, it is difficult to predict their actual execution without either modeling the interaction or physically connecting the systems in a laboratory. It may be difficult to replicate all of the stimuli that would be required to show how the elements interact, or to effectively recreate events (e.g., power outages) in real-world demonstrations. Therefore, the SGIL will play a much needed role in supplementing on-going industry demonstration projects, in order to better understand, and resolve, risks of scaling smart grid networks. The SGIL offers many unique advantages to utilities and industry suppliers as they seek to manage the unknowns of the emerging smart grid-enabled future. The lab offers a live, operational smart grid environment to test and simulate compliance of products and services with existing and new standards, as they evolve. New products and services are tested individually, or in combinations, for compliance and interoperability with other products and services, using industry accepted standards and test protocols. (Note: text extracted from DNV KEMA’s Global Contact publication, June 2011).

Brock: DNV and KEMA have formally joined forces. Please explain for our readers what the new company will offer.

Wilhite: DNV KEMA's services cover the energy value chain from energy source to end user, including renewable energy, carbon reduction and energy efficiency, power generation, transmission & distribution, and energy-related testing, inspection & certification. The company consists of all 1,800 former KEMA employees, complemented by over 500 employees from DNV’s former renewable energy and sustainability activities. While DNV KEMA’s core markets are in Europe, North America and China, the company will pay special attention to growth regions such as Asia-Pacific, Latin-America and the Middle East which have a strong need for energy expertise.

Brock: Tell us more about standards development for the smart grid in the U.S. as compared to other countries.

Wilhite: First, I am more than impressed with the work that George Arnold and his team at NIST have done with this enormous and complex effort to develop a framework to guide smart grid interoperability standards development in the U.S. While many of the referenced standards will be internationally adopted, the undertaking to ensure that key stakeholder needs and concerns in North America are included in this accelerated effort is quite daunting. That being said, it is an even more complex undertaking to take these standards, and their resultant testing protocols, to the next level in the U.S. Given the disconnected nature, and often inconsistent approaches, of our state-driven regulatory regimes and lack of a national energy policy, the question of exactly HOW we apply these standards will remain a difficult one for the near future. I do not suggest that we need state authorities driving standards adoption for their regulated utilities, but a common approach to standards adoption and testing would remove a number of barriers to wider implementation of smart grid networks, especially for multi-state utilities.

This is perhaps the advantage that other countries have in adopting smart grid, as compared to the U.S. Brazil, for instance, has one electric system regulator that can, by default, seek consistent approaches for all of its utilities. In the European Union, more than 30 separate countries are working through common frameworks through collaborative initiatives such as CENELEC (http://www.cenelec.eu/aboutcenelec/whatwedo/standardsmakingprocess/index.html). While it is great to see that the U.S. experience is being shared with the European Union's Smart Grid Coordination Group, the model that the EU has already employed with standards programs like CENELEC appear to be successful in bridging natural barriers in language, culture, and geography. Finally, since approximately 20% of the world’s electric customers are found in China, we find that they are quick to adopt and apply their own standards, but are now also showing some signs of international collaboration. Should we move to a future where the standards development and adoption process become even more universal, growth rates for smart grid deployment would certainly be expected to increase as resulting program risks and costs decline.

Brock: Last summer you addressed President Obama's Council on Jobs and Competitiveness at NC State University. Is the smart grid adding jobs and helping to improve the economy?

Wilhite: Just to clarify, I was one of several dozen invited participants to share perspectives with the President’s appointed Council on what short-term options should be considered relative to creating incremental jobs in the energy sector. A more detailed review of my observations from this session is captured in a blog posting on DNV KEMA’s Smart Grid Sherpa site: http://smartgridsherpa.com/blog/a-view-from-obamas-smart-grid-action-session. Following this posting, I did comment on whether jobs were truly being created as a result of smart grid, please see these comments at http://smartgridsherpa.com/blog/smart-energy-job-growth-exceeding-smart-grid and at http://smartgridsherpa.com/blog/has-smart-grid-spending-to-date-fostered-enough-job-creation. Since then, I would say that we have come pretty far in determining more effective metrics for estimating smart grid job growth. I would not suggest that we rely exclusively on the federal government’s reported metrics from the stimulus grant and demonstration projects. Instead, we need to have better methods to determine indirect jobs creation (e.g., suppliers to smart grid device manufacturers, educational institutions for new workers), plus those positions created as a result of induced job creation when direct and indirect suppliers to the energy value chain further expend their economic gains into other sectors. We also need to understand how smart grid investments in the energy sector also have impacts to other, related industries (such as increased PHEV sales as a result of smart grid-enabled vehicle charging stations). Finally, given the connected tissue of our global industry, we need job creation metrics that also consider the worldwide nature of these investments, as seldom do we find hardware or software systems truly manufactured only in the U.S. or exclusively with domestic components. Look for a future analysis report on this subject to be made available by DNV KEMA.

Brock: Looking to the future, how will an optimal smart grid look in year 2030?

Wilhite: This question is rather timely, in that I just addressed this subject in one of my recent blog postings at our Smart Grid Sherpa site, http://smartgridsherpa.com/blog/when-does-the-smart-grid-become-intelligent. First, I have never been a big fan of the term “smart grid”, as we have certainly employed some degree of automated technology in our transmission grids, and to a lesser extent in some distribution systems, over the past 20 or more years. As the use of analog measurement devices transforms into digital sensors; telecommunications systems become more reliable, cheaper, and faster; and data analytics and IT systems significantly expand in capability, we are finding that today’s “smart” grid will become tomorrow’s “intelligent” network.

As stated in the referenced blog posting, the key question, however, is how will we know when the grid transitions from being merely “smart” to becoming truly “intelligent (or optimal)?”

Perhaps the answer is best obtained by identifying some relevant dimensions of this future state. Reflecting on the progress of a current Smart Grid program, perhaps we will one day find intelligent grids where:

• Sensors and controls become truly autonomous, driven by self-correcting, intelligent algorithms that are operationally embedded and completely interoperable

• Utilities and energy providers are making the automation investment decision a priority, with intelligent controls a design standard for asset management and operations

• New, third-party stakeholders and market participants offer a larger array of new and innovative products and services

• Regulators and policy makers enable more effective cost recovery schemes, not tied to the current regimes, and with majority support (or demand) from relevant industry stakeholders

• Consumers demand the flexibility and fully engage as active participants, often demanding greater levels of innovation and automation from their energy providers.

Then only remaining questions, perhaps, are how long will it take to reach this intelligent position and is this truly an optimal state?

Brock: What has to change to enable an optimal smart grid in year 2030?

Wilhite: An optimal “intelligent” grid will not appear overnight, nor can it develop without significant changes in policy and regulation. Today’s electric and gas providers operate in a market that is significantly controlled through regulatory and government authorities. Energy providers of the future will seek to operate under a market and customer-driven model, rather than our regulatory construct of today. The advantage to all of us with a market-driven model is greater flexibility in product and service choices, pricing options, and increased innovation. Indeed, we have already witnessed some of these changes in the U.S. (e.g., Texas) where retail energy competition and consumer choice has been introduced. Driving these changes will also require clarity from our federal policy makers, in the form of a national energy policy that sets direction.

From the utility perspective, I do believe that the distinction between “T” and “D” will blur, such that equal degrees of automation will exist at all voltage delivery levels. We will also see a greater increase in privatized transmission systems, especially DC-powered systems that, with proper regulatory and pricing incentives, will induce private funding from non-conventional sources to serve remote sources of renewable power production facilities. Furthermore, the dividing line between utility and customer-owned systems will also become less concrete. In fact, in one of my recent Smart Grid Sherpa blog postings, I have suggested the notion that we may not require an electric meter in the near future, once the current generation of AMI deployments have reached the end of their asset life cycle (see posting: http://smartgridsherpa.com/blog/what-is-smarter-than-a-meter).

Finally, I believe that it is inevitable that our industry will see some form of disintermediation, such that consumers become power producers, even bypassing the distribution company as a supplier in the energy value chain. The utility model is well-established and represents significant investment, so it is not going away anytime soon. However, it will certainly be challenged by innovative ideas, which will attract an increasing number of start-up ventures and new private source capital, and interest from established industrial and technology firms, further fueling innovation and new applications. In short, the Utility of the Future will need to anticipate the potential for unlocking new value with transformational changes, while responding to the need to be even more efficient with current systems.

Brock: Thank you Rob. I appreciate your time. I look forward to continuing this dialogue at the Smart Grid RoadShow in April with other colleagues and being able to debate what's going on today and where we are headed in the future.

Jon Brock is President of utility and energy advisor Desert Sky Group, LLC. Jon is also a member of the SGRS Program Advisory Committee. He can be reached at jbrock@desertskygroup.com

By Jon T. Brock, President, Desert Sky Group, LLC

March 8, 2012

Last week I attended the EUCI Risk Management Best Practices event in Chicago where I moderated a panel entitled, Making Sense out of the Data Explosion. Recently, there has been an abundance of coverage on what we are calling “Big Data” and “Analytics” associated with “Big Data.” I found this topic to be of interest because instead of focusing on the increase of smart metering data, it was focused on trading and trading technology centric organizations that are faced with converting voluminous amounts of data into actionable intelligence.

Sponsored by SAS, Ascend Analytics, and RiskAdvisory, the focus on analytics was not the “Big Data” as a result of what the industry is terming the “smart grid.” I asked the attendees if the smart grid was causing the data to grow on the trading side of the house. The answer was “no.” Instead, smart grid data was going to the utility that would then use it for building a better forecast, and the forecast was being sent to the trading and trading tech centric organizations.

The first panelist to present was Patrick Reames, Analyst and Managing Director for the Americas at CommodityPoint. Mr. Reames presented recent research on data aggregation in commodity trading and risk management systems (CTRM). The research indicated that systems specialize in a specific area, be it power/gas, crude/products, or coal, but not one system specialized in all areas. Therefore, the environment is one of multiple systems working together. Data management reporting is handled via data warehouses, data marts, price feeds, bespoke reports, Microsoft Excel, and other various tools. Of the sixty-plus organizations that CommodityPoint interviewed, the data management systems in place included LIM (Morningstar), SunGard Fame, ZE, SAS, SAP, and GlobalView. As mentioned before, the “big data” is not coming from the “smart grid.” Instead it is coming partly from increased market complexity (number of instruments, exchanges, and markets) and increasing regulatory and stakeholder oversight and regulation (Dodd-Frank being a part of this). The result is a need to have a more accurate and timely assessment of positions and risk.

The second panelist to present was Ian Jones, Senior Strategist of Energy Risk at RiskAdvisory (a division of SAS). Mr. Jones pointed out that while the growth in global data generation reaches 40 percent per year, the growth in global IT spend is reaching 5 percent per year. Relevant data is very often a small sub-set of total “big data.” The challenges associated with “big data” risk management include a lack of efficient aggregation and analysis, poor integration, and the need for more visualization. Based on a 2011 Economist Intelligence Unit Survey sponsored by SAS, 25 percent of companies believe a vast majority of their data remains untapped, 53 percent use half of their “valuable” data, and 73 percent report increased data collection. The main opportunity for “big data” risk management is getting faster, better answers. Mr. Jones shared the experience of one SAS customer taking an 8.8 billion portfolio Value at Risk (VaR) computations from 18 hour runs to less than 3 minutes. The resulting benefit was near-real time results as opposed to a day later.

So “big data” in the risk management world means something totally different than “big data” in a smart grid world. The next time you hear the word “analytics” used loosely in industry, get the context it is being used in. It does make a difference.

By Jon T. Brock, President, Desert Sky Group, LLC

Reprinted with permission from the Smart Grid RoadShow

February 27, 2012

Renewable energy and energy storage are becoming critical components of an emerging smart grid. The ability to integrate renewables in a large scale and safe manner are a high priority in the national energy picture. The National Renewable Energy Laboratory (NREL) is at the forefront of renewable integration. Late last year at the Smart Grid RoadShow hosted by AEP, CenterPoint Energy, and Oncor in Corpus Christi, TX, NREL’s David Mooney gave utility industry executives a glimpse of its work in the area of renewable integration. I recently caught up with Dr. Mooney in his Golden, Colorado office. I trust that you enjoy the insights that Dr. Mooney and NREL have on renewable integration.

Brock: Can you discuss the role that the National Renewable Energy Laboratory (NREL) plays in the energy industry?

Mooney: NREL is the only national laboratory solely dedicated to advancing renewable energy
and energy efficiency. Backed by 34 years of scientifically driven energy innovation and approximately 2,500 employees and contractors that make up an extensive concentration of leading clean energy scientists and engineers with a wide breadth of experience, NREL leads the way in helping meet the growing demand for clean energy.

NREL is the heart of America’s rich history of clean energy discovery and accomplishment – in energy science, energy technology development, and technology commercialization. Our mission is to meet national energy challenges by delivering cost effective solutions. Our fundamental scientific research is aimed at achieving breakthroughs to transform renewable energy and energy efficiency technologies. Our understanding of systems engineering and energy markets makes us uniquely suited to integrating new energy technologies into a stronger, smarter national energy system.

Brock: Please give our readers a "state of renewable integration" along with the issues you see.

Mooney: Integrating large-scale wind and solar power is ongoing, but to different degrees around the country and world. Many grids today are successfully managing high penetrations of wind and solar. During periods of low electric demand and high wind, instantaneous percentages have reached more than 50% in Colorado, Ireland, Portugal, and Spain.

To maintain the reliability we’ve all come to expect, the variability and uncertainty of renewable generation requires the remainder of the power system to be more flexible in response. Additional flexibility can come from quick-start and ramp generators (such as gas and hydro), demand control, advanced renewable resource forecasting, and electrical and fuel storage. In addition, advanced, grid-friendly features such as frequency support, low- and high-voltage ride through, and active VAR control can be incorporated in wind and solar power plants. At an incremental additional cost, these features allow more secure and reliable grid operations during fault events or other emergencies. Finally, increased use of renewable power has an impact on transmission because the best resources are location-dependent and the “fuel” can’t be transported. Therefore, many networks may require expansion to reliably achieve higher renewable levels. Transmission is inexpensive relative to capacity additions, but multi-jurisdictional issues, cost allocation, and long planning and permitting horizons can be difficult. Some progress has been made with proactive transmission by designating renewable energy zones. NREL, along with multiple partners, is aggressively researching theses issues and developing methodologies to cost-effectively integrate greater penetrations of renewable and demand side technologies.

Brock: How does NREL forecast renewable resources?

Mooney: NREL’s focus is not on directly forecasting wind and solar resources, but on developing the underlying science and techniques that allow private companies to deliver forecasting services to wind/solar power plant and utility operators. As a research laboratory, NREL works to develop new forecasting methods and improve existing weather forecasting and models with the intent of reducing the uncertainty of renewable plant output and thus reduce the cost of integrating renewables on the grid. Because wind and solar forecasting research and development requires significant investments, NREL partners with other government agencies such as NOAA, academic institutions such as Colorado State University, University of Colorado and University of California San Diego, as well as with private forecast providers such as Windlogics, AWS Truepower and 3Tier. We also partner with various utilities, system operators and plant operators. NREL also collaborates on forecasting research with a large number of international researchers, especially in Europe, to improve solar and wind forecasting. These partnerships provide significant leveraging and cost savings to U.S. taxpayers while also getting top national and international experts to work together on a difficult problem.

Brock: Can you enlighten us on the impacts of distributed generation and storage applications?

Mooney: Significant amounts of variable and uncertain renewables (non-dispatchable) distributed generation is currently being interconnected into the electricity grid. Large-scale deployment of distributed renewables will likely result in the need for more system flexibility than is currently utilized. As penetration levels of PV, for example, increase on distribution circuits, this variability could compromise power quality and service reliability. Questions that need to be addressed as penetration levels increase include:

- At what penetration levels and technology mixes will the distributed generation need to be monitored and ultimately controlled?

- How can distributed generation be controlled – externally via control signals from a centralized controller or autonomously based on power quality and/or flow sensing?

- To what extent can load management be used to mitigate or eliminate the need for control of distributed generation or for the addition of storage?

- To what extent can energy storage be used to mitigate or eliminate the need for control of distributed generation? How can the energy storage itself be controlled?

- What are the highest value uses for storage?

o Frequency regulation

o Variability smoothing

o Peak shifting

NREL is currently addressing these issues along with its partners from utilities, industry, academia, and governmental research institutions.

Brock: It is my understanding that NREL has a new integration laboratory under construction. What can you tell us about it?

Mooney: NREL’s Energy Systems Integration Facility (ESIF), scheduled to be substantially complete by fall 2012, is designed to help address challenges and reduce risks of incorporating new energy technologies into America’s electricity delivery system. Research, development, and testing conducted in the ESIF will aim to overcome a variety of challenges facing our nation’s energy system. These include challenges related to integrating higher levels of renewable energy into the electrical grid, developing advanced fuels such as hydrogen, evaluating the use of advanced energy storage technologies, and advancing electrification of the transportation system.

The 182,500-ft² facility will house approximately 200 scientists and engineers, 15 fully equipped laboratories, several outdoor test areas, and a high performance computing data center with the fastest computing system solely dedicated to energy efficiency and renewable energy technologies in the world. The laboratory will allow for rapid configuration of a variety of energy systems to conduct experiments in a controlled environment at meaningful power levels up to 2MW.

This state-of-the-art facility will enable NREL and industry to work together to develop and evaluate their individual technologies on a controlled integrated energy system platform. Participation from utilities, equipment manufacturers, renewable systems integra­tors, universities, and other national labs and related industries that fully utilize ESIF’s capabilities will dramatically accelerate the research required to transform the energy system to one that is cleaner, more secure, and more reliable, with less risk.

Brock: What are the trends for renewable energy moving forward in the near to mid-term?

Mooney: Several trends for renewables will continue to emerge in the near and medium term. We're going to continue to see large, utility-scale renewable deployments. Considerable new wind build outs, very large scale concentrating solar power, and more and more very large scale PV plants will continue to come on line as system prices continue to fall. These deployments will be driven in the near term primarily by state portfolios standards and facilitated by production and investment tax credits. NREL and others will continue to work with utilities and systems operators to enable the reliable operation of the system under high penetrations of variable generation. While these large-scale deployments continue, many new trends will emerge at the other end of the system – in the distribution system. There is likely to be more and more distributed generation deployed and integrated into the system at homes and businesses. Currently most utilities look at PV, for example, as a demand reduction technology. But there are some circuits in specific areas that are seeing penetration levels high enough to cause distributed PV to be viewed as generators, not just demand reduction. It’s in the distribution system where there are likely to be the biggest changes in the future. In addition to increases in distributed generation, there is likely to be increases in electric and plug-in hybrid vehicles along with smart grid development. Some early studies show, for example, that the uptake of electric and plug in hybrids vehicles in the market is not going to place a huge burden on central generating assets, but could cause stress on the distribution infrastructure depending on the geographic distribution and charging habits of vehicle owners. Much of this technology could enable (or require) a more active operation of the distribution systems, which would certainly be a significant change. All these new technologies coupled with changing pricing structures could lead to a tremendous amount of customer choice that could drive how technology gets adopted into the distribution system.

Brock: I'm certain that a lot of these new scenarios moving forward will end up in your integration laboratory?

Mooney: Absolutely, that's really the motivation for the new lab. We're trying to anticipate what new systems scenarios might be likely so we can configure and operate those systems in a controlled environment. In this way we can work the kinks out of the physical configurations and controls and greatly reduce the risks for new technology adoption prior to systems being deployed and interconnected. Of course this work will be done in close collaboration with equipment suppliers, utilities, systems operators, and potential end users. A good example of this is in the area of microgrids. There is a wide diversity of interests in microgrids, from utilities offering reliability services to the Department of Defense looking to energy security at their fixed bases. In the ESIF, a megawatt scale microgrid can be configured with multiple generation sources, different demand profiles, and multiple storage technologies. This type of system can be configured and run at full power in the lab where the control systems can be validated in both grid-tied and isolated configurations. The utility or DoD base will then be able field the validated system with full confidence that it will perform as designed.

Brock: Thank you, Dr. Mooney, for your valuable insights on renewable integration. We look forward to continuing this dialogue and others related to the smart grid in St. Petersburg at the Smart Grid RoadShow in April.

Mooney: You are welcome, Jon. I’m looking forward to it.

Dr. David Mooney, Director of the Electricity, Resources, and Building Systems Integration Center at the National Renewable Energy Laboratory (NREL) in Golden, Colorado. NREL is the U.S. Department of Energy’s primary laboratory for research and development of renewable energy and energy efficiency technologies.

By Jon T. Brock, President, Desert Sky Group, LLC

February 8, 2012

I have recently been covering utility billing and customer service technology issues. Last week I covered new functionality that utilities themselves are beginning to ask for when it comes to the customer information system (CIS). Many of you responded to that newsletter with feedback related to progress that has been and still needs to be made. Granted, we as an industry have come a long way with dynamic pricing, demand response, smart meters, renewable integration via net metering and net billing. Yet we have a long way to go.

One reader challenged that some of the functionality being requested by utilities require fundamental changes in how we provision customer service. For instance, why does billing need to be a batch process? Many of the new functionality require real-time billing that can support scale and allow new features such as starting new rates on any date (not just on the cycle date) and time (not just midnight). Another reader suggested that billing determinant calculations move to the “smart” meter itself. I know that the meter data management (MDM) vendors have been entertaining billing determinant calculations in the MDM, which already performs validation, estimation, and editing. Interesting that the MDM market is consolidating quickly – e-Meter/Siemens, Ecologic Analytics/L+G, and Itron and Oracle having their own MDMs.

Interacting with customers, which many are calling consumer engagement, includes new technologies such as mobile apps, social networks, smart thermostats, and in-home displays. Would you download an “app” from your utility if you could see the status of electricity, gas, water (on/off), report outages, see usage in near real-time, set a profile of commodity use in your home, and monitor the results from anywhere in the world? Would you pay for that app? In a couple of months I plan to attend the AGA/EEI Customer Service Conference & Exposition in Ft. Worth, TX (http://www.aga.org/Events/2012Events/aga-eei-cust-srvc-conf-and-expo/Pages/Default.aspx). Many of these topics will be addressed there. While I cannot do justice to the planned agenda found at (http://www.aga.org/Events/2011Events/ExecConf2011/Documents/2012%20Cust%20Serv%20and%20Low%20Income%20Conf%20Preliminary%20Agenda.pdf), a few of the general session topics include:

• Building a New Customer Experience
• Creating Do It Yourself Customers
• The Customer is Already Smart
• The State of Utility Customer Interactions
• Understanding Online Customer Satisfaction

I have been known to look at utility customer service through generational lenses, many times comparing how my own family interacts with others. Myself? I never call the utility unless I have to. When I have to, I may call the call center. Last night I interacted with Comcast via online chat on their website, which is a huge step for me. My son, who is 15 years old, would rather text than speak on the phone. He will certainly download apps to the tablet and run them until he drains the batteries (energy efficiency is a topic for another time). When will he be a utility customer? If his mom and dad are successful in getting him through college and into the job market, in less than ten years. How will the utilities interact or engage him?

Utility customer service is entering a new phase. I hope to see you in Ft. Worth.

By Jon T. Brock, Desert Sky Group, LLC

January 26, 2012

The utility distribution market is alive and well in North America.  Returning from DistribuTECH 2012, attended by over 7,000 industry participants, and hosted by the city of San Antonio, I am coming to the conclusion that utility distribution companies have a lot going on, whether they are electric, gas, or water utilities.  Granted the electric utilities have somewhat “hijacked” the event with the term we all are getting to know as smart grid (I didn’t count but must have seen the term on most vendor exhibition booths), there were still a healthy representation of gas and water utilities.

As I attended sessions and exhibits, I reflected back almost a decade ago when DistribuTECH consisted of linemen in work clothes watching demos of re-closures or other transformer and sub-station type technologies.  Now the event has morphed into attendees in business casual viewing demos that look like they have come from the recent Consumer Electronics Show in Las Vegas.   While impossible to physically visit every exhibit and attend every session, I did notice several trends that kept repeating throughout the event.

Pre-Pay

That’s right, pre-pay.  While debated many times over the course of many years, pre-pay seems to be gaining traction among utilities and even some regulators.  Last year’s DistribuTECH in San Diego released research pointing to pre-pay as a possible trend, and this year I heard rumblings (not the thunderstorm that rocked San Antonio Tuesday night) confirming it as a trend.  While at DistribuTECH, pre-pay vendor PayGo Electric announced a pilot program with Georgia Power to study the commercial feasibility of providing the option of a prepaid electric service to the company's existing and future customers.  David Elve, recently hired smart meter expert, confirmed the interest from both utilities and regulators in a pre-pay option that resides in the smart meters.

Distribution Management

It only makes sense that distribution management systems (DMS) are starting a trend upwards following a large push for smart metering and sensors on the grid.  Following a progression from substation automation to distribution automation to distribution management systems, a common piece of functionality gaining traction is the conservation voltage regulation (CVR) or Volt/VAR control and optimization.  While not new to utilities, the ability to automate it and execute it from an enterprise level seems to be reaping benefits.  Overheard at a session, Progress Energy stated that implementing a distribution management system from Telvent (owned by Schneider Electric) consisted of 10 percent of its project costs but reaped benefits in the neighborhood of 90 percent.  Voltage reductions ranged from 2.5 - 5 percent.  With numbers like that, utilities will take a hard look at the DMS as a critical part of its operation’s infrastructure.

Integration

The number of new technologies both from a hardware and software perspective is overwhelming to say the least.  Many benefits can be gained from these new technologies, but it requires a successful integration of them and other pieces of hardware and software.  Integration vendors with experience tying it all together have grown in presence on the exhibit floor.  I have vocalized that benefits from smart metering need to have integration to the outage management system; however, I have not seen many utilities that are far enough along to demonstrate a full integration.  But to my pleasant surprise, I stumbled upon Power Stream, Inc., Ontario’s second largest municipal utility.  Power Stream, serving approximately 328,000 customers north of Toronto, has fully integrated its smart meters to the outage management system.  Apparently early indicators demonstrated an annual savings of up to $250,000 CAD (not that it really matters with the Canadian and US dollar hovering close to each other) per year from reduced truck rolls as a result of outage activity alone.  It should be noted that this number will fluctuate by utility and also represents just one of the benefits of proper integration.  Getting new technology is one thing, but successfully integrating it is another.  Watch for integration efforts at utilities to increase in the coming years.

While I have not done justice to all the topics covered at DistribuTECH 2012, I note here three trends I personally saw and heard discussed multiple times at the event: pre-pay, distribution management, and integration.  I want to thank PennWell and the city of San Antonio for hosting one of the industries’ largest events and “reunions” of sorts (I enjoyed seeing friends, colleagues, clients from all parts of the globe).  Safe travels to all returning home and hope to see you next year in San Diego.  

By Jon T. Brock, Desert Sky Group, LLC

January 10, 2012

Market forecasts have indicated a growing advanced meter outlook with the U.S. market peaking and declining while other international markets pick up the new growth.  Most of these market forecasts are based upon sales or shipments but not deployed advanced meters in production.  Late last year I attended the Smart Grid RoadShow in Corpus Christi, TX where AEP, Oncor, and CenterPoint Energy gave an update of their advanced metering deployments in the state of Texas.  The luncheon panel discussed the status (as of November 2011) of the deployed advanced meters, not shipments.  At the time of the panel, the Smart Meter Texas web portal reported over 4 million advanced meters registered in the state providing 15-minute interval data to the Texas market.

AEP, Oncor, and CenterPoint Energy are by no means the only advanced meter deployments in the state of Texas.  There are many others contributing to the statewide effort including but not limited to Austin Energy, TNMP, CPS Energy, to name a few.  The luncheon panelists were Jeff Stracener, Manager AMI, AEP, Jon Pettit, AMS Program Manager, Oncor, and Corrie Morales, AMS Support Supervisor/Electric Market Operations, CenterPoint Energy.

CenterPoint Energy started with a 10,000 advanced meter pilot project in 2006 and had approximately 1.5 million advanced meters deployed with a scheduled completion date of June 2012.  AEP began looking at advanced metering in 2007 and had 400,000 of approximately 1 million advanced meters deployed.  Oncor had approximately 2.1 million advanced meters deployed on its way to 3.2 million and is deploying at 8,000 per month.

The panelists entertained multiple questions from the audience.  One such question involved what concerns you the most with your advanced metering deployment?  Panelists expressed concern over the complexity of integrating systems in order to meet market requirements.  Texas is an unregulated state and each of the panelists represents the meter asset owner, or the regulated distribution utility.  The state has many market requirements for passing data such as meter read information between market participants via a “centralized data hub.”  Ensuring that multiple systems talk to each other in a smooth fashion to meet market requirements was a major concern of the panelists.

After deployment, what are your plans to take advantage of the network you have just deployed?

AEP, Oncor, and CenterPoint Energy are all focused on successful deployments.  After such deployments, the utilities expressed an interest in analyzing the new data coming in from the advanced meters to aid in load profiling purposes.  Some expressed a need to redo and optimize business processes that change or are new as a result of advanced metering and the data it provides. 

What are the lessons from a deployment in progress at this time?

While doing a great job on logistics for deploying advanced meters, one utility expressed the need to better prepare the field technicians for troubleshooting issues that they have never encountered before.  Such issues include problems with the advanced meter itself or the network that the advanced meter uses.  Keeping the affected business units involved throughout the deployment was a good lesson learned.  Several utilities used affected business units for user acceptance testing, or what is called UAT in the information technology world.  One utility built an online training program for internal business units to access.

Customer Apathy – with opt-out talk around the country (particularly on the coasts) do we have to drag customers kicking and screaming into this?

The utilities reminded the audience that like other areas in the country, they are regulated even if they operate in an unregulated state.  Every customer engagement or training program has to be reviewed and approved by the Texas Public Utilities Commission. Customers do have concerns and getting outright acceptance is difficult.  One utility broke the concerns down into pre-deployment concerns and post deployment concerns.  Another utility argued that customers cannot be forced to adopt but could be educated.  That utility was building contests around saving energy and money and letting customer “compete” with each other as a form of education.

How do you measure success?

The three panelists expressed meeting or exceeding the expectations of multiple stakeholders.  Those stakeholders included the market, customers, and internal business units.  Some had set financial and customer key performance indicators (KPIs) prior to starting the deployment and were tracking those throughout the effort.   

While the U.S. begins to peak on advanced metering shipments, the production numbers will rise.  When the number of advanced meters put into production rise, the focus will quickly shift to what benefits they are providing for customers.  This was not discussed by the panel, but I did make an interesting observation among utilities in attendance at the Smart Grid RoadShow.  While virtually all had put in the regulatory business case a strong link to outage management, none had actually built that integration yet.  Look for integration efforts to increase at utilities that have deployed advanced metering.  Have you integrated your smart meters to outage management?  I want to hear from you.  Take a short “Yes/No” survey at http://www.desertskygroup.com.

By Jon T. Brock, President, Desert Sky Group, LLC

Reprinted with permission from the Smart Grid RoadShow

August 23, 2011

Every year the Edison Electric Institute (EEI) holds a convention to explore issues facing the electric industry from a shareholder-owned electric company perspective.   Founded in 1933, EEI members serve 95 percent of the ultimate customers in the shareholder-owned segment of the industry, and represent approximately 70 percent of the U.S. electric power industry.  This year’s event was hosted at the Broadmoor in beautiful Colorado Springs, CO and the theme was “The Power of Opportunity.”

Thomas Edison, the founder of the electric industry and the namesake of the organization is quoted to have said that “opportunity is missed by most people because it is dressed in overalls and looks like work.”  EEI has connected Edison’s original remarks to this year’s event claiming that “dressed in overalls,” the electric industry is seizing the power of opportunity by investing more than $80 billion annually to build the electric energy system of the future.  EEI also reminds it members that the production, distribution and use of electricity are undergoing a major transformation through innovation and increased use of smart technologies.

A keynote from a non-industry executive opened the event.  Former Secretary of Homeland Security Tom Ridge shared his thoughts on managing corporate risk in light of recent global developments.  Ridge shared the importance of breaking down silos.  Comparing to his experience at the Department of Homeland Security, he discussed the differences between a “need to know” culture versus a “need to share” culture.  The “need to know” culture existed in various organizations that included the likes of the Department of Defense, FBI, CIA, and the NSA.  The “need to share” culture existed in the newly formed Homeland Security Department which was trying to bring information from the various organizations that had previously operated under the “need to know” mantra.  Ridge stressed the importance of breaking down silos, incorporating transparency and honesty into the culture of a company, and speaking with one voice.  He closed with his own thoughts that the two most strategic industries in the economic recovery period that we live in today are the financial services and the electric industries from a risk point of view.     

Without covering every session in detail, the main theme that was echoed by many panelists was the need for a comprehensive energy policy.  The breakout sessions themselves included topics on solar, wind, electric transportation, regulatory issues, smart grid, nuclear generation, environmental issues, and customer needs and wants.  Many stressed the lack of a comprehensive energy policy as a major issue that needed to be addressed.  Most agreed on the need to price carbon, although differed on how to price carbon.  Most agreed that a new energy policy needed to include multiple industries.  The industries specifically targeted were utilities, oil/gas, and transportation.  Indeed, Chevy was in attendance touting its new Volt and many discussed how the introduction of EVs and PHEVs would impact their transmission/distribution grids.

The direction voiced by many at the EEI Annual Convention was one of comprehensive energy policy.  If we are going to tackle the environment and energy security, then oil/gas, utility, and the transportation sectors will be heavily involved.  Not only must we knock down the silos that exist within our industry, be it generation, transmission, distribution, customer service, but we also need to find ways to work with the oil/gas and transportation industries.  A comprehensive national energy policy would go a long way in making that happen.

By Jon T. Brock, President, Desert Sky Group, LLC

Reprinted with permission from the Smart Grid RoadShow

August 22, 2011

On April 27^th of this year tornadoes struck the Chattanooga and north Georgia areas with what is described as the most devastating storm in EPB’s 75 year history.  Shortly thereafter I attended the Smart Grid RoadShow, an event focused exclusively on Grid Transformation and Smart Grid initiatives in Chattanooga, TN.  The host utility was EPB, a publicly-owned provider of electric power serving approximately 169,000 residents in a 600 square mile area.  Addressing an executive invitation-only audience on the first evening of the event was David Wade, Executive Vice President Electric System and COO of EPB.  Mr. Wade started by asking the audience to consider history when trying to envision what the electric distribution grid would look like in 20 years.    

Henry Ford apparently asked many times what people wanted in transportation.  They would answer “faster horses.”  Wade surmises that Henry Ford is trying to tell us two things: one was that his potential customers didn't trust the car, second is that they trusted the traditional form of transportation – horses.  One thing they did value was getting somewhere quicker.  An interesting analogy when we compare that to what consumers are saying today about the smart grid, isn’t it? 

Basically we are talking about collapsing time and space.  We've used that concept before to make improvements in other industries.  Examples include the interstate highway system, airline travel, and now high speed communications.  During the birth of our own industry we had to build generation close to the load because we couldn't transport energy for long distances.  The industry innovated and developed new transportation technologies in high voltages and at the time it was revolutionary.  It enabled us to transport energy over long distances collapsing time and space. 

Wade also pointed to the computer industry.  Just a couple of decades ago mainframe computers the size of a large room were required to do what we can do today in tiny spaces.  If asked, customers probably did not ask for a mainframe on their desktop.  Instead, they were asking for cheaper computing power (remember paying by the cycle or CPU minute?).  Advances in computing power, storage, and speeds have significantly changed our world. 

If we take a look at where the electric industry is today, we think in terms of centralized generation and we interact with our customers as load.  We interact with our network when we have trouble.  We open or close switches.  We communicate over the phone or radio.  We place our trust in putting steel in the ground and building centralized generation, just like faster horses. 

What we need to be doing is thinking about the future.  Our customers may not know what to ask for.  What will happen when we have the ability to interact with smart devices all over our network in homes where there can be distributed generation?  Wade asked himself why we do not take distributed generation sources as an industry and put them on the line where they do not need to be a part of the connected grid.  Instead, we connect distributed generation in a way that it would “turn off” if the distribution grid loses power.  Sounds like dumb generation to me!  Wade stated that he would have loved to have distributed generation when tornadoes came through one area of the EPB service territory.

If we listen to the lesson of Henry Ford we could go places as an industry.  Are we going to continue to trust our horses by investing time and money in making them faster?  Are we going to blindly say that customers are not asking for the smart grid and therefore we should sit?  Or are we going to decide to do something bigger?  I would like to thank David Wade of EPB for challenging us in the audience and making us think about where we should be taking the industry.

Jon Brock is President of utility and energy advisor Desert Sky Group, LLC.  Jon is also a member of the SGRS Program Advisory Committee. He can be reached at jbrock@desertskygroup.com        

By Jon T. Brock, President, Desert Sky Group, LLC

Reprinted with permission from the Smart Grid RoadShow

May 19, 2011

The “smart grid” is so widely defined that most will not venture into a definition publicly.  It can mean different things to different individuals or companies.  I recently had the good fortune to attend the Smart Grid RoadShow, an event focused exclusively on Grid Transformation and Smart Grid initiatives in Chattanooga, TN.  On the first evening of the event an invitation-only dinner occurs with utility and energy luminaries called Envision 2030.  Speaking to the dinner guests was Erich Gunther, Chairman and Chief Technology Officer of EnerNex.  Mr. Gunther also is the founder of Smart Grid Labs, chairman of the U.S. Department of Energy’s (DOE’s) GridWise Architecture Council, among many other roles working with EPRI, IEEE, to mention a few.  Recognizing the many different paths that the smart grid is taking, Mr. Gunther revealed to the audience that in his multiple roles with various organizations there is some commonality.  The need to define a vision of where the smart grid is going in the next 10, 20, 30 years is something that all the various organizations are striving for. 

Working with the DOE’s GridWise Architecture Council, Mr. Gunther informed the audience that there are trends in the smart grid today and future that “most” can agree on.  “Most” is defined as 90% give or take a couple of percentage points.  With this in mind, Mr. Gunther proceeded to list the macro trends that will occur over the next 10-20 years.

• The global population will increase
• Natural resources will become scarce and therefore more precious
• CO2 concerns will increase
• Public interest in sustainable energy solutions will increase
• The spread of intelligence in devices will increase
• Intelligent decisions will be based on local information
• More memory and more computational capabilities will exist in end devices
• Isolated end devices will become connected end devices (communications)
• Communication speeds will continue to increase
• Cyber threats and risk will increase
• Cost of renewable energy resources will decrease
• Cost of energy storage will decrease
• Generation will become more distributed
• Transportation will change (electric powered)

Mr. Gunther challenged the audience to take a couple of these trends and start to analyze what is applied.  There are a number of things that we might have to deal with over the next 10-20 years.  For example, generation is becoming more distributed, more renewable, more variable, and electric vehicles are entering the picture.  Those elements in and of themselves even on a small scale can have a profound impact on the electric distribution system.

For a moment let’s forget about the other trends and think about re-training our work force to deal with these elements that we've never had to deal with before.  Mr. Gunther pointed out that the existing distribution design guides we have that were developed over 15-30 years ago, and were developed in such a way to quickly deploy infrastructure.  Now we are talking about a “smart” infrastructure that will have a different set of requirements put on it.  This will result in a set of best practices that will allow future engineers to quickly deploy “smart” infrastructure with a new set of applications as easily as we did previously.  

One can argue about how fast these trends will happen, but they do imply some profound changes that we need to make in every aspect of our industry.  The new devices we need, the new policies that we need in order to manage this, the new business practices we need, and the new guidelines and training we need for our work force in order to make it happen are required for us to move forward as an industry.

Many thanks to Erich Gunther of EnerNex and the many hats he wears for putting the smart grid in perspective for us.  Review this smart grid trend piece in the year 2030 to check for its relevance.  One prediction I have for that year: the electric distribution network will not be called a “smart” grid, but just the grid.

By Jon T. Brock, President, Desert Sky Group, LLC

Reprinted with permission of EUCI

February 14, 2011

Fifty-six percent utility attendance.  How many times have you heard that at an industry conference?  Of the fifty attendees at the EUCI 9^th Annual Utility Billing Conference in Las Vegas, fifty-six percent were from a utility in North America.  I could not pass up the opportunity to gather updated information from the utilities when it comes to “smart” functionality surrounding the customer information and billing systems (more commonly referred to as the CIS) in today’s changing marketplace.

The attendees (utility and vendor) broke into four groups and “brain-stormed” new functionality that will impact the CIS as a result of the “smart utility” trend.  I use the term “smart utility” because electric, gas, and water utilities were represented in this exercise.  After brainstorming, each group presented to the larger conference the results of their efforts.

Functionality Prioritization

CIS functionality has been an interesting element to track over the years.  Approximately four years ago, it was becoming virtually pointless to do a functionality checklist when selecting a new CIS because most bidding vendors would come in with the same score.  Recently with “smart” functionality beginning to creep into the check-lists, utilities must be cautious of separating required functionality from preferred functionality.  Observations from last year’s conference in San Antonio included:

·         Listen to your customers and be prepared to follow through with what they are asking for

·         Monitor new “smart” functionalities and be prepared to offer what will become required

·         Possible new “smart” functionality could include distributed generation, net metering, and dynamic pricing

·         Pre-pay electricity is becoming a requirement (and multiple ways to pay via kiosk, online, text messaging, and phone)

After the four groups in Las Vegas presented back to the larger conference, new “smart” functionality could be summarized as the following:

Hearing from the utilities themselves and not the vendor community is a welcome change periodically.  Sometimes we lose track of what the true functionalities are within the utility.  I recall all the new gizmos and gadgets we were going to deploy as an industry with deregulation.  In the end, the retailers that were successful were the ones that could get a commodity bill out first and then work on the gizmos and gadgets later.  I would advise vendors in the utility billing space to listen to the utilities and deliver on the required high priorities while toning down some of the hype around the preferred future requirements. 

Jon Brock is President of utility and energy advisor Desert Sky Group, LLC.  He can be reached at jbrock@desertskygroup.com        

By Jon T. Brock, President Desert Sky Group, LLC

Reprinted with permission from Smart Grid Road Show, November 16, 2010

Recently I attended the Smart Grid Road Show in Portland, Oregon and got a few minutes of Jon Wellinghoff’s time for a brief interview.  Named as Chairman of the Federal Energy Regulatory Commission (FERC) by President Barack Obama in March 2009, Wellinghoff was in Portland to give the keynote address at the Smart Grid Road Show, an event focused exclusively on Grid Transformation and Smart Grid initiatives.  The event’s focus and FERC’s priorities seemed to align very well as FERC has stated its top initiatives to be the Smart Grid, Demand Response, and Integration of Renewables.

After spending some time on the status of current Notice of Public Rulemakings (NOPRs) on demand response/transmission and NIST’s progress on standards, I asked about electric vehicles and the role they may play in a smart grid world.  More specifically, I asked how customers of electric cars in the future would settle an electric transaction that is occurring between a utility/ISO-RTO and their vehicle.

Wellinghoff informed me that settling is occurring now at PJM in a small pilot.  Apparently there are 7 electric cars at the University of Delaware. Settlement is occurring between PJM and the owners of those cars.  For the purpose of the experiment those 7 cars have been aggregated with a 1 megawatt battery (since settlement at PJM has to be done in 1 megawatt increments) and then PJM pays the group.  Wellinghoff expressed a desire to see it done more dis-aggregated but acknowledged that would depend on PJM’s ability to interact with service providers below the 1 megawatt level.  For purposes of the discussion the Chairman explained that it takes about 100 cars to get to 1 megawatt.  PJM is looking at the cars as tiny resources in order to help with regulation service in its jurisdiction. 

Demonstration of Regulation Services – Source: FERC

The cars have a unique address that can be recognized by PJM and PJM can tell if they are on or off so the cars do not necessarily have to be in the same place to be aggregated.  They can be located anywhere in the PJM footprint to be “virtually” aggregated.  They have the same impact on regulation services as long as they are in the same interconnect.  PJM is its own balancing authority and each balancing authority has to maintain its own frequency at 60 hertz.  The larger the balancing authority the more dispersed the resources can be.  Generators have historically provided the regulation services but in much larger volumes. 

Regulation Service While Charging – Source: FERC

A couple of things came to mind during our conversation.  If the PJM experiment holds and the industry will settle transactions between ISO-RTOs and electric car consumers for regulation services, will there be “roaming charges” when travelling outside an ISO-RTO footprint or just no regulation service?  Are the ISO-RTOs now becoming, for lack of a better term, the “network” area?  And while this experiment focused on regulation service in a control area, where are the specific utilities and who is responsible for the billing of the services? 

There are a lot of unanswered questions when it comes to the electric car but we can be assured of one thing.  The smart grid will change the way we live.  It is an exciting time to be a part of an industry that is changing rapidly.  I would like to thank Chairman Jon Wellinghoff for taking some of his valuable time to discuss the smart grid and electric vehicles with me and for his continued leadership at FERC.             

Jon Brock is President of utility and energy advisor Desert Sky Group, LLC.  He can be reached at jbrock@desertskygroup.com

By Jon T. Brock, President Desert Sky Group, LLC

August 13, 2010

Is it just me or do the organizations represented on this panel held at the Aspen Institute’s Environment Forum in the last week of July strike you as quite interesting?  Perusing the agenda for which sessions to attend, this one certainly caught my eye as an after lunch must-attend plenary session.  Held on the grounds of the Aspen Institute in beautiful Aspen, Colorado and sponsored by National Geographic, Chevrolet, Duke Energy, and Shell, I certainly had pre-conceived ideas of where this panel was heading.

Moderated by Joel Achenbach, staff writer for the Washington Post, and sub-titled The Rhetoric and Reality of Offshore Oil Resources, Shell began this lively debate by giving its perspective of off-shore drilling safety.  Elizabeth Cheney, vice president of safety, environment and sustainable development for Shell Upstream Americas stated that Shell can and does drill safely in deepwater.  Ms. Cheney also informed the standing room only crowd that Shell had recently joined a consortium of oil companies such as Conoco Phillips, Chevron, and Exxon Mobil focused on containing oil spills in the Gulf of Mexico. 

Bringing a research angle to the panel, Mr. Robert Gagosian, president and CEO of the Consortium for Ocean Leadership, noted that data is being collected by both sides (BP and the U.S.) in a litigious manner.  Litigious meaning that there is no transparency or visibility into the data being collected but to be used at a later date in legal proceedings.  Mr. Gagosian is advocating an ocean observation program that is transparent and open to all.  He also clarified that collecting data in one “instant” is not advisable as the scientific process takes time and the data must be collected over long periods of time in order to measure the true impact of such a “spill” in the Gulf.

Former U.S. Secretary of the Interior from 1993 to 2001 Bruce Babbitt was quite vocal in his opinions that this type of accident will happen again unless there is a radical re-structuring of regulatory oversight.  Mr. Babbitt is pushing for an independent agency similar to how the NRC has regulatory oversight in the nuclear industry.  For certain there are agencies responsible for regulatory oversight in the offshore drilling business today but there was much debate over its effectiveness and independence.  Mr. Babbitt believes the industry to be effectively un-regulated in its current state.

Finally it was Hollywood’s turn.  Kevin Costner, who needs no introduction, has visited the Gulf and informed the audience that there were no words to describe what is happening in the Gulf.  Mr. Costner also made a strong point that this is not “our” ocean, but belongs to others as well.  It turns out that Costner co-founded a company known as Ocean Therapy Solutions and in 1993 purchased a patent from the Department of Energy and invested $24 million after tax of his own money to perfect a centrifuge that would separate oil from water at high speeds.  His goal is to stop the recurring scenes of oil clean-up on beaches that we all saw after the Exxon Valdez disaster.  After much hardship trying to commercialize and get his machines approved by various government agencies, BP has purchased 32 of them and currently has 13 of them out in the Gulf.

All in all it was a very insightful panel discussion and in my opinion was one of the highlights of the Aspen Environment Forum.  Can oil companies drill in deep water safely?  Probably.  Should they be allowed to “police” themselves by forming safety consortiums?  Probably not.  Do we need more transparency in collecting and distributing data from the Gulf and other environmentally sensitive areas?  Absolutely.  Should the U.S. have an independent regulatory agency with strong oversight on this type of drilling?  Yes.  Will there be another accident?  Of course.  Should the U.S. government allow new technologies to aid in the clean-up of future spills?  The answer is a resounding “yes.”   

By Jon T. Brock, President Desert Sky Group, LLC

July 23, 2010

In today’s smart grid world, we hear a lot about the benefits of the various smart grid technologies and how they will empower consumers to better control energy usage.  Approximately 80 percent of stimulus funds aimed at the smart grid have gone to projects that ultimately “touch” the consumer in one way or another.  Be it smart meters, advanced metering infrastructures, dynamic prices, and the like.  These projects indeed have merits and will ultimately change the way we use energy but has the market overlooked other possibilities that optimize the electric distribution grid without the need to educate the consumer?

Without getting too technical, the industry agrees that it was built primarily without efficiency in mind.  In fact, the electric grid was designed to handle a “worse case scenario.”  Take the hottest day of the year, assume all air conditioning and electrical equipment is running and then design a grid that can reliably handle that without having to do rolling black-outs.  Granted, generation plant-siting does take efficiency into account.  However, we are entering an age where distributed forms of generation will become a reality and will become a major issue for distribution grid operators if a smart grid-like communications infrastructure is not present.

So is there a way that electric distribution grid operators can optimize without touching the consumers and thereby reduce load?  Certainly.  Those who operate electric distribution grids know the answer.  They have been doing it for over 10 years.  It is known as Volt/VAR control.  Historically it has been somewhat of a manual process, making adjustments at capacitor banks based on various readings coming in from around the network.  However, in a smart grid world, the communications infrastructure will enable more readings from more nodes on the network in a near real-time model.  Having access to this data enables engineers to better optimize the grid as opposed to adjusting the network and then waiting for results to come back. 

A number of utilities in North America have measured load when running Volt/VAR control and optimization exercises.  Results range from a load reduction of 1 percent to 3 percent, depending on several factors.  This occurs without harming reliability and without the consumer’s knowledge.  No smart meters, no advanced metering infrastructure, and no dynamic prices.  So now the question is where should this technology reside?  Is it a stand-alone technology or is it a part of a larger distribution management system (DMS)?  I want to hear your thoughts.  Please visit my homepage and let me know what you think by checking your answer on the lower left side of http://www.desertskygroup.com.  Results are displayed as the poll is taken.

Jon Brock is President of utility and energy advisor Desert Sky Group, LLC.  He can be reached at jbrock@desertskygroup.com

By Jon T. Brock, President Desert Sky Group, LLC

July 16, 2010

Is Duke Energy converting its business model from selling a commodity to selling a service?  That was the question I posed to Jim Rogers at a roundtable discussion held shortly after his keynote address at the Smart Grid Road Show earlier this year in Cincinnati.  He was preparing to head to Washington D.C. for the release of the Kerry-Lieberman Climate and Energy bill and was gracious enough to give several energy media/analysts 60 minutes of his valuable time.  The question gave him pause, as he contemplated how to best describe one of North America’s largest electric utility’s business in a changing industry. 

To put the changing industry in perspective, he asked us to go back to Thomas Edison and the Pearl Street power station.  The power station on Pearl Street went into operation in 1882 in New York City and is considered to be the world's first central electric generating station. It was built and operated by the Edison Electric Light Co., founded by Mr. Edison.  The purpose behind this innovation was not to provide the Internet, MRIs, air conditioning, refrigeration, televisions, radios, gaming consoles, and the like.  It was a rather simple purpose.  The main purpose was to provide lighting, as the name of the company infers.  Rogers then asked us to consider where we are today with the smart grid and what the key benefits are in 2010.  Whatever those benefits may be, outage avoidance & restoration, avoiding truck rolls, providing consumers the flexibility in controlling energy use, or shaving peak load, we cannot quantify what the smart grid will enable in the future because we simply do not know what it will enable. 

One of the other analysts in the room asked the question we all wanted to ask but hadn’t.  It was one of regulatory recovery and approval of smart grid investments.  Rogers stated that he was old fashioned in that he puts full responsibility of getting regulatory approval upon the shoulders of the electric utility industry itself.  His position is one of working with the technology providers to create a narrative of sorts that will sell the benefits of smart grid to the regulator.  It will not be an easy road since we do not know the full benefits yet but is one that is not impossible.  He went on the state the challenge in a different way.  The electric generation fleet in the United States is aging and will need to be replaced in the next 30 years.  Couple that fact with new transmission/distribution investment and a potential carbon tax and you have rates that are going to increase.  Knowing that electric rate increases are coming, we need to get the regulatory regime right and invest in energy efficiency while putting into our consumer’s hands the ability to control usage first.  If we do that as an industry then the consumer’s level of frustration can be somewhat minimized as opposed to having no control over usage.

So back to the question.  Does Duke sell a commodity or a service?  After careful thought and background, Rogers replied that Duke is in the business of optimizing the use of electricity.  To be more precise, the electric utility’s purpose is to provide kilowatt hours in such a way to optimize the consumer’s usage in order to invest in productivity gains in their usage.  How we as an industry optimize the system within new boundaries being set by the smart grid will lead to productivity gains in the usage of electricity.  We have to define this new business to the regulators and educate our consumers.  It is no small task but is also not impossible. 

By Jon T. Brock, President Desert Sky Group, LLC

May 4, 2010

Many have compared the smart grid to the Internet, claiming that what we are doing is building an “energy Internet” of sorts.  With that in mind, some also claim that we are building this “energy Internet” differently by service territory, which makes it difficult if not impossible to optimize asset performance on a holistic scale.  If that is the case, then why don’t we take a step back and look at this on a country or even continent basis as opposed to city, state, regional basis?    

I recently had the good fortune to interview a smart grid luminary, Mike Davis, Associate Lab Director, Energy & Environment for the Pacific Northwest National Laboratory (PNNL) on issues related to the smart grid, differences by global geography, and ideas on how to improve a smart grid implementation for success.  Mike will be joining myself and three other industry luminaries at the Smart Grid Road Show (www.smartgridroadshow.com) to be held May 11-12, 2010 in Cincinnati, Ohio to discuss in more detail smart grid experiences and future looks.  For now, I trust you enjoy this interview with Mike.

JB:  Let me start with the first question.  Please share with our readers the background of PNNL and its role in the smart grid world.

MD:  Pacific Northwest National Laboratory is an US Department of Energy (DOE) government research laboratory run by Battelle Memorial Institute and is located in Eastern Washington.  At the laboratory we are home to over 4,700 scientists, engineers and support staff dedicated to delivering breakthrough science and technology to meet today's key national needs.  I am responsible for running the laboratory’s Energy and Environmental Directorate that is comprised of approximately 1200 staff and scientists with an annual investment stream of over $300 million in funding surrounding PNNL’s energy and environmental mission.  Our foray into what the world now knows as “Smart Grid” is an interesting one and for PNNL goes back a long way.  Here in the Pacific Northwest there has been an interesting energy model in that the Bonneville Power Administration (BPA) has been moving power over long distances for a long time.  To do that efficiently, BPA needed to know what was going on regionally as well as needing the “ability to see” circumstances at the southern end of the Pacific intertie, if you will.  So beyond “seeing” inside the regional territory they needed a larger view beyond local service territories in order to understand capabilities surrounding both supply and demand.  Coincident with that, ten or fifteen years ago, some of our scientists and engineers supported  BPA to develop new high performance monitoring systems  to “see” and “status ” the Northwest’s energy infrastructure system over a wide  area  in support of major  transmission lines moving power from the Northwest into California.  As we fast forward to today’s “Smart Grid” developments, we are building knowledge in terms of what's going on across the Northwest energy system at a greater level than if you were just trying to manage a single service territory.  This is a fundamental shift in thinking; revolutionary in fact when we think about a ‘bigger view’ or a ‘more real time view’ or even a ‘bi-directional view’ of energy by way of consumers or net generation sending signals from the demand side back to the supply side.  These are shifts that our infrastructure was not designed to handle but hold great potential if we can successfully deploy these new  “Smart Grid” technologies and functionalities.

So, when I arrived at PNNL, we had several researchers that were well into “wide aware intelligent knowing and viewing”.  This capability and the insight it could provide for all parties concerned with grid planning, operation and even regulation, seemed to me to be key to the future of the utility industry.  But, neither the laboratory nor industry had a platform to do the work or realize the benefit of this type of “viewing”.  With “Smart Grid” now coined, we can use terms such as sensing, monitoring, measuring and/or validating energy flows throughout our transmission and distribution system (our electric infrastructure) and with these new capabilities, actually see our electric infrastructure operating in near real time.    However, to place the maturity level of these capabilities  on an ‘adoption curve’,  today many utilities still rely on customers to call the call center to tell them their power is out.  It’s really unimaginable.  So in terms of adoption curves, we are very early in, even now. 

JB: So PNNL was an early developer in this space.  What is your definition of smart grid?

As noted above, PNNL was very early into knowing and experimenting with “SmartGrid”.  So, what is smart grid to PNNL after our decades’ long journey in this space?  It’s the intelligent infrastructure that enables real-time multi-directional sensing, monitoring, measurement and, ultimately operational control  to deliver all the things that matter to us – reliability, ubiquitous communication (without cyber security compromise), safe, optimal and most efficient energy delivery, “best source” generation enabled without undue shock and volatility to the system that includes new generational forms, and enabled consumers who can manage demand and net generation that can give back into a system that MUST STAY IN BALANCE.  Balance with signals and power flowing from both supply and demand sides  is very different than balance we have been maintaining in a one way supply to demand world.  This is a big shift. 

JB: Being in so early with so many resources focused on energy infrastructure understanding and scientific breakthrough through sensing, monitoring and visualization of the infrastructure – is this where the EIOC came from – the Energy Infrastructure Operations Center at PNNL?  And, how do you see this type of resource being utilized on behalf of the nation surrounding energy transformation?

What we did at PNNL was take the talent of folks who had been doing this for so long in the Pacific Northwest and partnered that with what we knew about climate, then combined that with what we knew about energy infrastructure operating systems and the supporting technologies to enable all that and built a platform that to a utility looks like their control center but in fact is a “real-time wide area view” of US electric infrastructure across much of the United States.  With this platform, we utilize phasor data in concert with industry standard software tools to test new smart grid concepts as we observe the grid in near real time dynamic operation.  This platform is what we call our Electric Infrastructure Operations Center (EIOC).  Here we are able to show industry stakeholders, policy makers, members of Congress and other leaders, a data driven dynamic view of US electric infrastructure, not previously available to them.  We can now show folks through visualization techniques, ”traditional views” of the system, such as  the status of devices, substations, generators, etc. and then show them  a  dynamic view of the larger system  including power flows.   When we  show folks real time or very close to real time power  flows, they can not only visualize electric  infrastructure in such a way that they get a whole lot more information out of the system, but they can also see new business models that are not so far out of reach.  Within the EIOC we're taking energy infrastructure data to knowledge in a way that a utility can't.  Most utilities do not have a spare control center that they can run experiments in.  They have to see their own model and data, and the models produce information and eventually that enables planning and rate cases and more all within that utility’s defined parameters.  At a national laboratory we are not limited by these parameters; we can do this in real time way faster than any utility can because we are not bound by the constraints of a utility business model or their current sensing technology, but at the same time, we are reflecting their actual infrastructure and operating dynamics.    This approach demonstrates some of the important  power behind new public private partnerships in this space and the power of knowledge coming out of ARRA funding as long as we all continue to ask – what are we learning and what knowledge is being extracted from these  experiments/projects in the field?  The laboratory complex can greatly strengthen and shorten learning cycles and also assist in the R&D lift ahead of us all as we beneficially transform US electric infrastructure, business models and consumption patterns of our citizens and businesses.

JB:  So, what big “ah-has” are you seeing through the EIOC?  What can it teach us?

We have demonstrated out of this platform that we can actually dispatch demand response programs and demand management programs over the internet without using current utility assets and reduce demand as well as consumption.  We believe you can actually control demand, you can aggregate demand to the point of dispatch-ability so that it is a real asset and dispatch it back against the supply side, all in ways that are acceptable and valuable to the end user.  Now, we are beginning to think that you can actually look at supply and demand in near real time and use demand assets just like you would supply assets to be much more productive, thus realize much better asset utilization across everything that touches an electron. 

JB:  I have two questions based on that.  One, you mentioned the phasor data.  Would you be able to pull in phasor data in a non-smart-grid world, or did smart grid enable some of that?  Or is the phasor data that you are pulling already in existence, you just had to identify those and get access to them?

MD:  Already in existence.  It was one of the early uses of computers and high performance digital devices in the power system.  BPA and a few western utilities began implementing these networks in the late 80’s / early 90’s.  I think some of the early work here at PNNL linked this early phasor work with energy efficiency experience and deep understanding of how buildings systems use energy to begin evaluating the ability of smart end use control to improve grid reliability and performance.  What it actually came out of was the whole effort to enable better asset utilization with additional functionalities.  Some of those additional functionalities are just better data and faster rates and synchro-phasors have been part of that long before we popularized the concept of smart grid.

JB:  And I do see some of those synchro-phasors in the stimulus money.  It appears they are going to put more of them around.

MD:  Well, that is fully consistent and maybe in a small way an outcome of some the white papers and thought leadership that we have produced. PNNL has been substantially engaged in the national phasor activities with DOE and leading utilities.   We've been navigating this space for some time, and if you really want to understand transmission at the interconnection scale, you must be able to see well beyond individual service territories in near real time.  Grid operators engaged in wide-area reliability activities will be better able to aggregate the phasor deployments as they become larger and more widely distributed and placed.  We will support these activities as they unfold.  We are very happy to see this happening because I candidly believe that for a couple of hundred million dollars you can have a phasor network across North America that gives us asset utilization on transmission like we've never had before. 

JB:  I heard you mention on the demand side a lot of smaller devices making up a large amount of load.  I know that group contains the electrical appliances.  How about electrical vehicles?  Do you have anything going on in that area?

MD:  We've looked at that at an initial level and based on current installed capacity, we believe there is enough capacity to handle about 70% of our light duty vehicles based on the current characteristics in terms of energy it takes to move the current fleet, not necessarily new lighter or smarter cars, but 70% of the automotive power that it would take to support the current light duty fleet.  That could be done by filling valleys off peak across the U.S. on a state by state or region basis.  If we took this approach, there would still be an improvement in emissions, even though you burn more coal, these plants are more efficient in aggregate than the corresponding conventional vehicles.  You have to manage the charging, absolutely, but the energy demands of 70% of the light duty fleet are in fact available to us.  We have reports out on that.

JB:  You mentioned the Northwest and even some national activities.  What geographies do you play in globally?  Does PNNL play in the global energy picture?

MD:  We do to some extent in China.  Some of our team is currently working with Chinese grid companies.  They are building a national network that we're talking about.  They are using phasor technology to be able to manage their entire transmission infrastructure.  The advantage they have is that they are using our technology but they don't have to deal with mismatches between state and federal regulation.  They don't have to deal with 3,200 different service territories.  They have essentially one decision maker, their own government.  Basically, that lets them take our technology and simply move it into the market place at a much higher rate without all of the barriers and delays associated with whether it is federal or state regulation, and whether it is whose electron or the color of that electron.  They can simply say, “We know we need loads of electricity, and we know we're going to have a large system to deliver, and let's build it.”  So, they are deploying, at least in the transmission level, our technology faster than we are. 

JB:  Fascinating.  So does PNNL help them with the learnings from the synchro-phasors and the control center?

MD:  Yes, consistent with open literature and findings, our engineers exchange views on data acquisition and visualization tools via forums like IEEE and utility organizations.

JB:  You may have answered this in the first question indirectly.  What areas or what part of the smart grid does PNNL play in?  The areas I've listed here are policy, generation, transmission, distribution, and the consumer.

MD:  I think it's really probably more so in transmission, the consumer, and distribution.  You know Battelle, which operates PNNL, is part of a team that recently won the Northwest Smart Grid Demonstration Program, which is $178 million demonstration.  It is built around BPA plus twelve other utilities, including various key vendors.  What we really did as a region in that demonstration was design experiments, if you will, around all the various smart grid functionalities across utilities and across five states.  The data from which will flow back through our EIOC. The objective is to find out what the real value proposition is and what the real business case is for all these various functionalities as they are deployed into these utility service territories.  So we think as a team, we have the right experiments ready to deploy and test over the next five years.    What will come out is knowledge that will be transparent and publicly available in terms of how these experiments performed and the real value delivered.   The first year and a half of these projects are installation, and then the next two and half to three years will be measurement, monitoring, and validation.

JB:  From your perspective, what are the main objectives of a smart grid?

MD:  For me, it's the ability to deliver affordable, clean, and reliable electricity.  The assets have to be utilized on a system wide basis, not just a service territory basis.  The assets also have to include the demand side even though the utilities don't own those.  The assets that consume electricity can be just as important as the assets that produce and deliver electricity.  So broadly speaking, it’s realizing asset utilization far superior than anything this industry has known before in the context of ever increasing demands for low carbon electricity. 

JB:  So what you are saying is it should cross boundaries from ISO to ISO?

MD:  Yes.  Another way to think about it is where would we be if we were trying to develop 3,200 different internets?  Because we have roughly 3,200 different electricity service territories, how can you come up with anything close to asset optimization when the whole system was built on a service territory basis and a return on invested capital?  In the future, we might do better if we operated on a return on asset performance and could actually include both supply and demand assets.  A return on invested capital was a great way to build the system, but that may not be the best way to optimize assets over the long term now that we are trying to build a network out of the whole thing. 

JB:  That's right.  With that in mind, let me shift to a negative question.  What are we doing wrong in rolling out the smart grid right now?

MD:  Well, I guess it's not so much about what we are doing wrong, but maybe we are not realizing the full challenge.  We're focused a great deal on technology, but I think the challenge is actually lesser in the technology space and more in the policy and business model space.  You hear the term all the time “the low hanging fruit”, or “fruit on the ground”.  Then the question becomes, why is that the case?  In fact, there is more technology out there than the market place is picking up so what is the real incentive for developing new technology?  Your time line if you are in the private sector trying to develop new technology is a killer.  I think the technology pickup is very slow because given our business models and regulatory structure; we're still trying to optimize service territories, rather than the entire system.

JB:  Yes, we're still focused on home.

MD:  Yes, we're primarily focused on the supply side of each service territory.  The reality is that each service territory has a geographic boundary, a regulatory boundary, and a balance sheet boundary.  These boundaries all dramatically constrain system wide improvements.

JB:  So, do you believe that is a similar challenge globally.  I've heard you say earlier that is not an issue in China, because they have one service territory. 

MD:  Right, while China does have more than just one service territory, they can act as if they have only one service territory.  They can bypass our local, state and regional policy, regulatory and business model constraints and say we're going to build a national grid based on the national benefit.  We took similar action when we built our interstate highway system and our global internet.

JB:  I won't ask if we should nationalize transmission.  I'll save that for the conference.

MD:  I'm not going to say we should nationalize transmission.  I'm going to say if the desired result is to have a national grid then we probably need to change our approach, or certainly our willingness in terms of how we cooperate to produce it.  Now, we could cooperate and bend if we chose to, but our tendencies are to hold on to our service territories, our traditional legalistic approaches to managing or avoiding change and our current business models.  I may well be in the minority, but I believe that until we effectively change our current business models, building the electric infrastructure best suited for our future is going to be a slow go.

By Jon T. Brock, President Desert Sky Group, LLC

April 28, 2010

The smart grid has gone global.  It may mean different things to different stakeholders and may also vary based on geography.  Cultural differences across the globe will impact how consumers adopt what we as practitioners are calling the “smart grid.”    

I recently had the good fortune to interview a smart grid luminary, Don McConnell, President for Battelle Energy Technology on issues related to the smart grid, differences by global geography, and ideas on how to improve a smart grid implementation for success.  Don will be joining myself and three other industry luminaries at the Smart Grid Road Show (www.smartgridroadshow.com) to be held May 11-12, 2010 in Cincinnati, Ohio to discuss in more detail smart grid experiences and future looks.  For now, I trust you enjoy this interview with Don.

JB:  Let me start by asking you to share with our readers the background of Battelle and its role in the smart grid world.

DM:  Battelle has been involved with a broad series of energy issues for a long period of time and two different vantage points.  One is that through our role in management of six of the Department of Energy’s National Laboratories. Through the labs we have been engaged with development of many of the fundamental aspects of the smart grid going back to actually the late 1990’s.  Our efforts span the development of the Phaser grid observation systems that was done by the Pacific Northwest National Lab to the design and execution execution of the GridWise demand management trial, to the Enterprise Demand Dispatch engine developed by Battelle Energy. Battelle Energy Technology is the commercial side of our activities on the smart grid. 

Across our portfolio today, we're engaged in aspects of visualization and real time monitoring for transmission all the way through demand management and real time integration of renewables through distribution systems.  It's fairly a wide swath with a particular focus now on the commercial side on the demand response and distributed resource integration.

JB:  What geographies does Battelle play in?  Is it limited to the United States or is it a global look.

DM:  Battelle is engaged in smart grid activities in multiple markets.  In the U.S, we are engaged both in the east and then western grids in projects spanning the implementation of real-time interactive hierarchical smart grids from the wholesale level down to the utility and from the utility to the individual consumer.  In China, Battelle Energy’s smart grid leadership has been engaged in planning for the smart grid in China at the strategic level.  Our smart grid planning for renewables integration for major renewable portfolio standards development has focused on island power applications such as Ireland in terms of integration of renewables and distributed resources.  Our current efforts are dominantly focused on North America.

JB:  You may have answered this in the first question, but what part of the smart grid does Battelle play in?  The areas are policy, generation, transmission, distribution, and the consumer.

DM:  The area that we deal with here dominantly real-time management of transmission, distribution, and the consumer interface with a particular focus on how the consumer interacts with the emerging smart grid system.

JB:  That's going to be a hot topic going forward.

DM:  The consumer interface is one of the major challenges for implementation of smart grid systems, particularly as the current grid serves consumers so reliably and well that consumers largely need not pay attention to their interface with the grid.

JB:   Absolutely.  From your perspective, what are the main objectives of smart grid in the electric industry?

DM:  I think if you look at a smart grid and what it can provide, the implementation of intelligence at a distance and two way communication as to the status of the grid enables increased awareness as to what challenges an electrical network is facing on a near real time basis. This in turn allows improved operational effectiveness and efficiency as far as the utility is concerned and improves experience for the customer, especially in avoiding and responding to upsets to service. Basically, it enables a system that is much better at balancing how the grid system operates and therefore remains responsive to the needs of customer for reliable and affordable power while avoiding both overbuilding for contingencies and the risk power shortages. 

I think the key to achieving these goals is the capacity to employ intelligence at a distance to enable fundamental changes on how we manage electrical power and how consumers react to management of power.

JB:  So do you think that is different when you look at a utility vs. a consumer?

DM:  I think the value proposition differs substantially on both sides of the meter. To some extent, we haven't quite paid as much attention to that as what we might have wanted. 

To the utility, there is a whole spectrum of benefits of a smart grid that allows for better situational awareness, the ability to have a more integrated response in real time, the ability to integrate distributed resources to avoid congestion and to maintain voltage on lines at times of peak demand.

When you speak to consumers about the smart grid, one of the big challenges we have is that the existing grid systems is a remarkably reliable system. Most people don't worry about electric service, except under exceptional circumstances like storm damage or some other unusual event causes an interruption to their power.  Also, with most consumers isolated from the actual cost of providing power at any given instant, benefits of avoidance of peak power prices is absorbed at the utility level and are never sensed by the average consumer. Consequently, improvements in grid utilization to avoid congestion and the integration of distributed energy assets to support power flows are invisible to the consumer on a day to day basis. The real question for most smart grid activities is how benefits to the consumer can be made visible. 

That question enters the deliberations of public utility commissions in terms of explaining what the advantages of the smart grid will be to the average consumer. Smart grids require enlightened consumers to be fully effective and that is one of our great challenges.   

JB:   Let me ask a negative question.  Are we doing something wrong in rolling out the smart grid?

DM:  If we are making a mistake, and we are probably in this early stage of this process, is that we're not paying enough attention to how consumers will react and respond to the changes that the smart grid will entail.  If you look at some of the unsuccessful attempts to implement aspects of smart grid, even things simple as automated meter reading, the real issue as they roll out is how do we engage the customer.

 For smart grid to be totally effective and realize the potential that we describe in glowing terms, it requires all the aspects of smart grid technology a smart infrastructure including the ability to collect and respond to real-time information, a secure system for communicating and the means for interacting with both consumers and power providers to more effectively manage the grid system. However, it also requires an enlightened customer, and an informed regulator who understands what this technology means in their particular environment. 

Right at the moment, the customers and the regulators are still just beginning to understanding what a smart grid is likely to mean. Consequently, if there is a shortfall it is that I don't think we've done nearly as good of a job in engaging the customer in terms of what this is going to mean to them and how they respond to it.

JB:  It sounds like we've got some education to do here.

DM:  I think that is the key to broad acceptance going forward and quite frankly it has to move from speaking “technish” to people about technical changes that they can’t see and instead focus on providing clear statements of the benefits they will see individually and collectively in terms that are important to them.  So, I think the real challenge from the customer’s viewpoint, is articulating a value proposition defining what the smart grid represents to them.  I think this is an area that we've just begun to scratch the surface of terms of how to interact with the customers.

JB:  Is that a North American issue or is this different by global geography?

DM:   It's definitely a North America issue particularly because we've treated utilities and power generation as a commodity purchase, not a consumer product purchase.  You would go about engaging with your customers that completely differently if you considered electric service to be a customer service or a customer product as opposed to commodity.  I think we see elements of this in other places, but they tend to reflect the local cultures that exist.

China has a very different situation relative to what customer expectations are as many of them are really receiving power for the first time.  Although I think here and in Europe, we have comparable sorts of dynamics, I think the process of engagement is somewhat different depending on what the local cultural responses will be.  Consumer responses differ depending on socio-economic and other social anthropology characteristics of any given market place.  We’re certainly anticipating that here in the implementation of Grid Smart here in central Ohio.

JB:  It sounds to me like we've got a difference of cultures, and you bring up a good point that if we are going for consumers who are use to a reliable commodity purchase to smart grid, it is one set of education but if you are leap frogging and going to a set of customers who have never had electricity, it may be a little bit easier to go into something and educating those customers because they are used to less.  

DM:  I think that's a fundamental issue. Quite frankly, I anticipate we will see public attitudes continue to evolve as the value proposition of the smart grid emerges in the public mind. This will be greatly accelerated once we start seeing implementation of differentiated consumer services emerge such as plug-in hybrid charging where the smart grid is essential to consumer satisfaction.  Over time because expectations are going to change on the consumer's behalf as new functionality is delivered via the smart grid.

JB:  That's all the questions I had for you Don.  I want to thank you for your time and I do look forward to the panel in Cincinnati in early May where we can sit down with our colleagues and actually discuss this in further detail.

By Jon T. Brock, President, Desert Sky Group, LLC

April 23, 2010

The smart grid has gone global.  It may mean different things to different stakeholders and may also vary based on geography.  While North America appears fixated on getting into the consumer’s home, Europe appears to have started focusing on the distribution technologies, while Asia is learning from other geographies on where to put its priorities.  Alexander Graham Bell would not recognize what we have done to the telecommunications industry he helped father while Thomas Edison would totally recognize the electric industry of today.  Interestingly enough, the new smart grid world may involve the convergence of these two industries leveraging an information technology industry that did not exist when they were born. 

I recently had the good fortune to interview a smart grid luminary, Ray Gogel, President & Chief Operating Officer for CURRENT Group, LLC on issues related to the smart grid, differences by global geography, and ideas on how to improve a smart grid implementation for success.  Ray will be joining myself and three other industry luminaries at the Smart Grid Road Show to be held May 11-12, 2010 in Cincinnati, Ohio to discuss in more detail smart grid experiences and future looks.  For now, I trust you enjoy this interview with Ray.

JB:  Please share with us the background of CURRENT and its role in a smart grid world.

RG:  Sure, CURRENT is an early software and hardware pioneer in smart grid technology.  We've been recognized with numerous green tech awards, and we have a quickly growing clientele in some of the largest utility companies in Europe and North America.  What we do is provide low-cost, easy and quick-to-implement distribution management solutions which improve both the efficiency and reliability of the grid and help the grid address the increasing volatility that is coming into it.  We do this, Jon, by strategically placing sensors which, combined with enterprise software, improve power factors and dynamically manage voltage, thereby providing transparency, automation and control of the elements and events on the distribution grid. That is really our North American solution. This solution provides 3-5% reduction in load which you might well call “consumer-less energy efficiency”. Aside from the reduction in fuel costs and carbon emissions, it also has positive impacts in terms of reducing customer complaints and service investigations and, as I mentioned before, increases the utility operator’s ability to handle volatility that is an ever-increasing part of the industry’s future, as renewables and distributed generation are added into the grid.

JB:  You did mention a North American solution.  What geographies do you play in globally?

RG:   We play in North America, Europe, and increasingly we are providing solutions to the Asia Pacific arena, as well. Most people are aware of the pivotal role which CURRENT played in SmartGridCity™ at Xcel Energy. That formed the cornerstone for both global product lines, but each of these geographies requires significantly different forms of functionality.  Coming out of SmartGridCity™, we learned that dynamic event management on the distribution grid in North America can be done by strategically placing sensors on the grid and combining them with enterprise software to improve distribution power factors (volt/VAR) and provide dynamic voltage optimization, as I noted earlier.  In Europe and AP, utilities want our solutions to do that—and much more.   Europe, in particular, needs complete transparency and control on the grid, so we also do “grid to ‘edge’ [i.e., consumer] integration” with metering, leveraging the evolving universal standard of PRIME.  In this way, we ‘light up’ the entire distribution grid, gaining actionable sensor information from both meters and transformers.  This is pivotal to handle both the increased volatility associated with central site renewables as well as for the incorporation of distributed generation into the grid

JB:  Ok.  So if you had to take the areas of the smart grid, which areas do you play in?  Let me read them to you.  There is smart grid policy, generation, transmission, distribution, and the consumer.  Ray, what areas does CURRENT address?

 RG:  I think all Smart Grid service providers have some tentacles into the policies domain because we're all really helping to reshape the nature of the electric industry.  But when it comes down to naming the traditional verticals within the utility space, we are clearly focused on distribution.   It is an oxymoron to talk about Smart Grid without focusing on distribution.

JB:  Ok, and I did hear say you earlier “consumer-less energy efficiency”?  So what you are saying is that you actually have the ability to increase energy efficiency without touching customers?

RG:  Absolutely – the energy savings are 100% in control of the utility and immediate.

JB:   So what are the main objectives of a smart grid from your perspective?

RG:   The goal of the “smart grid”, and what it ultimately helps the industry address, are some of the invalid assumptions that are embedded in our electric industry and, as of the 21st century, are no longer valid.  Assumptions like:

ü  Energy is so cheap that it is okay to waste it, 

ü  Or that carbon and other forms of pollution have no consequences for our planet. 

ü  Or that supply and demand doesn’t have to be managed as a continuously flexing, holistic phenomenon but can be looked at and managed separately in silos. 

ü  Or that analog speeds and manual interventions and our “run until broken” approach in customer service is going to be something that customers will continue to tolerate and support for the next 100 years. 

So “smart grid” to me means leveraging innovative technology and new 21^st Century business models to rethink many of these assumptions because they are simply no longer valid.  And from a distribution perspective, if I apply that to our product set and where we work as a solutions provider, that's all about how you make the grid more efficient.  How do you optimize it?  How do you improve reliability?  Reliability is something utilities have always focused on.   But the challenges of reliability which we address today are much larger than the traditional sense of reliability which the industry has always wrestled with.  Today there is increasing volatility coming into the grid via central site renewables.  That’s a challenge of a different order.  Add to that the introduction of distributed energy coming into the grid and ‘reversing’ the directional flow of electrons, and you have a  conundrum which the distribution grid will have to address effectively if we are to live up to our customers’ reliability requirements.  Think of the increased complexity that arises from the distribution neighborhood network having more and more localized generation built into it that might be cost effective from a marginal pricing perspective and that utilities will be required to absorb.   In my mind, this represents a deep rethinking of the electric industry as we know it today and the solution requires huge innovation.

JB:  It is a changing industry, and it is interesting to think of different analogies.  When you mentioned energy too cheap and also energy efficiency not being an issue, I do recall back in the IT or hardware realm when a 20 megabyte hard-drive was just incredible and developers were forced to develop down to that limit because they had to be efficient.  And then when storage got cheap and limitless, efficiency is out the window.  You can't load a program that's not several gigabytes now.  It's incredible how we have gotten so inefficient at least in the computing areas. 

RG:  That's a good analogy.

JB:  What are we doing wrong in rolling out the smart grid right now?

RG:  Well, “wrong” is obviously a relative term.  It's probably best to focus first on what we [i.e., the market as a whole] are doing right.  We're talking innovation which is not something we've talked about in a long time.  We're bringing stimulus money to the table.  We're doing it slower than perhaps we’d all like to, but certainly we're making progress.  Not necessarily the “wrong” side,  but an area where we have made less progress than I hoped is in addressing the real drivers of value for the electric industry from a national perspective.  When you look at some of US roll-outs currently being planned, there is a lot of overlap in how our country is approaching it from a utility perspective.  Looking at some of the pilots -- I'm not convinced that the full sweep of  a potential re-invention of the grid is really being sped up or expedited in a way that  maximizes the nation’s  return.  If you look at Europe, you see a different picture, Jon.  You see stimulus money being deployed by consortia of utilities who are bidding for support monies where they are experimenting with all sorts of different new forms of technology and ultimately new business models.  So, they are dealing with distributed generation in an expedited format.  They are dealing with carbon proactively.  They are dealing with distribution generation components beyond simple PVs.  For a while here in the States, it seemed that the common wisdom was “first we have to have an infrastructure refresh of all our meters before we can move on to the smart grid.”   So, it sometimes seems to me that Europe and Asia Pacific are more sweeping in their innovation, and you see more acceptance of the concept of innovation.  I think as an industry in North America, we haven't necessarily directly addressed what we want from innovation.  We're stuck in a paradigm that says ‘ok we like the idea of innovation -- and sure we like that America might be on the leading edge of creating new products and new ways of doing business -- but at the same time, that disruptive new technology better darn well be perfect before we think about deploying it.’  And it better not really change the nature of our industry or else we will have a lot of finger pointing to deal with.  We tend to push back on the natural growing pains in technology, rather than accept them as part of a process.  You cannot do innovation in a continuum where everything is perfect.  That's not the nature of innovation.  I think as a country, we run the risk of being bypassed and not being a global player because even though we're putting real money into this space, we're not having the deepest conversations around  how much risk do we want to take?  Where do we want to experiment with new cutting edge ideas?  What is the regulatory dialogue that has to take place that gives utilities real return for innovation instead of just downside when they are not perfect?  Where’s the utility’s upside for leadership and innovation?

JB:  You are absolutely right.  We're in an industry that has a low tolerance for failure to put it bluntly.  In innovation and entrepreneurial circles, we don't call them failures, we call them learnings.  Do you see a difference between countries?  Do you see a higher tolerance for learning in Europe per say than North America?

RG:   No one is willing to sacrifice reliability for learning, regardless of geography.  Being reliable is the nature of the electric franchise.  So, I don't see anybody being very risky in Europe.  What I see, however, is very well thought out plans that examine and sample different components of the smart grid and don't keep repeating themselves in the same areas.  I see a strong emphasis on sharing those results in an open format.  I think that's what the FP7 Program, for example, does very well in Europe, and that to me bodes well for the Europeans getting ready to handle the volatility that's coming into their grid and redesigning what the future of the grid is going to look like.  On the American side of the equation, what worries me is we really haven't found a way to show regulated utilities what the viable business models of the future might be.  We need answers to questions such as: How could innovation in fact be incented to encourage change?  Or how utilities are going to transform from a throughput model which incents ever increasing demand to a model which monetizes and incents the efficient management of that demand—i.e., which prices ‘negawatts’ into the utility ROI model.  I I haven’t seen a lot of people playing in the States with the concept of virtual power until recently, but it’s a concept which clearly has been played with in Europe for awhile. 

JB:  Interesting, so give me an example of virtual power in Europe.

RG:  There was a virtual power program experiment over there called Fenix that started already in 2005 or 6, I think it was, examining how do you use microgrids, how do you seamlessly modulate customer demand, and how do you leverage distributed generation to really let the grid “flex”  so that it can absorb and leverage all sorts of different types  of power-- including “negawatts”-- to keep the grid functioning and in shape. Now the conclusion of that program which ended in 2009 as I recall was "wow, we have a lot more to learn".  It was one of the major takeaways, but it was a dialogue that was started early and with some real thought behind it and there are going to be more consequences coming off of it.

JB:  Well, Thank you very much Ray.  I appreciate your time.  I look forward to continuing this dialogue at the Smart Grid Road Show in early May with other colleagues and being able to debate what's going on today and where we are headed in the future.  

RG:  My pleasure, Jon.

By Jon T. Brock, President, Desert Sky Group, LLC

April 16, 2010

The smart grid is becoming an implementation reality.  Last week the U.S. Department of Energy announced $100 million towards workforce education for the implementation and operating of what electric utilities call the “smart grid.”  That money is for the workforce per se and not the end consumer.  Recent issues involving consumers highlight the need for educating the end consumer on what this “smart grid” is and what it will do for them.    

I recently had the good fortune to interview a smart grid luminary and utility customer service practitioner, Charles Dickerson, Vice President of Customer Care for Pepco Holdings, Inc. (PHI) on issues related to the smart grid, differences by global geography, and ideas on how to improve a smart grid implementation for success.  Charles will be joining myself and three other industry luminaries at the Smart Grid Road Show to be held May 11-12, 2010 in Cincinnati, Ohio (http://www.smartgridroadshow.com) to discuss in more detail smart grid experiences and future looks.  For now, I trust you enjoy this interview with Charles.

JB:  Please share with our readers the background of Pepco and the PHI organization and the role it plays in the smart grid.

CD:  PHI is comprised of three electric and one gas distribution companies along with two unregulated affiliates, and I'm going to spend a vast majority of time in this conversation talking about the regulated companies.  The regulated companies are: Pepco (that serves the electric needs all of Washington D.C., and large areas of Prince George’s and Montgomery counties in MD) Delmarva Power and Light (that serves large areas in Delaware and ten counties along the eastern shore and northern part of MD) and Atlantic City Electric (that serves Atlantic City, NJ and the southern surrounding counties).

JB:  My next question is what geographies do you play in globally?  I'm assuming you've just told us where you operate.

CD:  We are a mid-Atlantic electric and gas utility.

JB:  Ok, and if you had to take your areas that you participate in terms of smart grid, let me read these to you.  Do you play in the policy, generation, transmission, distribution, and the consumer?

CD:  Distribution, transmission, and the consumer.

JB:  Generation was sold off years ago.  Correct?

CD:  You are correct; our generation was sold off years ago in the regulated businesses.  As you know, we have a transmission project called the Mid Atlantic Power Pathway Project (MAPP) under consideration which we think is vital to help alleviate congestion and help increase transmission reliability within the region.  More so with the distribution and the customer side, we plan on installing close to 440,000 smart meters in Northern Maryland and Delaware and another 220,000 smart meters in the District of Columbia.  We received approval for stimulus funding for Pepco from the DOE for our Washington, DC and Pepco Maryland SMART GRID projects.  In addition to the physical meters installations, we are making the necessary system changes to accommodate the information coming in from those meters to help us better assist customers and realize a more discrete view of the electric system.  We are also installing a number of distribution devices such as Automatic Sectionalizing Re-closures (ASRs) and capacitor controllers to name a few technologies that are designed to help reduce the number of customers who experience outages as a result of a fault and reduce the duration of outages for customers how experience outages.

JB:  I understand that your background is customer service there, so from your perspective what are your main objectives of the smart grid?

CD:  I'm glad you asked that because this is where my passion lies.  For the past two minutes in my last answer, I was talking about technology which I firmly believe the entire smart grid initiative is not as much about, as it is about the ‘people’ – customers and those who directly interact with them.  I think many of us in our industry, and this is an area where we can do ourselves a favor by reevaluating our own perspectives, focus too much on the devices and not enough on the end game – changing customers’ behavior.  We have to remember that the technologies and devices are means to an end, and I think the end game is to be able to empower customers with the information they need to make more informed choices about how much energy they want to use and when they want to use it.  So it's more about changing customer behavior than about installing devices.

JB:  That is an interesting answer Charles.  Do you think that we may have over emphasized technology to a certain extent?

CD:  I think so.  I think the industry is comprised of a lot of engineers, technology people, and accountants and we tend to think in those terms.  We tend to think of wires and pipes and accounting so that things can be installed and accounted for correctly.  None of those things are bad in and of themselves; however, at the risk of over stating it, even if we installed every single meter correctly, received regulatory approval for every single rate we wanted, even if the back office systems worked perfectly, if the customers do not change their behavior, I'm not certain that I could conclude that the SMART GRID would be successful.  So, at the end of the day, customers are concerned about price. They are concerned about the price they pay for electricity, and this is probably more of an issue today for customers because as the price of energy rises, energy costs becomes a larger percentage of what they have available to spend.  So they need tools to help them make decisions and then they need to know they can make better decisions.  One of the things that the smart grid would allow customers and utilities to do is more closely match the cost of energy that the customers sees with the true cost of energy when they are using it.  With more discreet usage and costs information customers would know, for instance whether it's costing them three times as much to wash their clothes at 09:00 am than it would at 9 o'clock at night.  I believe that if customers knew the cost difference that they would wait to wash clothing during the less expensive times.  I'm just using those numbers and those times to make the point. 

JB:  You may have answered my next question.  What do you believe we are doing wrong in rolling out a smart grid?

CD:  I don't think I answered it.  Wrong is not the word I would use.  I do believe however that we are not placing enough emphasis on the behavioral aspect and the people aspect of SMART GRID.  Let me take this a step further.  One of the other things that I've been saying a lot is that the whole education piece around the smart grid is a “conversation not a commercial.”  Its going to take time to get people to understand the concepts associated with energy usage and its going to take time for those of us in the industry to change our vernacular to language our customers change relate to.  I just had an interesting conversation yesterday with a group of consultants who (like many) were comparing the electric utility industry to the telecommunications industry.  People typically try to use the TC industry as an analog and say that TC customers get time of use (day / evening calling pricing) plans.  I believe that is true; however, the concept of minute is something we’ve been made to be aware of from our early childhood.  How many times have our parents said to us, ‘give me a minute’ or ‘wait a minute’?  So when you tell people if you use more minutes, it costs more on your phone, they can relate.  If you transfer it to a term like kilowatt or kilowatt hour or even a more complicated term rate demand, then you try to get people to understand what that means, you have a harder hurdle to overcome, a harder challenge.  The concept of a kilowatt demand or kilowatt-hour is not something that many customers readily grasp.  So, it is incumbent of us to translate these electrical industry terms, via repeated and patient conversations and not just commercials, into a lexicon that our customers can understand.  Try to explain that through a series of television and radio ads alone aren’t going to do it.  What's going to have to happen is that we're going to have to focus more on one-on-one dialogues with people.  Customers need more patient dialogues to get them to understand what these terms mean, how they impact them in their usage, and what they can do with that knowledge to manage themselves financially.

JB:  That is interesting.  Do you think that is a global phenomenon or are you speaking about a United States phenomenon? 

CD:  I can not imagine this will not apply globally, but my perspective is based upon the United States. 

JB:  So, education will be ultimately the key. 

CD:  Education not advertising.  They are two totally different things.  We're going to have to advertise to get people aware that the technology and rates will be available to them, but once they are aware, they are going to call our call centers and text and email our contact centers and they are going want to talk and chat and they are going to want to get in social inner circles to find out what does it mean and how is it going to benefit them.  And just to tell them that we gave them meters, isn't going to do it.  They are going to have to know what consumption means, how prices are tied to usage, and how best to shift their usage so they can mitigate prices and ultimately pay less for energy.

JB:  I want to thank you for your time Charles.  That concludes all the questions I have right now.  I am looking forward to the panel at the Smart Grid Road Show in Cincinnati in early May where we will address more of these issues in detail.

Jon Brock is President of utility and energy advisor Desert Sky Group, LLC.  He can be reached at jbrock@desertskygroup.com         

Reprinted with permission from Electric Energy Online, February 24, 2010

By Jon T. Brock, President, Desert Sky Group, LLC

February 24, 2010

Seventy-five percent utility attendance.  How many times have you heard that at an industry conference?  Of sixty registered attendees at the EUCI 8^th Annual Utility Billing Conference in San Antonio, seventy-five percent were from a utility in North America.  I could not pass up the opportunity to gather some relevant research on what the utilities are thinking when it comes to issues and functionality surrounding the customer information and billing systems (more commonly referred to as the CIS) in today’s changing marketplace.

The attendees (utility and vendor) broke into four groups and “brain-stormed” existing programs versus new program ideas under the topic areas of CIS implementations, credit & collections, functionality, and e-Bill capabilities.  After brainstorming, each group presented to the larger conference the results of their efforts.

CIS Implementation

It is no surprise that implementing a utility CIS has won the moniker of being one of the most painful exercises in a utility back-office.  Commonly referred to as a “root canal,” the utilities reported back the following observations, from experience of course:

• Integrators need to learn more about the utility business

• Provide additional training when going from “green screen” to windows-type user interfaces

• Designate a “user group” to perform site visits of vendor offerings

• Keep resources in place for post-go-live support

• Protect against project manager turnover

• Do not cut corners (no going live until fully ready)

• Perform detailed data cleansing during the implementation

• Put appropriate quality assurance procedures in place

One of the organizations in attendance actually represented a group of utilities and expressed having them as a “user group” of sorts helped tremendously when gathering requirements for a successful implementation.

Credit & Collections

In the current economy and threat of employment uncertainty, credit & collection activities have been put to the test in the utility industry.  Observations from the utility experts included:

• Use of credit scoring services such as Experian or Equifax
• Mix both live and automated outbound calling – live calling needs utility experience
• Use an intelligent bar code on the remit for suppressing the dunning letter
• Join a consortium or group for requirement definition/learning
• Offer pre-pay functionality to customers with credit challenges

One utility was offering classes to small businesses in its community on how-to set up and run a small business complete with local resources to use.  Credit & collection issues had reduced for that segment of consumers.  Other utilities were experimenting with automated turn-on/turn-off features of new smart meters being implemented.

Functionality

CIS functionality has been an interesting element to track over the years.  Approximately three years ago it was becoming virtually pointless to do a functionality checklist when selecting a new CIS because most bidding vendors would come in with the same score.  Recently with smart grid functionality beginning to creep into the check-lists, utilities must be cautious of separating required functionality from possible functionality.  Observations included:

• Listen to your customers and be prepared to follow through with what they are asking for
• Monitor new smart grid functionalities and be prepared to offer what will become required
• Possible new smart grid functionality could include distributed generation, net metering, and dynamic pricing
• Streetlights may require a separate system in order to work with the existing CIS
• Pre-pay electricity is becoming a requirement (and multiple ways to pay via kiosk, online, text messaging, and phone)

One utility suggested offering pre-pay electricity to higher-income users since its acceptance was not limited to low-income or credit challenged customers.

e-Bill

This conference was held in conjunction with an e-billing conference so many of the utilities in the room had quite a bit of experience with e-billing.  Observations from the utility participants included:

• Let customers choose to turn off the paper bill
• Make the choice an environmental one – demonstrate what is being saved by turning off paper
• Adopt an environmental cause that is local (not trees in South America but something in your state) and track it for the customers who choose e-bill
• Need to collect and cleanse e-mail addresses frequently (privacy laws apply)
• Need to become an expert on how to keep e-mail out of a “spam” filter
• Convert from a “pull strategy” to a “push strategy”

The utilities in attendance were ranging from 4% adoption to 33% adoption.  A key for success is educating customers to turn off the paper.  For instance, yours truly pays electronically but still gets a paper bill from some billers.

Hearing from the utilities themselves and not the vendor community is a welcome change periodically.  Sometimes we lose track of what the true functionalities are.  I recall all the new gizmos and gadgets we were going to deploy as an industry with deregulation.  In the end, the retailers that were successful were the ones that could get a commodity bill out first and then work on the gizmos and gadgets later.  As emphasized by John Saenz, the Senior Vice President of Retail Energy for CPS Energy in San Antonio, the utility bill is the most important aspect of what we do because it touches everyone (either physically or electronically) once a month.  Well said.

Jon Brock is President of utility and energy advisor Desert Sky Group, LLC.  He can be reached at jbrock@desertskygroup.com         

By Jon T. Brock, President, Desert Sky Group, LLC

Reprinted with permission from Electric Energy T&D Magazine, January 29, 2010

To set the stage for what follows, you’ll need to travel back a decade with me to December of 1999. I’m busy doing last minute shopping for Christmas presents and preparing to stay up all night on December 31st, ready to go into work if the “big blackout” comes as a result of Y2K (the date switching from 1999 to 2000 in countless systems). I’m working at one of North America’s largest electric utilities, and no blackout occurs. My thoughts quickly turn to the analysts who in January of 2000 proclaim that bricks-and-mortar have once again outsold the “dot-coms” for the 1999 Christmas buying season. Then, March 10, 2000 brings the peak of dot-coms being over-valued, and the NASDAQ hits 5132.52 – just before the collapse. So is the Smart Grid following the same path as the dot coms? Considering the way it’s being characterized at the moment, I believe so…

Just as the dot-coms were over-hyped in the late nineties and eventually came to fulfill their promise in the mid-2000s, I’m of the opinion that like the dot-coms, grid transformation will very likely fall short of expectations for the near term, but will probably be better equipped to deliver on those promises over the longer term, the latter being several years – certainly not one or two.

According to IT analysts at renowned Gartner Group, Smart Grid technologies serving the utility industry are nearing the peak of their “hype cycle.” The hype cycle is a process that Gartner says every technology goes through. Developed in 1995, the hype cycle consists of five areas: On the Rise; At the Peak; Sliding into the Trough; Climbing the Slope; and Entering the Plateau.

As Gartner sees it, technology hype cycles provide a snapshot of core technologies, software and infrastructure. Examples include topics in wireless, security, productivity tools, hardware infrastructure and networking. Gartner’s “Emerging Trends & Technologies Hype Cycle” provides a view of highly hyped and high-impact trends and technologies from across the information technology landscape. Smart Grid technologies for the utility industry are nearing the peak, preparing to “slide into the trough,” according to Gartner.

To illustrate the point, for the past three months I’ve posted a single question on my website, asking: “Is the Smart Grid over-hyped?” Although by no means is this poll scientific, 87% of respondents answered “yes.” Would a more scientific approach yield different results? Perhaps, but I think not.

Joining the previously mentioned dot-com collapse are other examples including broadband fiber in the telecommunications markets; utility deregulated retail markets in North America; and even renewable technologies, to an extent. So, if we have history as a teacher on our side and we know that a specific segment of the market (in this case the Smart Grid) is over-hyped, then why are we running like lemmings toward a cliff we know exists? Or DO we know it exists?

I would agree that it’s patently unfair to lump multiple technologies into a single basket called “Smart Grid,” so let’s take a closer look at them at the very highest level for starters. The United States Department of Energy provides a good definitional overview of the electrical grid. DOE states that the electric grid delivers electricity from points of generation to consumers, and the electricity delivery network functions via two primary systems: the transmission system and the distribution system.

The transmission system delivers electricity from power plants to distribution substations, while the distribution system delivers electricity from distribution substations to consumers. The grid also encompasses myriad local area networks that use distributed energy resources to serve local loads and/or to meet specific application requirements for remote power, village or district power, premium power, and critical loads protection. But when we start talking more specifically about the Smart Grid, many more definitions exist. Moreover, to call it “smart” assumes that the existing grid is “dumb.”

An analogy that I have adopted from the DOE is the comparison of the forefathers of telecommunications and electricity markets. The story goes like this:

If Alexander Graham Bell were somehow transported to the 21st century, he would not begin to recognize the components of modern telephony – cell phones, texting, cell towers, PDAs, etc. But by contrast, Thomas Edison – one of the grid’s original architects – would be totally familiar with the grid. In that respect, the legacy grid we have today is “dumb.”

Going back to my Y2K example, the reason that we had little to no blackouts when the date switched from ‘99 to ‘00 is not only due to all the hard work put in to prepare, but also to the fact that many of the distribution and transmission networks in 1999 did not care about a date – again, “dumb.”

Obviously, the Smart Grid has many definitions, often depending on who’s doing the defining and/or the composition of the intended audience. I will not attempt to define it yet again here, but instead, let’s examine its components.

Despite all the “hype” around smart metering and the fact that someday I can watch my car charge from a smart phone; electric grid stakeholders representing utilities, technology providers, researchers, policymakers, and consumers have worked together to define the functions of a Smart Grid. Through regional meetings convened under the Modern Grid
Strategy project of the National Energy Technology Laboratory (NETL), these stakeholders have identified the following charac­teristics or performance features of a Smart Grid:

•    Self-healing from power disturbance events
•    Enabling active participation by consumers in demand response
•    Operating resiliently against physical and cyber attack
•    Providing power quality for 21st century needs
•    Accommodating all generation and storage options
•    Enabling new products, services, and markets
•    Optimizing assets and operating efficiently

Not to disparage the efforts of the utilities winning stimulus funds – which, as most of us in the industry know, have been split into categories such as investment, demonstration, and innovative research – but I fear that the business cases of the awarded stimulus put too much emphasis on benefits that are heavily dependent on smart metering and time-differentiated rates. Granted, that was the intent of the DOE. However, getting an infrastructure in place, stabilized, and working well with proven standards and interoperability targets is crucial before moving to end-use consumers. As I stated at the beginning of this article, I fear a “cliff” or market correction is coming, given the way Smart Grid is characterized
at the moment.

As defined by NETL, there are several functions that the Smart Grid can address and not all of them are focused on real-time rates for residential consumers. For instance, recently I have been researching various T&D technologies such as Volt/VAR control & optimization, load balancing, and self-healing solutions that do not necessarily require a touch-point at every consumer and can deliver benefits in a rapid fashion as it relates to digitizing the electric grid. However, these technologies are not as prevalent in the current investment or demonstration awards as smart metering. The innovation research funds will go towards electro-fuels, advanced car­bon capture technologies, and transportation battery storage.

I am not saying that smart metering and time-differentiated rates for end-use consumers are not important or that they do not have benefits. To the contrary, they are vital priorities that will eventually change the way we live (remember rotary phones?). What I am saying is that regulators, utilities, ratepayers, and investors alike will have to be patient when expecting the benefits of the Smart Grid to be realized. This is much easier said than done. Are we about to enter the trough after the hype? You bet… but this time, we know it.

Jon Brock is President of utility and energy advisor Desert Sky Group, LLC.  He can be reached at jbrock@desertskygroup.com

By Jon T. Brock, President, Desert Sky Group, LLC

October 21, 2009

"If you cannot measure it, you cannot improve it." That was a quote by Sir William Thompson, Lord Kelvin (1824-1907). Much has been said about providing information and transparency to consumers of commodities.  This rings especially true for electricity in today’s markets.  The National Information Solutions Cooperative® (NISC) announced to its member utilities recently that it has signed a channel partnership with Google (NASD: GOOG) to provide energy information to end consumers.  The announcement, made at the annual NISC member information conference, signaled Google’s move into the nation’s largest group of cooperative utilities and public power entities to date.  Previously, Google had signed partnerships with individual utilities such as JEA, SDG&E, Toronto Hydro, TXU Energy, White River Valley Electric Cooperative, and Wisconsin Public Service.  The purpose of the Google move into energy is to educate consumers on their energy usage.

Per the Google website, Google PowerMeter is a free electricity usage monitoring tool that provides consumers with information on how much energy the home is consuming.  Google PowerMeter receives information from utility smart meters and in-home energy management devices and visualizes this information for consumers on iGoogle (a personalized Google homepage).  PowerMeter is a product of Google.org, the non-profit philanthropic arm of Google, which aspires to leverage the power of information and technology to address global challenges.

NISC was formed July 2000 as a consolidation of Central Area Data Processing Cooperative (CADPC) and North Central Data Cooperative (NCDC). Both predecessor organizations were formed in the mid 1960’s and had a rich history of serving energy and telecommunications cooperatives with information processing services and accounting and billing software. NISC has more than 510 energy and telecommunications members in 47 states, American Samoa, and Canada. It bills more than 7.2 million end user subscribers/meters.  The first NISC member to sign up for the Google PowerMeter is Minnesota Valley Electric Cooperative (MVEC).

Located on the southwest side of Minneapolis, MVEC serves 33,000 electric consumers with approximately 40,000 meters.  The consumer mix is 70% residential and 30% commercial.  Most of the meters are Landis & Gyr while the advanced metering infrastructure (AMI) network technology is provided by Aclara (a little over 25,000 meters have been converted with an Aclara module inside).  MVEC is going to be utilizing a newly developed meter data management (MDM) application provided by the NISC.  This is where Google will get its data for the PowerMeter.  Consumers will sign up for the service via MVEC’s e-bill site.  There they will give consent for MVEC to send their usage data to Google.  The consumer may then access a personalized igoogle page to view their energy consumption.

Source: www.google.org

The goal of both the NISC and of Google.org is to simply educate energy consumers on what they are using and the impact of specific devices in the home on energy usage. Education can modify behaviors and increase energy efficiency awareness among the public. Evidence of this can be seen with the advent of the digital dashboard on the Toyota Prius. Love them or hate them, Prius drivers have learned from real-time (or near real-time) feedback what the most efficient miles per gallon driving habits are.  For instance, 38 miles per hour seems to be a more efficient speed than 35 or 40 miles per hour.  If the public knows what its energy usage is in near real-time, then it can start to make decisions that are more informed and could encourage energy efficiency.

The role that technology plays in our everyday lives is increasing at a rate unforeseen by many of us just a few years ago.  Lord Kelvin was correct: if you cannot measure it, you cannot improve it.  He was slightly off course when he stated “radio has no future.”

Jon Brock is President of utility and energy advisor Desert Sky Group, LLC.  He can be reached at jbrock@desertskygroup.com