by Roy Pratt, Hewlett-Packard Co.
The emerging smart grid encompasses more technology, costs and complexity than the traditional utility distribution network.
Smart grids will enable utility companies to anticipate and shape consumer demand for electrical power and optimize their own power delivery and reliability.
A new generation of embedded computing, advanced metering and data management technologies make this possible. Smart grid projects can be derailed easily, however, with the wrong course of action.
Hewlett-Packard Co. applied its extensive smart grid experience alongside major utilities to identify the seven sins of smart grid and approaches to progress.
Sin No. 1: The Same Old Mindset
Historically utilities employed conservative approaches to ensure continuity and reliability, but smart grid technology is profoundly disruptive. It changes every process in the organization.
Utilities must recognize these changes and understand smart grid’s pervasive impact. Smart grid implementations are a transformational event for customers, the grid and utility organizations.
The transition to smart grid for utilities will be as dramatic as the shift from landlines to mobile phones was for telecom.
The three fundamental areas of impact to the utility business include:
- AMI/SMI Field Environment. With today’s smart meters, utilities have advanced capabilities to monitor multiple types of energy usage in defined time periods. Equipped with new communications technologies, smart meters can exchange energy consumption and power control information with a utility company within seconds. Smart meter communications technologies enable smart grids to cover large, diverse, geographical areas. The number of communicating devices can increase most utilities’ network management 1,000 times.
- Systems Environment. When most utilities’ major systems environments were designed 20 or 30 years ago, the primary objective was reliability and simplicity. New smart grid systems provide communications and command-and-control functions required to support smart meters. Examples of these new systems are meter data management systems, automated data collection systems, distribution management systems and demand management systems. Utilities’ legacy systems will require considerable modification to handle the granularity, volume and timeliness of new data and will require specific integration to leverage the new smart grid systems’ business value.
- Customer Experience Environment. With smart grid technology, customers will be armed with tools and information to help utilities reduce drastically demand spikes and drive energy conservation. Therefore, utilities will enter a new realm of customer relationships. Gone are monthly paper bills and rare outage calls. Customers will demand daily, if not hourly, interaction with utility providers through websites, portals, in-home-displays, communicating thermostats, mobile phones, Web applications and automated home energy management systems. Home area networks (HANs) will integrate the customers’ in-home experiences with components that send and receive real-time information from utilities and third-party providers. In addition, through the Internet, customers will have access to a secure utility portal to monitor and compare detailed energy consumption.
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Internally, utilities must clearly identify how the smart grid will impact all areas of their organizations and corresponding processes with process analysis methodology. This identifies tangible and familiar smart meter implementation components and correlates them with common organizational operational processes. This methodology will show how smart grid components will impact all stakeholders.
Sin No. 2: Smart Grid Immaturity
To achieve appropriate smart grid maturity, it is necessary to identify upfront a smart grid project’s primary objective.
The difference between securing cost savings through automated meter readings and implementing advanced meter infrastructure (AMI) to enhance customer relations and conservation capabilities is immense.
The sin is to confuse goals with what is ready to implement. Smart grid vision and maturity builds from the simple to the complex in stages that build upon one other, like in the chart.
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| Utilities will enter a new realm of customer relationships. Gone are monthly paper bills and rare outage calls. |
Introducing communications into a digital electronic meter–a smart meter–is the first and most basic smart grid phase. Automated reading systems can gather time-based electric consumption information and deliver granular information to utilities without reading meters on site.
During the second phase, AMI improves communications considerably using fixed-network infrastructures.
Fixed (in-place, always-on) communication allows utilities to pull energy consumption data anytime and allows them to send information down through the meter to share with homeowners or to the meter for control functions.
The real-time sense and respond phase of smart grid maturity includes bidirectional device communication applied to customers and devices that control power flow in the electric grids, such as wires, transformers and switching stations.
All grid network devices deliver consumption information and relay how the network is responding. They also empower utilities to adjust network operations and optimize power delivery and reliability.
The proactive control phase of smart grid maturity is the next phase, characterized by the addition of significant instrumentation, monitoring and control devices to the grid.
These devices feed operational data into real-time analytic models that adjust grid control parameters to optimize power delivery and reliability. This operational model data also is used to model future states of the grid given forecast (weather, fuel prices, spot market prices, transmission anomalies, etc.) events.
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Technology and integration challenges currently limit progress into a completely modeled environment, but just as cloud computing was a distant utopia 10 years ago, this may come to pass.
Sin No. 3: Design, Not Architecture
As engineering-oriented organizations, utilities customarily design point solutions. Pure design, however, will not support successful smart grid projects.
Point solutions are optimized for specific design constraints and lack flexibility and resilience to changing constraints. Therefore, design must be replaced with robust architecture to drive interoperability among solutions.
Service-oriented architectures (SOAs) are ideal for smart grid because they allow complex functionality to be abstracted behind Web services and for those Web services to be deployed in an asynchronous phased implementation.
It simplifies the construction and maintenance of what otherwise would be an overly complex enterprise.
SOAs are modular and scalable, allowing an incremental approach to smart grid deployment that supports the reliability utilities require.
As smart grid solutions evolve and change, SOAs enable utilities to regularly revalidate components throughout the proposal, building and deployment stages.
As such, the architecture-based approach provides critical future-proofing and investment protection.
The diagram below illustrates a three-tiered SOA approach. Level 1 represents the front-end devices, separated from Level 2 by an infrastructure management bus to provide meter independence, device independence or both.
Level 2 provides basic core functionality for AMI. This, in turn, is separated from back-office systems at Level 3 by a message interface bus. Functions sit underneath the defined services required. This logical, simple SOA gives flexibility to enhance the solution without deep-routed changes (see Figure 1).
Sin No. 4: All-in-One Implementation
As a fundamental change, smart grid implementations are too large and complex to be handled at once; thus, they should not be handled in a big bang.
To minimize disruption, smart grid technology should be implemented gradually in multiple phases.
Smaller changes will minimize technology, schedule and thus project risks and empower a utility to start reaping rewards incrementally.
For example, many utilities realize the benefits of automated meter reading relatively early. More complex functionality, such as pre-payment, load limiting or distributed generation, however, will yield the most benefit when applied later in the process to larger domains.
As Figure 2 illustrates, opting for a phased approach minimizes project risk and maximizes time value of benefits through an interconnected progression of enhancements.
Sin No. 5: Homogeneous Technology
Many utilities have grown accustomed to homogenous technology environments.
With the dawning of the smart grid era, utilities must manage variance and ongoing change from topographies across service territories.
Variance will increase as customers shift from being demand consumers to supply providers with distributed generation.
Change in vendor technologies and the need for best-of-breed solutions for niche applications will force continued change in technology components.
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As the market evolves, no one vendor can have all the answers.
Many parties, however, are making efforts to advance the technology and standards that will make smart grids more practical and adaptable.
As an illustration, the phased implementation in the previous section spans nine years.
Most smart grid projects can span three to five years. Over such time, a utility is likely to see two to 10 generations of smart grid technology in its own implementation.
Being locked into any one vendor invites significant problems when products or availability change.
With a heterogeneous approach to architecture, utilities will be ready and able to adopt the best solutions as they become available.
Sin No. 6: Going it Alone
With the pace of change accelerating, no one organization has the full knowledge to go it alone. From standards bodies and systems integrators to government agencies, pockets of development and further research are occurring everywhere.
Utilities should not try this independently. Only a collaborative, open approach among utilities, vendors, partners, industry groups, regulatory bodies and the government will prove successful.
Utilities should involve themselves with these groups to learn about technology solutions, business models, regulatory approaches, financial justifications and customer marketing and communications.
Sin No. 7: Forget the Data
The final sin is to forget why the smart grid was started and as the necessary resources and time commitments.
The smart grid promises to transform the efficiency and effectiveness of energy production and consumption through information sharing between consumers and utilities.
A solid plan is required to determine how this frequent, granular data on consumption and the network will be used.
In addition to reducing consumption and improving grid efficiency and reliability, the smart grid data can introduce new markets, services and lines of business, but only when properly handled.
Customers can experience benefits including security and safety monitoring that leverages the always-on connection to their homes. Interfacing appliances will give consumers detailed information on their performance. In turn, energy management services will help consumers conserve and save.
From the outset of any smart grid program, utilities should plan for an advanced analytics processing capability if they don’t already have one.
The value of smart grid is in the data it can provide to drive efficiencies, improve effectiveness, ensure reliability and develop new products and services. Knowing the seven sins of smart grid enables utilities to be successful in their implementations.
Exclusive C Three Equity Index
2010 Year of Mergers, Consolidation
Six major deals were announced or completed in 2010 and the first few days of 2011.
FirstEnergy and Allegheny merged. PPL acquired the old LGE Energy companies in Kentucky from E.On. Mirant and Reliant Resources merged and created GenOn Energy. Northeast Utilities and NStar merged. Carl Icahn acquired Dynegy, the successful spin-off of QEP Resources by Questar. AGL Resources acquired Nicor. And Duke Energy purchased Progress Energy.
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2011 should bring several more M&A announcements.
There was other big news, as well: the death of cap and trade; the Environmental Protection Agency’s flexing its muscles; a House majority change; striking down California’s Proposition 23 by a 61 percent to 39 percent vote; and extending renewable energy credits through 2011.
NICOR was December’s big winner. The merger valuation bump was evident there. AES Corp. has been on a $500 million stock repurchase binge.
Dynegy’s prices were helped by Icahn’s bid. Natural gas seemed to be the common denominator among most of December’s top 10 winners.
Rate cases and being the acquiring company seemed to be the common denominator among the bottom 10.
2010 was the year of natural gas, regulated and less regulated.
But wait, is that not what we said in 2004, 2005, 2006, 2007 and 2009? The only year in this group where Less Regulated Natural Gas did not lead the C Three Index pack was 2008.
In 2010 the LDC index, the more heavily regulated natural gas distribution company group, almost kept pace with its less regulated siblings.
Speaking of the LDC group, a “passionate investor” of Piedmont Natural Gas recently wrote, “The lower natural gas prices have plagued natural gas utility profits recently.”
The companies to which he refers all have a substantial part of the natural gas price risk hedged through gas cost-recovery provisions, decoupling mechanisms or both. None of these companies has substantial upstream holdings. Why do lower natural gas prices hurt local distribution companies if they have their price risk mitigated? This frustration probably keeps a few LDC executives up at night.
The LDC’s excellent investment in 2010 outperformed other groups over five years except for the Less Regulated Gas. Over shorter and longer terms, the Less Regulated Gas Group has been the clear winner. This analysis factors dividends for any company paying one.
Natural gas also will play a major role in balancing new renewable electricity sources. Thirty-three natural gas-fired power plants came online in 2010 with nearly 5,000 MW of capacity. During 2010 C Three added to its power plant database more than 35 new projects accounting for more than 30,000 MW of planned new capacity coming online between 2011 and 2020. As long as natural gas prices remain relatively low, the trend should continue.
Methodology and Components of Each Index Tracked by The C Three Group
Less Regulated Electric Focus. More than 50 percent of revenues come from nonstate-regulated sources and/or more than 33 percent of assets are nonstate-regulated.
Less Regulated Gas Focus. More than 50 percent of revenues come from nonstate-regulated natural gas distribution and/or more than 33 percent of assets are nonstate-regulated.
Regulated Electric. No more than 20 percent of revenues can come from natural gas distribution and no more than 49 percent of revenues and 33 percent of assets can be associated with nonregulated activities.
LDC. No more than 20 percent of revenues can come from electric distribution or generation and no more than 50 percent of revenues and 33 percent of assets can be associated with nonregulated activities.
Regulated Electric and Gas Combination. More than 20 percent of revenues derived from natural gas distribution, no more than 50 percent of revenues and 33 percent of assets from nonregulated activities.
The C Three Index. The C Three Index is the nonweighted average of each of the companies included in the groupings above.
The C Three Indices are developed based on a straightforward premise: If you invested $100 in each of the stocks of the companies we track, what would those shares be worth after a certain time?
Historical share prices are adjusted for dividends, splits and spin-offs.
Past EL&P Issues
