The business case for renewable distribution generation

Guest post: Caroline Mason, Commercial Key Accounts Manager

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

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

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

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

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

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

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

  

Looking forward to 2013

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

“Where’s the Big Data?”

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

----------------------

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

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

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

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

Virtual tour of ABB's Smart Grid Center of Excellence

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

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

Asset health management in the smart grid era

An end-to-end asset health management strategy can help prioritize repair-replace decisions, improve reliability, increase workforce efficiency and meet regulatory milestones. For more information, download this free white paper, Using smart grid data to power end-to-end asset health management.

Watch this video to learn how an end- to-end asset health management strategy ties analytics and equipment monitoring to a business intelligence platform that provides actionable results.

Smart Grid Investment Trends: Follow the money, Part 1

The progression of smart grid implementation in North America has been interesting to watch as the focus shifts to different stakeholders and technologies. When I look at the smart grid implementations, new investment trends are emerging. The trickier question is which trend is driving the most implementation and what benefits utilities are able to capture.  

The two biggest investment drivers right now are the need to improve utility operational effectiveness – the subject of this blog -- and connecting renewable energy resources to the grid. Operational effectiveness encompasses advanced metering infrastructure (AMI), distribution grid management, utility analytics (aka “Big Data”), and distributed energy resources (DERs). In each case, underlying drivers such as aging infrastructure and operational cost pressures are increasingly compelling utilities to invest in new solutions to meet new, more demanding expectations of customers, shareholders, and regulators. 

I attended a conference three years ago and one of the speakers said that advanced metering infrastructure (AMI) had “hijacked” smart grid.  At the time, the ARRA funding for the DOE Smart Grid Investment Grants was largely focused on AMI projects. In my opinion, this happened for three reasons. Politically, customer engagement is important and many consumers associate the meter on the side of their house with the grid and hopefully link a smart meter to a smarter grid. The second reason is that for many utilities, the business case for AMI is generally positive or at least break even. The business cases looked even better with the ARRA grants covering up to 50% of the project costs. Finally, AMI technology can be deployed within the three-year time frame required by the grants. (find out more) 

But if we follow the money, many utilities are finding a business case for distribution grid management investments built around improving operational reliability (Fault Detection Isolation and Restoration, or FDIR) and efficiency improvements (Volt/VAr control and optimization, or VVO). The capability to improve operations without having to convince customers to change their energy-use behavior – something that has proven to be a challenge during some AMI implementations – appears to be attractive to utilities.  

Additionally, the utility investments in AMI and distribution grid management are pushing another smart grid investment trend: “Big Data”.  Meter data management systems are capturing interval data from residential customer meters that can now be provided to consumers, and this data can be analyzed to help define customer usage patterns and preferences for demand response programs. Business intelligence solutions can also provide situational awareness and improved performance for grid operations based on analysis and display of operational information captured by systems such as distribution management systems.

Another “Big Data” play is asset health.Asset health management addresses the industry’s aging infrastructure and aging workforce by managing the process of capturing asset data and using this data to achieve asset reliability performance goals more efficiently. Algorithms and performance models are applied to the data to determine condition and health of assets, to provide situation awareness and identify needed condition-based maintenance, and to execute the asset maintenance that drives grid performance.     

Improving operational effectiveness also means using the best of new demand response technologies for peak shaving, load shedding, and load shifting applications to gain more control over energy supply and demand.  Today, two-way communications and programmable communicating thermostats or web portals for capturing consumer usage patterns and preferences have enabled more sophisticated demand response programs for residential customers. Commercial and industrial customers are now using demand response for peak shaving to avoid excessive demand charges, load shedding in response to emergency utility requests, production scheduling and load shifting based on electricity market prices, and ancillary services such as spinning reserve capacity and frequency regulation.  Aggregators have emerged to offer ancillary services to the energy markets established by regional independent system operators. In each case, demand response represents new business model opportunities to more effectively and efficiently deliver power to end customers.

So far, many investments in DER applications such as distributed generation (i.e. solar PV installations), distributed energy storage, and electric vehicle charging infrastructure, are mostly pilot projects to demonstrate the technologies, quantify the benefits, and gain operational experience. Investment interest is growing in this segment.  

In my next blog, I will talk more about interconnecting renewables and also how utilities are managing and monetizing distributed energy resources.