Navigant Research Blog

With Pepco Deal, Exelon Moves to Calmer Waters

— May 2, 2014

As a former Exelon employee, I don’t find the announcement of Exelon acquiring Pepco a surprising development.  A wave of consolidation has hit the utility industry since the recession began in 2008, with larger companies with stronger balance sheets looking to take over vulnerable entities.  Pepco may not have been in obvious peril, but it has recently earned less than its allowed return on investment, making the Washington, D.C.-based investor-owned utility a likely target for acquisition.

Exelon has agreed to buy Pepco for $6.8 billion, creating the largest utility in the Northeast. After the merger, Exelon’s utilities will serve 10 million customers and have a combined rate base of $26 billion, putting it close to Duke Energy as the largest utility customer base in the country.  

Steady as She Goes

Exelon’s stock and earnings have taken a beating the past couple of years, due to the exposure of its nuclear and coal plants to flattening electricity prices brought about by weak economic growth and strong shale gas expansion.  When it acquired Constellation for $7.9 billion in 2012, Exelon was counting on the competitive generation and supply segments as the growth leaders of the business, while the regulated utilities were just the hull of the ship keeping it afloat.  The opposite occurred, however, as low energy and capacity prices sank the baseload generation business to the point where Exelon is considering retiring several nuclear plants and made the retail supply business, which thrives on volatility, a strategy in limbo.  Texas-based Energy Future Holdings Corp. (EFH) recently declared bankruptcy due to similar failed bets.  Price spikes this past winter and future capacity price increases in New York and New England may present a glimmer of hope (Exelon’s stock is up over 30% this year), but those factors involve plenty of risk and a long-term horizon, as well.

So, now the pendulum swings back to the safer, regulated side of the business.  Acquiring Pepco makes geographic sense, as it expands Exelon’s reach down the I-95 corridor from Philadelphia to Baltimore to Washington, D.C.  There will certainly be opportunities for overhead and personnel savings to be found among the various headquarter locations, as well.  Already an expert in the PJM wholesale energy marketplace on the Eastern Seaboard, Exelon has a long familiarity with the region’s public utility commissions.  There really is not much downside for Exelon, aside from valuing the business appropriately.

This is not a sexy deal in terms of being a beachfront for new business models or technology breakthroughs.  It is simply a back-to-basics, balance sheet-stuffing, risk-reducing measure to steady the helm in current market conditions.  If the opposite of a polar vortex occurs this summer, maybe the merchant business will come roaring back to the fore.


Automated Demand Response Draws Vendors of All Stripes

— March 10, 2014

Automated demand response (ADR) technology was pervasive at the recent DistribuTECH conference in San Antonio, as vendors from all sides of the utility spectrum are looking to get a piece of the DR pie and extract more value out of their core offerings.  Companies that focus on utility operational systems want to incorporate DR management, while those that specialize in customer energy management want to move up the value chain and offer utilities full service customer DR programs.  Metering companies want to show the benefit of their hardware and data to provide smarter DR, and pure-play DR providers want to protect their territory and expand in both of the other directions as well.

There were also some interesting press releases related to ADR in conjunction with DistribuTECH. AutoGrid announced a new $12.75 million investment round led by German utility E.ON.  This funding will support AutoGrid’s customer growth, including international expansion.  It will also allow the company to develop new applications for its Energy Data Platform software, which provides predictive analytics for big data and automated control for DR purposes.

Comverge released a new suite of IntelliSOURCE advanced applications for demand management optimization. The main component is a machine learning system that utilized big data analytics and two-way device telemetry to improve forecasting capabilities.  This gives utilities the ability to transform DR from a mostly emergency resource to a real-time operational resource that facilitates renewable energy integration and supply management.  Called Demand Response Optimization, the engine can determine the most cost-effective assets for a utility to deploy, taking customer and environmental factors into account.

Worldwide Growth

EnerNOC introduced a new utility DR product called Demand Manager, which is a software-as-a-service (SaaS) platform that provides utilities and retail electric providers with the tools to manage their DR programs.  Unlike the typical model, where EnerNOC provides a turnkey, fully outsourced program management service, Demand Manager allows utilities to buy software and professional services if that’s what they prefer.  The offering includes a data-integration application programming interface (API) that allows EnerNOC’s software to integrate with utility interval meters, thereby leveraging smart meter investments.

I have also heard from several utilities recently that they are looking to procure new demand response management systems in order to initiate ADR programs in addition to or in place of their existing manual or direct load control programs, so activity appears to be heating up on both the vendor and customer sides of the equation.

In my recent report on ADR, I forecast that the number of ADR-equipped sites worldwide will grow from fewer than 217,000 in 2014 to more than 1.9 million by 2023.  The report, Automated Demand Response, examines the global ADR market with a focus on two key sectors: C&I and residential.  Along with global market forecasts, the study provides an analysis of the market drivers and challenges, as well as the key technologies, related to ADR.

The full scope of ADR technology and the ADR market landscape will be covered in our upcoming webinar, Automated Demand Response, which will take place March 11, 2014 at 2:00 pm EDT.  Click here to register.


Polar Vortex Sparks Wintertime Demand Response

— January 23, 2014

Polar vortex became the first catchphrase of 2014 in the United States.  It was no joke, though, as the phenomenon led to record low temperatures and several deaths around the country.  The cold snap also took its toll on the electric grid, leaving hundreds of thousands of people without power across a large swath of the nation.  There could have been even more outages had demand response (DR) not been at the disposal of system operators as a step in their emergency procedures.

PJM, ERCOT, and NYISO all set new winter peak demand records due to the heating requirements that the frigid temperatures required.  When you combine record demand with power plant and transmission line outages that can be caused by the cold weather, electric grids can quickly get into emergency situations where they need to call on reserves to prevent forced load shedding, otherwise known as brownouts or blackouts.

Prior to this winter, ISO-NE activated its DR system in response to grid and weather conditions during the winter in each of the past 2 years, and ERCOT called one winter event a few years ago, while PJM and NYISO have never had winter DR activations.  ISO-NE called an event this past December as well – on a Saturday night no less – due to generator outages, but it survived the vortex without having to implement DR.  The rest of the regions all dispatched their DR resources at some point during the vortex conditions, and all of them succeeded in avoiding further emergency steps like blackouts.

Load Spikes

ERCOT was the first region to call DR as the cold wave swept East across the country.  It activated its contracted DR customers and put out a general conservation notice to all consumers.

PJM actually deployed DR twice in 1 day due to higher-than-anticipated morning load ramp and an evening peak load spike, as seen in the chart below.

PJM Load Curves on January 7, 2014

(Source: PJM)

NYISO dispatched DR for a 6-hour stretch and took the additional step of encouraging consumers to conserve electricity by lowering thermostats and turning off major electric appliances.

It’s too early to get verified performance results, but the main test was passed by avoiding blackouts.

Year-Round DR

The winter is hardly over yet, so there could be more DR activity coming up this season.  The vortex may have been a rare event, but all ISO/RTOs will now take a much closer look at its DR performance requirements for the winter.  PJM is in the process of including an annual DR product that would require mandatory participation year-round, as opposed to its traditional summer-only program.  ERCOT will analyze whether it should increase payments for winter peak periods to incentivize more participation.  ISO-NE was preparing to handle winter grid reliability prior to this season due to the shortage of natural gas pipeline infrastructure in the region, which could lead to fuel shortages for gas-fired generators.  It developed a special winter DR program, which is intended to be implemented prior to the regular emergency DR program, to shore up the system before it reaches that stage.

This new reality will put a lot of stress on DR as an operational resource.  A large portion of typical DR is based on air conditioning curtailment, which is not much help in the winter.  Some large industrial facilities have stable load year-round, and some industries, like ski resorts, have more load in the winter.  However, the majority of commercial and residential customers will not be able to fully participate in an annual DR program.  DR providers will have to be cognizant of where customers’ limits lie, and create new technologies and strategies to minimize pain and maximize performance.


States to Utilities: Modernize the Grid

— January 21, 2014

My recent blog discussed California’s roadmap for integrating demand response (DR) and energy efficiency (EE) into its markets.  Around the same time, at the end of 2013, New York and Massachusetts released orders requiring significant structural changes in the way their electric utilities operate and how demand-side resources are incorporated into the wholesale and retail markets.  It’s valuable to look at these developments as a trend rather than isolated cases.

The New York Public Service Commission’s order approving the state’s EE programs for the next year is typically a rubber stamp.  This time, however, it included some strong language about the future role of EE and DR will play as central components in grid planning.  “The Commission and other policy makers can no longer afford to think of energy efficiency and distributed clean energy resources as peripheral elements of the electric system that require continuous government support.  Rather, the time has come to manage the capabilities of these customer based technologies as a core source of value to electric customers.”  The Commission, therefore, will begin “articulating the broad policy based outcomes” for these clean energy resources that “will result in timely decisions regarding changes to our regulatory model, including performance and outcome based incentives, that will be required to achieve our broad policy objectives.”

10-Year Plan

The Massachusetts Department of Public Utilities, meanwhile, released a long-awaited order on its Grid Modernization program that took place over the past year.  This order establishes four grid modernization objectives: reducing the effects of outages, optimizing demand, integrating distributed resources, and improving workforce and asset management.  The department proposes to require each electric distribution company to develop and submit to the department a 10-year strategic grid modernization plan that includes a comprehensive advanced metering plan.  It plans to address three other specific topics in separate proceedings: time varying rates; cyber security, privacy, and access to meter data; and electric vehicles.

Massachusetts is further along on specifics, but the message is clear that both states see the need for drastic changes to their utility regulatory frameworks.  While some people talk about these developments as the death of the utility industry, California, New York, and Massachusetts all seek to include the utilities as part of the future solution.  They don’t expect instant changes, but they will require faster action than the typical utility is used to.

External market forces may push things even faster than that pace, however, so utilities must become nimble, not relying on the regulators to protect them.  Distributed generation in the forms of solar photovoltaic and combined heat and power will continue to proliferate due to economic and environmental drivers.  Businesses and consumers will demand better service, access to data, and flexible pricing options.  The potential for increased storm activity will necessitate more resilient systems.

The states may make the most public news for grid modernization, but utilities will thrive by staying one step ahead of the regulators and helping to craft their own futures.


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