NEWS

Load Management Under Deregulation Takes Cue from Consumers

Thin reserve margins, spot price spikes, transmission and distribution congestion, rotating blackouts, and interregional arbitrage are just some of the challenges of a restructuring power industry. EPRI is helping power providers and their customers understand how to manage risk and increase profitability in these turbulent times, using Internet-based load management systems.

“Industry deregulation offers new challenges-and opportunities-for companies that can strategically balance system capabilities and customer needs,” said EPRI’s William M. Smith. “Load management has a new market-driven role under deregulation that can benefit all participants, from generator to customer.”

Smith said that energy service providers can gain more control over the price they pay for bulk power through their ability to adjust demand in response to variations in electricity price and availability. Meanwhile, customers participating in the program gain the ability to control their costs through energy management. Distribution companies can benefit from both excess capacity and shortfall situations by targeting particular regions for load growth or demand reduction.

Bonneville Power Administration (BPA), for example, faces challenges of meeting peak demand and buying or selling power at a time when generating capacity is stretched thin nationwide. BPA has been working with EPRI to assess system and customer opportunities for dispatchable load management in their service area.

“We’re a winter peaking organization, and when the Arctic Express forces temperatures down we have to buy power, and that’s expensive,” said BPA’s Bruce Cody. “Secondly, if transmission lines aren’t constrained we can sell power into California on hot days when prices are high. If we can do that without inconveniencing our customers, or if we can let them share in the profits, it’s to everyone’s advantage.”

To gain that advantage, BPA turned to EPRI for help in characterizing the system benefits customers can contribute by participating in load management programs. The next step is to develop supply curves to determine the costs and savings associated with managing different customer loads.

Says EPRI’s Smith, “We have moved into the next generation of load management. The load management of old was generally mandated by regulators to defer investment in new generation, and sold to customers as a way to preserve system reliability. Market-driven load management aims to balance supply and demand through economic as well as reliability triggers. Serendipitously, load management technology has progressed to interactive, real-time, enterprise integration configurations that take advantage of Internet, paging and wireless telecommunications.”

EPRI has developed five programs to help companies implement market-driven load management activities. The programs are described in Destinations, EPRI’s new 2001 offering at www.epri.com/ Destinations/index.html.

ISO New England Piloting Internet-based Load Response Program

ISO New England chose Halloween as the date to announce a new Internet-enabled program that could alleviate some of the fear generated by an overburdened power grid.

The ISO has announced the launch of a pilot program that will provide quantifiable load response capabilities with the click of a computer mouse. The voluntary program utilizes the Internet to enable ISO New England to rapidly interrupt power blocks of participating commercial and industrial customers to decrease demand on the region’s six-state power grid. The pilot project will run from November 2000 to March 2001 for 10 to 15 MW of load from certain customers of New England Power Pool (NEPOOL) companies, including suppliers such as NewEnergy Inc. and Select Energy Inc., utilities such as National Grid and NSTAR, and large customer buying groups such as PowerOptions.

The pilot’s objectives are twofold: to demonstrate that a load response program can increase reliability on the electric power grid and to give C&I customers the ability to respond to price signals in the wholesale electricity marketplace. If the pilot proves successful, a larger Group Load Response Program would be implemented by next summer.

When the cost of power is high, or in the event of a capacity deficiency, participating interruptible customers will be paid to curtail their use of power from the grid-either by cutting back on electricity use or by obtaining power from on-site generation.

“Voluntary load response programs have long been used as a power system management tool,” said Philip J. Pellegrino, ISO New England’s president and CEO. “What is different with this pilot program is that via the Internet, ISO New England will be able to manage load, in virtually real-time, with the click of a mouse.”

The pilot program will utilize Load Management Dispatcher (LMD), an Internet application service developed and supplied by Retx.com of Atlanta, Ga. The LMD will track ISO New England market prices and provide automated notification to the energy service or load provider, or customer, when predetermined opportunities become available in the market.

The LMD will be integrated into the ISO New England’s hourly energy trading platform, which will then stream real-time electronic price signals to the energy company. This information is combined with the commercial customer’s energy usage and load management strategies to establish an economic dispatch opportunity.

ISO New England will begin notification of a potential interruption with a click of the mouse. Once notification is received, the customer can decide whether or not to interrupt its load based on whether the spot energy price exceeds the customer’s desired dispatch point.

Once the interruption is completed, LMD collects end-use customer usage data via a meter data recorder installed at the customer’s site. LMD then provides customer-specific hourly performance data that is matched with the hourly clearing price. This information will allow the ISO to properly credit the customer financially and will have metered data on the amount of interrupted MWs that can be measured against the operating reserve requirement.

Con Edison Reports Distribution Performance Gains

Consolidated Edison Company of New York released data in early October showing that its overall summer 2000 electrical system performance was the best in the past eight years, based on the rate of service interruptions.

When adjusted for the cooler-than-average weather Con Edison experienced in its service territory, the decrease in service interruptions for summer 2000 compared with the previous five-year average was approximately 34 percent. Without the weather-related adjustment, the electrical system’s overall performance data for June, July and August 2000, compared with the previous five-year average, indicates a reduction of approximately 43 percent in the number of customer interruptions.

Con Edison is attributing the improvements to a system-wide reinforcement program that included additional testing, repairs and replacements of feeder cables and components throughout the company’s service area.

“In preparation for this summer, we worked diligently on an ambitious system reinforcement program,” said Robert Donohue, Con Edison’s electric operations senior vice president. “This is just the first year of a five-year program, and it has yielded excellent results.”

As part of the reinforcement program, Con Edison replaced 135 miles of underground and aerial feeder cables and 949 cable joints, installed 170 new transformers, and enhanced and upgraded nine 4-kV substations. Major power transformers were replaced at the Jamaica substation in Queens and at the Greenwood substation in Brooklyn. The company also reported equipment additions and upgrades to at least a dozen other substations.

PricewaterhouseCoopers Expects M&A Activity to Continue in 2001

The utility industry witnessed unprecedented merger and acquisition activity in 2000, but according to the Transaction Services group of PricewaterhouseCoopers, there’s more to come. The group points to the following factors as driving M&A activity in 2001:

  • Utilities remain undervalued relative to the S&P 500 based on historical discounts, despite the industry’s strong relative stock performance year-to-date. Value-unlocking opportunities remain for acquirers.
  • Unregulated independent power producers (IPP’s) have outperformed regulated utilities as the markets have placed a higher relative value on generating and trading assets. Look for IPP’s to arbitrage their high P/E multiples, as well as decent credit ratings, to acquire generating assets from traditional utilities that currently trade at relatively lower P/E multiples.
  • Deregulation has taken firm hold both in Europe and in certain states in the United States. UK utility operators, in particular, are expected to continue to be strong acquirers. The deregulation process in the United States will drive industry consolidation in 2001, as domestic companies look to become “super-regionals” with the scale to survive as independents.
  • Besides the large “super-regionals” that will focus on being low-cost producers, look for the advent of new energy service companies. Much like the “one stop shopping” strategies implemented by companies in the recently deregulated financial services and telecommunications industries, these energy services companies will aim to be multi-service and technology providers. Mergers, acquisitions, joint ventures and strategic alliances will be integral components of building the new energy services companies.
  • The business customer is critical. With up to 50 percent of revenues for the typical U.S. utility coming from the C&I market, utilities that can’t meet the demands of business customers will soon find themselves vulnerable to takeovers by those who can.

Two Natural Gas Utilities to Expand AMR Capabilities

In early October, two natural gas service providers announced large-scale purchases of Itron automatic meter reading (AMR) equipment to enhance service quality in their respective territories.

Bay State Gas, the Westborough, Mass.-based subsidiary of NiSource Inc., will purchase from Itron 261,000 AMR meter modules along with a mobile AMR data collection system and meter reading software to automate approximately 240,000 residential gas meters and 21,000 commercial and industrial gas meters throughout the Bay State service territory.

“In today’s highly competitive energy marketplace, state-of-the-art AMR technology is critical to reducing the cost of service while improving the quality of service,” said Kenneth Margossian, executive vice president of Bay State Gas.

Michigan-based SEMCO Energy Inc. began deploying Itron AMR technology in late 1996, and in early October 2000 announced the purchase of an additional 60,000 Itron radio meter modules. The purchase enables SEMCO to expand its AMR capability in its home service territory in southeastern Michigan, as well as in its subsidiary ENSTAR Natural Gas’ Alaska service territory.

SEMCO’s latest purchase of AMR technology follows the late-1999 purchase of 50,000 Itron radio meter modules. SEMCO began deploying the technology in late 1996 and to date has automated more than 75 percent of its 250,000 meters in Michigan. SEMCO expects installation in its Michigan territory to be completed by the end of 2000.

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The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

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