Pepco Exec: Industry Dealing With ‘Unintended Consequences’ From FERC Order 1000

by Corina Rivera-Linares, TransmissionHub

No one knows how FERC Order 1000 will affect the electric industry because of unintended consequences in how entities work together, said Michael Maxwell, vice president of asset management with Pepco Holdings Inc.

“Now there’s this competitive streak that Order 1000 has kind of laid out,” Maxwell said during a panel on extreme weather and T&D, part of TransmissionHub’s TransForum East in Washington, D.C.

In addition, it is not only the utilities identifying the projects and working together, he said; PJM Interconnection also must deal with evaluating those projects.

“If you think about what you have to do now in terms of presenting a project to PJM, you end up having to build whole organizations to support that level of effort moving forward,” Maxwell said. “So we’re having to adjust to this new world order. I’m not sure what’s going to be (on) the other side of this rainbow ” but we’re going to have to work hard to figure it out as we go along.”

Because utilities cannot replace everything at one time, they must plan to replace assets over a period, Maxwell said.

“The electric system ” was built over 100 years,” he said. “You’re not going to rebuild it within 10 or 12.”

Fellow panelist Consolidated Edison Co. of New York (Con Edison) engineer Griffin Reilly said that building its infrastructure is “business as usual” for Con Edison. Electric storm hardening, he said, is “essentially just accelerating our replacement program with these investments.”

Panelist Ken Collison, vice president at ICF International, said other factors such as generation retirements involving coal plants factor in transmission planning, as does the gas-electric integration matter.

The panel also included Edison Electric Institute (EEI) Manager of Federal Regulatory Affairs Karen Onaran. On the one-year anniversary of Hurricane Sandy’s landfall on the East Coast, the panel discussed storm restoration and grid reliability.

Each jurisdiction Pepco serves–the District of Columbia and parts of Maryland, Delaware and New Jersey–has a different view on what is considered reliability, resiliency and hardening efforts, as well as its response to recent weather events, including Hurricane Sandy, Maxwell said.

Some of the bread-and-butter projects Pepco presents to state regulators when asked how it is improving reliability include vegetation management, he said.

In New Jersey, Gov. Chris Christie reached out to Pepco’s Atlantic City Electric and all the utilities in the state to develop a package of resiliency projects, including micgrogrids, to help ensure that the state will be better prepared if another event like Hurricane Sandy occurs.

In Maryland, the governor and state regulators reached out to Pepco and Delmarva Power, as well as the other utilities to come up with resiliency projects to improve the system.

Washington, D.C., Mayor Vincent Gray has said the nation’s capital should not have outages that last more than a couple of days and requested a game-changer, Maxwell said.

The mayor in August 2012 established his Power Line Undergrounding Task Force, which includes government officials, regulators, local utility executives, public advocates and residents to address power outages in the District of Columbia as a result of the derecho thunderstorm system that left extensive wind damage across the region in June of that year.

An interim report accepted by Gray in May calls for a multiyear program estimated at nearly $1 billion in a first phase to selectively underground up to 60 high-voltage lines that are most affected by storms. The task force recommended a financing arrangement through an approximately even split between the District of Columbia and Pepco.

Reilly said five of the top 10 storms in Con Edison’s history in terms of electric outages happened within the past four years, including Hurricanes Sandy and Irene and the October 2011 snowstorm.

“We see a trend, whether or not you want to call it climate change “,” he said. “There’s definitely something happening in our region, and we need to address that.”

Reilly described Sandy’s impact on Con Edison’s system, including the damage to its East 13th Street substation from flooding and the wind damage to its overhead system.

Con Edison has made numerous improvements to its energy delivery systems as part of a $1 billion plan to fortify critical infrastructure and protect New Yorkers from major storms, including building more than a mile of concrete flood walls around stations and critical equipment, Reilly said.

After Sandy, state regulators launched investigations into utilities’ responses, including the Connecticut Public Utility Regulatory Authority, which found that utilities performed in a “generally acceptable manner” regarding that storm.

Maxwell said it is regulators’ role to hold utilities accountable, but regulators also react to political and public pressures.

“Despite what they had been doing prior in terms of regulating us and looking at reliability and looking at how the utilities operate, when the heat is turned on, the behaviors of the commission changes, and they will launch investigations,” he said.

Regulators must balance understanding their roles and determining the appropriate cost for measures and appropriate things to be done, Maxwell said.

Similarly, Reilly said Con Edison’s $1 billion plan to address flood risk and the potential for wind damage likely would have been met differently by regulators three years ago.

“The public is now seeing that there is the risk (and) they’ve all been impacted by it,” he said.

Collison agreed it is easier to get investments into the system after extreme weather events.

“Is there a way to show how those investments have improved the system?” he said. “If there’s a way to show that, it may be easier to build on that in the future.”

Some utilities have described how installed smart grid equipment helped them restore power faster. Another thing that could help is looking at what other utilities, regions and countries have done to improve resiliency on their systems, Collison said.

“We found examples where certain countries, certain regions, certain states had policies that allowed for selective undergrounding,” he said. “It’s expensive, but if you see how others have addressed it, that could be a way that you could also find ways to do that for your system.”

Onaran said utilities need to be held accountable to some extent, but the approach should be from more of a learning experience and in a collaborative fashion rather than just having regulators fine utilities.

She said EEI’s report “Before and after the storm: A compilation of recent studies, programs and policies related to storm hardening and resiliency” helps EEI’s member companies work with state regulators and customers and pick options that work best for them.

In working on its report, EEI reviewed efforts in various regions including undergrounding, microgrids, vegetation management, increased labor forces and smart grid initiatives.

“This gave a general idea of what are the options out there that are available and what works best for your state, your utility,” she said.

An updated EEI report will be released in January, she said.

The national response event that occurs when several regions become depleted in their resources is an EEI initiative that came directly out of Sandy, Onaran said. A national response executive committee of utility CEOs and senior execs overlook the pooling of all requests for crews and equipment, for instance, and allocating is based on need, she said.

“We want to make sure that at this point, we are responding as one industry and not individual utilities,” she said.

Eye on the World

GE Helps ELMAR Modernize Aruba’s Electrical Grid

To create a modernized electrical network and equip Aruba with secure, high-capacity and long-range wireless coverage for its complete network, ELMAR–the country’s power utility company–has turned to GE’s RF Grid IQTM point-to-multipoint (P2MP) advanced metering infrastructure (AMI).

The installation of GE’s AMI solutions will create an all-encompassing wireless metering network, providing ELMAR with crucial electrical usage and power generation data to improve grid efficiency and functionality while enabling grid integration of renewable energy sources.

“Part of Aruba’s energy plan for the future is to generate more renewable energy and implement it into its electrical grid, with the long-term goal of becoming a 100 percent green country,” said Robert Henriquez, director of ELMAR. “GE’s Grid IQ P2MP AMI solution provides utilities with important information such as how much power is generated by a country’s wind farms and solar power facilities and when the majority of this power is being generated, helping them to better understand their electrical grid and what can be done to optimize it.”

Modernizing the Grid

With the RF Grid IQ AMI solution, GE introduces its first AMI product offering specifically designed for global smart meters applications. The wireless AMI network rolled out in Aruba will encompass 170 P2MP meters interconnected via seven access points, each of which is capable of communicating with up to 20,000 smart meters and 64,000 distribution automation devices within a 40-mile radius–some 1,980 square miles. Aruba’s seven new access points enable the island’s entire installed smart meter base–48,000 to date–to efficiently and effectively communicate crucial data back to ELMAR to be analyzed. This infrastructure also will allow for network expansion by as many as 140,000 meters and 448,000 distribution automation devices without additional investment. For the first six months of the operation, ELMAR will be able to access and use GE-hosted monitoring software to help maintain its new wireless AMI network.

Optimization Modeling Helps Control Electricity Supply Continuity in Brazil

For boaters, fisherman and others, a lake filled with water is an opportunity for recreation. But for an organization such as Operador Nacional do Sistema Eletrico (ONS) in Brazil, a full lake behind a hydroelectric dam is also an optimization challenge that must be addressed to provide reliable electric power at a stable cost.

Brazilian power system generation is dominated by hydroelectric sources that use large reservoirs that allow multiyear regulation. As of 2010, the country’s power generation facilities included more than 200 major power plants, of which 141 were hydroelectric. The hydro facilities account for 77 percent of Brazil’s installed generating capacity and are in 14 large river basins with their generation interconnected to take advantage of hydrological diversity between the basins.

Because the hydro plants use water stored in reservoirs to generate electricity, operators must decide when to use the water. Because the water inflows depend on rainfall, the amount of water available for future power generation cannot be predicted with high accuracy. Moreover, historical records indicate the possibility of dry periods, which place a burden on hydro generation and might require the use of thermal power plants to meet demand.

ONS uses a complex computer algorithm that models the system to help ensure electricity generation meets the demand at minimum expected cost, planning the generation of power based on such information as electricity demand forecast and water inflow scenarios based on the historical data. The system also sets the monthly price of power for the country; however, during the early part of this century, power rationing in Brazil called into question the validity of meeting day-to-day needs using a policy based on minimizing the expected cost of power.

Alexander Shapiro, a professor in the Stewart School of Industrial and Systems Engineering at the Georgia Institute of Technology, is an expert on optimizing systems using stochastic programming.
Alexander Shapiro, a professor in the Stewart School of Industrial and Systems Engineering at the Georgia Institute of Technology, is an expert on optimizing systems using stochastic programming.

To improve the system, ONS decided to develop a methodology for adding a risk-aversion criterion to the planning model. Four years ago, it contacted Alexander Shapiro, a professor in the Stewart School of Industrial and Systems Engineering at the Georgia Institute of Technology. Shapiro is an expert on optimizing systems using stochastic programming, a technique useful for modeling complex systems when not all input parameters can be known.

“The usual criteria used for our planning purposes took a neutral approach to the risk of energy supply failure,” said Joari Paulo da Costa, a research engineer with the Methodology Development Department of ONS in Rio de Janeiro. “During earlier energy rationing, it turned out that this approach was not sufficient and that some measure of risk aversion had to be taken into account by the planning model. An ad-hoc procedure had been implemented, but only with the results of the risk-averse methodology proposed by professor Shapiro have we achieved a proper inclusion of these concerns into the methodology and computer program.”

During the course of the project, Shapiro visited Brazil several times to confer with ONS officials, including da Costa and Murilo Pereira Soares, a senior engineer.

“If they don’t have enough water, they have to use more expensive generation sources,” Shapiro said. “The algorithm they have been using sometimes produces high prices for electricity that, although fully justifiable within the mathematical framework, do not conform to the expectations and are not intuitive.”

The system presented a classic optimization challenge concerning the use of a resource whose future availability could not be determined accurately.

“The risks in the system are very simple,” Shapiro said. “When you have water in the reservoirs, you can either use it now, which makes electricity very cheap now, or you can hold onto it. If you use it now, in a few months you might not have enough water to produce the electricity you need.”

Shapiro and former doctoral student Wajdi Tekaya worked with ONS to understand the problem formulation and suggested modifications that would reduce the risk of energy supply failures. The changes they made rely on stochastic programming, which is often used for modeling optimization programs that involve uncertainty.

“We developed a methodology for how to control the risk of energy shortages while optimizing the use of water,” he said. “We also wanted to control the risk of price spikes. It is a very complex system.”

The project also provided a computer implementation of the proposed methodology. This prototype served as a proof of concept, which played a fundamental role in validating the proposed methodology.

The new risk-averse methodology developed in the collaboration between Shapiro and ONS has been integrated into the computer program being used to set operational policy and prices for the Brazilian Interconnected Power System, da Costa said.

The methodology developed by Georgia Tech and ONS potentially could be applied to other power generation systems, as well as to other operations in which uncertain natural resources such as water supplies must be used to meet the demand for electricity or other products.

“The approach to managing risk is very general and could be applied in other areas,” Shapiro said. “The approach is a new one that could be used to reasonably control the risk.”

In real-world optimization problems, decision-makers rarely have all the information they want, so decisions must often be made on incomplete data.

“We have to make the best decisions with the information that we have,” Shapiro said. “We all know the past, but we cannot know the future. We have forecasts, but we do not know for sure what will happen.”

Sabre Industries Celebrates Grand Opening for Sabre/Brametal Testing Services in Texas

Sabre/Brametal Testing Services

Sabre Industries Inc. recently celebrated a grand opening for its new testing facility, Sabre/Brametal Testing Services LLC.

Developed with Brametal’s extensive testing experience, the new facility is the result of Sabre’s joint venture with Brametal, S.A. A subsidiary of Hollmore Participacoes E Investimentos S.A, Brametal is a Brazilian company with experience in engineering, design and testing of lattice transmission towers.

Sabre/Brametal Testing Services is located on Sabre Industries’ 147-acre industrial complex in Alvarado, Texas, and is the only one of its kind in North America. Completely automated, the facility provides full-scale structure testing on lattice towers and tubular steel poles. Also located on Sabre Industries’ industrial complex in Alvarado is Sabre Tubular Structures, Sabre’s steel pole division, and Sabre Galvanizing Services, one of the most environmentally friendly galvanizers in the United States.

“Working with Brametal to develop our new testing station has given Sabre the opportunity to build a best-in-class testing facility for our utility customers,” said Peter J. Sandore, president and CEO of Sabre Industries Inc. “We will be the only company in the United States to offer this type of testing along with engineering, design, manufacturing and galvanizing of tubular steel structures all on one site.”

Proprietary software allows for simulated loads that automatically are applied to provide realistic and accurate results. The facility offers destructive and nondestructive testing and can test towers up to 235 feet high and 85 feet wide at the base and poles up to 235 feet high and 12.5 feet wide.

“Sabre/Brametal Testing Services LLC is pleased to be able to bring full-scale structure testing back to North America,” said Ricardo Minatto Brandão, chairman of the board of Brametal. “Through our joint venture with Sabre, we can offer our customers in the United States testing without the added cost of shipping structures overseas.”

FirstEnergy Announces $2.8 Billion Expansion of Transmission Initiative

FirstEnergy Corp. plans to invest an additional $2.8 billion over four years to expand its previously announced Energizing the Future transmission initiative. The focus of the initial construction effort will be the 69-kV transmission power lines and substations in the Ohio Edison, Cleveland Electric Illuminating Co., Toledo Edison and Penn Power areas. The program is expected to expand into other FirstEnergy service territories.

“Our work on the backbone of our network will focus on enhancing the service reliability to the communities, businesses and homes in our service areas,” said Anthony J. Alexander, president and CEO of FirstEnergy. “The average age for much of this equipment is more than 40 years old. Our goal is to replace outdated equipment with state-of-the-art smart technology that can be operated remotely in order to help prevent some outages from occurring. And if an outage does occur, the new equipment can help reduce the number of customers who are affected and shorten the duration.”

Work on the new Energizing the Future projects is expected to begin in 2014 and continue through 2017. The 69-kV system is the vital link between the high-voltage transmission lines and the distribution network that provides power to end-use customers. As part of this program, some 7,200 circuit miles of 69-kV and higher transmission lines will be evaluated and rebuilt as needed. More than 170 substations will be inspected and upgraded, along with 70,000 transmission structures that will be evaluated and rebuilt as needed. The scope will involve adding redundancies to the network, which is designed to enhance customer service reliability. Work also will be done to improve security at substations by adding fencing, thermal imaging devices and various surveillance options. Some of the projects will be done by FirstEnergy, but certain work will be completed by area electrical contractors. Over four years, this program is expected to put more than 1,100 contractors to work, the majority being union workers from northeastern Ohio.

Once operational, FirstEnergy’s investments are expected to benefit the communities where the company has substations, transmission lines and equipment by increasing tax payments, which will support local schools and police and fire services. Because most of the work will be done on the company’s existing rights of way or existing substations and other facilities, the environmental impact to communities is expected to be minimal.

Overall, the new transmission projects are designed to increase FirstEnergy’s load serving capability in areas where future economic growth is anticipated, particularly in Ohio’s shale gas regions; improve reliability of service; create more flexibility to restore service after storms; reduce line losses; and lower the company’s overall transmission maintenance costs.

The Energizing the Future initiative previously was announced in May 2012 as part of FirstEnergy’s ongoing commitment to enhance its high-voltage transmission system. Many of the projects, including new or rebuilt high-voltage power lines, new substations and the installation of specialized voltage-regulating equipment, are needed to help support system reliability as coal-fired power plants in the region are deactivated based on the Environmental Protection Agency’s Mercury and Air Toxics Standards and other environmental rules. These initial Energizing the Future projects represent about a $1.8 billion investment in Ohio, Pennsylvania, West Virginia, New Jersey and Maryland over the next five years.

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