By Hisham Othman, Ph.D., Petra Solar

Nationwide, more and more utilities face policy mandates to adopt renewable generation. While integrating renewables such as solar power delivers clear payoffs, it requires utility professionals to successfully navigate regulatory hurdles, community relations, power quality control and distribution management. Here are the ten most critical steps utilities must undergo when integrating renewables.

1 Examine the economics.

The economics of solar vary by location. Factors such as fuel cost, the availability of state incentives and insolation (the amount of sun that falls on a region throughout a year) all influence the bottom line. Even regions with current access to affordable fossil fuels cannot count on the predictability of future prices. Factoring in “externalities” (economic costs traditionally excluded from bottom-line calculations) such as pollution and carbon emissions makes solar a clear economic winner.

2 Get the regulatory case in order.

It’s important to begin the conversation with regulators early in the deployment process. For example, local regulations might specify whether a distribution company can own its own generation assets, whether there are feed-in tariffs in place to incentivize solar and whether the solar investment can be added to the regulated asset base. Establishing your regulatory case is critical to determining return on investment. (In other words, it is necessary information for fully completing Step 1.)

3 Choose between utility- and consumer-owned solar.

One of the most significant choices utilities face is whether to purchase solar assets or to encourage property owners to purchase them. Utility-owned solar can prove to be a money-maker for the utility by putting in place a solid long-term generation asset, but it demands a more significant upfront investment. Ratepayer-purchased solar, on the other hand, requires less upfront investment from utilities and lessens demand on existing generation assets, but it means utilities forego revenue from selling electricity and often requires a significant ongoing maintenance effort.

4 Choose between centralized and distributed solar.

Large, utility-owned solar farms have their benefits; they are well defined within the transmission and distribution system and are relatively easy to manage. Nevertheless, distributed solar—local sources of solar energy on rooftops, utility poles and other existing infrastructure—has a number of advantages over centralized solar farms. Distributed solar is often easier to site and permit and has a lower negative impact on the environment than centralized solar. Distributed solar installations also hedge against the possibility of local weather events, such as passing clouds, impacting generation. Additionally, a happy outcome of deploying distributed solar is that the distribution includes building distributed sensors and meters across the network. This translates into building a smart grid as you go, a fact that adds significant value to a deployment and changes the economics of distributed solar considerably.

5 Decide how to finance your solar.

One finance option is a power purchase agreement (PPA), in which a developer builds the solar system and the utility signs a 20-year to 25-year agreement with them to purchase power. Another option is to lease equipment through a bank and sell the energy the equipment generates, or utilities may elect to invest directly and increase the asset base.

6 Design your communications infrastructure.

Distributed solar power offers a huge opportunity to deploy advanced grid communications without significant infrastructure adjustment. Distributed generation assets, such as solar panels placed on utility poles, can house communications devices to monitor grid activity and prevent blackouts.

7 Consider reactive power needs and capabilities.

Reactive power requirements to ensure voltage quality—in which reactive energy flows and there is no net transfer of energy to the load—may be changed by the integration of high levels of solar. Incremental reactive power requirements can be specified to be integrated within the solar panel inverter. Alternatively, the utility can build a reactive support on the circuit to address all the needs of the local community.

8 Examine system management.

Consider how to integrate solar assets within utility operations. Assuming a utility has decided on distributed solar with some communications and monitoring capabilities, the utility will start collecting a massive amount of data including voltages, frequencies and temperatures. Make good use of this valuable data and use it to drive operational improvements. Integrate all of the incoming data into the distribution management system (DMS), SCADA, graphical information system (GIS) and outage management system (OMS).

9 Get the community involved.

Ensure that the community knows in advance and fully understands its new assets. Address community members’ concerns from the outset with a dual goal of stemming criticism and of drumming up enthusiasm. Community enthusiasm for solar will ease your deployment process and allow you to roll out demand response programs in the future. This step is simple when people are educated on the potential financial benefits from solar.

10 Think long-term. Take advantage of your new assets to integrate emerging technologies and meet challenges as they develop. Planning for distributed solar also prepares the grid for future developments like electric vehicle charging stations and energy storage. Like a human, a smart grid has ears to listen, a voice to communicate, a brain to process information and the capability to mature over time. Capitalize investments in solar to cultivate that grid, enabling it continually to grow smarter.

Hisham Othman, PhD, is vice-president of professional services and manager MEA at Petra Solar; he leads corporate consulting services globally and manages corporate activities in the Middle East and Africa.

Grid Modernization: The Social Factor

By Laura Elena Ortuàƒ±o, Frost & Sullivan

According to Frost & Sullivan’s recent research, the North American advanced meter infrastructure (AMI) market was $2.73 billion in 2011 and will continue to grow in the future.

The benefits and virtues of an intelligent grid have been exhaustively analyzed. A few drivers of grid modernization include:

A decrease in urgency to expand transmission lines and develop new power plants.
Enhancing service with fewer blackouts.
Reducing electricity prices for consumers based on behavioral changes in their energy consumption habits (through critical peak pricing and demand response).
A more sustainable energy-conscious resource use and the ability to incorporate devices that produce clean energy to be injected into the grid (i.e. solar panels, wind generators, plug-in hybrid electric vehicles).

Nonetheless, these projects have faced opposition. One of the main concerns regarding smart grid implementation is privacy, along with the need for policies assuring that data collected by utilities is protected and utilized properly. There’s a significant risk that user consumption data may be used for purposes ranging from targeted marketing to determining a household’s habits. Individuals’ electricity usage patterns describe their lifestyle, and that is why privacy is such an important topic for end-users.

In addition, the social implications of these “smart” initiatives must be examined in order to evaluate the diverse effects these projects can have on certain communities. The U.S. is currently facing a recessive period in the economy and a higher-than-average unemployment rate. In this context, some of the additional applications enabled by the deployment of AMI projects could result in adverse reactions from the community that could transform hesitation into potential social tension.

Features such as remote connect/disconnect that allow utility companies to interrupt and shut off services without having to step foot in the household must be properly addressed and regulated. The same occurs with the prepaid plans being offered by some utilities that may limit usage. Low-income consumers may feel threatened by these initiatives. Thus, it is imperative to establish proper regulations and implement policies to protect the consumer. This must be done educating the consumer and establishing engagement programs, which must play a big role in paving the way for smart grid deployment.

In order to effectively address these issues, it is extremely important to insure that a more intelligent grid does not result in adverse reactions. In this sense, the 2010 California Senate Bill 1476 serves as an example of a law that addresses disclosure and privacy regulations of smart meter data. Models to follow in successful consumer education and engagement programs include: San Diego Gas & Electric, AEP Texas and Bluebonnet Texas. Each prepared for smart meter deployment by creating proactive campaigns that, by imparting effective training sessions for better customer energy awareness, delivered a satisfied customer experience.

As grid modernization continues to show a boosted growth, it is important to keep in mind that social factor, which calls for sensible solutions within a sensible context.

Laura Elena Ortuàƒ±o is a research analyst with Frost & Sullivan.

Survey Reveals Utility Telecommunications Outlook

Newton-Evans Research Co. Inc. completed a three-volume report series focusing on data communications in the electric power industry. Survey findings from over 100 electric utilities worldwide include:

Eighty eight percent of utility respondents agree that open protocols provide a degree of protection from premature product obsolescence, but 58 percent indicate they have experienced products that are supposedly standardized/open/interoperable which have not functioned as expected or as the vendor promised.
Only 11 percent of respondents think that synchrophasor technology will be a main driver in smart grid communications requirements, and 10 percent believe that synchrophasors will be the catalyst to adopt IEC standard 61850. Forty-eight percent were neutral regarding either statement.
As the table illustrates, when asked to list some of the key data communications issues facing their utilities, the three most frequent responses were cost, reliability and security. Technology obsolescence, bandwidth, interoperability, lack of standardization, spectrum availability, NERC CIP compliance, latency, terrain-topography and scalability also were mentioned.

Survey participants also were asked what vendors should do to address these issues. The most frequent sentiment could be paraphrased as: “Be more attentive to utility requirements, communicate more and work together.” This was followed by comments mentioning standardization.

This feedback clearly indicates that utilities expect more cooperation from communications equipment suppliers and services providers. Collaborative research and development may provide a feasible compromise.

Additional information on the three volume study “Global Study of Data Communications Usage Patterns and Plans in the Electric Power Industry: 2011-2015” is available from Newton-Evans Research Co. Visit https://newton-evans.com to access the report brochure.

EPRI Publishes CIM Report

The Electric Power Research Institute (EPRI) has published a technical report titled “Common Information Model Primer.”

The primer explains the basics of the common information model (CIM). Starting with a historical perspective, it describes how the CIM originated and grew through the years. The functions of various working groups of Technical Committee 57 of the International Electrotechnical Commission (IEC) are described. The process of how an IEC standard is created is also outlined.

The basics of the unified modeling language (UML) are detailed to introduce the reader to the language of the CIM. Then, building on commonly understood objects (basic shapes), the concepts that underline the CIM are carefully built step by step. The reader is then transported into the world of power systems where the concepts that were developed previously are applied to the complexities of the electric grid.

The CIM is a set of open standards for representing power system components originally developed by EPRI in North America and now a series of standards under the IEC. The standard was started as part of the Control Centre Application Programming Interface (CCAPI) project at EPRI with the aim of defining a common definition for the components in power systems for use in the energy management system (EMS) application programming interface (API) now maintained by IEC Technical Committee 57 Working Group 13 as IEC 61970-301.

More information at https://epri.com.

Analyzing, Measuring and Communicating Data over a Smart Grid

By Markus Staeblien, Texas Instruments Inc. (TI)

Each country and utility has its own reasons, strategy and understanding for a smart grid; therefore, different technologies are required to meet those needs. These technologies would not exist without a semiconductor solution—analog components that attach to the line to condition the signals and digital components for analyzing, measuring, calculating and communicating data over a smart grid.

Measuring energy is a key functionality and finds its place in various portions of the grid such as generation, distribution and consumption of energy inside or outside of a building. Energy measurement during generation and distribution is much more complex than at consumption. The efficiency and quality of energy generation and distribution relies completely on the ability of the systems to measure key components with high accuracy. Key parameters that quantify the quality of power are variations in voltage levels (HV, MV), transients, surges, harmonic content, protections, etc. The electronics that are needed to capture and maintain quality are comparatively more expensive and intelligent with self-healing capabilities. Voltage and current are analog signals, with the power being an instantaneous product of the two. A challenge faced by most engineers is choosing the right type of sensors and converting the analog waveforms accurately for processing with digital computers.

The measuring devices in high-end meters now rely on the frequency-domain analysis, in addition to time-domain parameters calling for high-end digital signal processors (DSPs). These generally reside in substations and power plants. If the quality of service is maintained, the focus shifts to the transmission, where emphasis is given to loss minimization, continuity of service and intelligent load management. Once the power is available for consumption in buildings, the meters are less complex and form two sets of metering spaces called utility metering and sub-metering. Depending on the load that needs to be serviced and the region’s grid structure, the energy is available as three-phase or one-phase. Meters measuring energy outside are utility meters and inside are sub-meters. Utility meters always involve billing by monetary means, whereas sub-meters rarely involve money. Irrespective of the meter type, the measuring parameters include voltage, current, power factor, active/reactive power and energies, and the ability to track time-stamped usage. The expected accuracy of utility meters is much more stringent (usually within 0.5 percent to 0.1 percent error) than sub-meters (within 1 to 2 percent).

Without communication, the energy usage of appliances such as HVAC systems, dryers, heaters and plug-in electric vehicles (PEV) is unknown to utilities and energy customers. Communication enables the consumer and utility to gather information in real-time and allows utilities to ease energy usage within the capacity of their power grid. This also permits data to be consolidated within residences, multi-dwelling structures or industrial facilities. Wireless connectivity technologies such as Wi-Fi (IEEE 802.11) and ZigBee (IEEE 802.15.4) RF mesh networking have become popular alternatives in the past several years. These operate in the 2.4 GHz ISM band and at 900 MHz. There are other technologies, such as wireless M-Bus, that operate at frequencies around 170 MHz. There is currently wide deployment of RF mesh technology in smart meters, especially in urban areas where residences are closely spaced.

Wireline communication for smart grid applications uses power line communication (PLC) technology to exchange data over existing power lines. To achieve cost effectiveness without using repeaters, transmission distances on outdoor power lines should be at least 2km, and reliable transmission through distribution transformers outside residences is sometimes necessary. Communication between 10 Kbps and 100 Kbps is necessary for demand response applications and meeting latency requirements of applications such as PEVs. The PLC technology that best meets global broad application needs and cost effectiveness is narrowband OFDM (orthogonal frequency division multiplexing), which has become very popular over the past decade.

Markus Staeblien is TI’s general manager, smart grid business unit.

How Vendor Mergers are Shaping T&D (Revisited)

By Mark Hatfield, Black & Veatch

The July 2007 issue of Utility Automation and Engineering T&D (now POWERGRID International) contained an article on “How Vendor Mergers are Shaping T&D” by authors from Enspiria Solutions (now Black & Veatch). This article revisits the topic to look at merger and acquisition (M&A) activity during the last three years among energy solution providers.

After a lull of activity with the start of the recession, the market is active again, and there’s an increase in mergers and acquisitions (M&A) and public financing activity among energy solution providers. Primary drivers for the activity are utility investment in smart grid projects, infusion of Department of Energy (DOE) capital to smart grid initiatives, and a regulatory and political environment encouraging additional investment. A company’s decision to be involved in M&A activity or to pursue public financing involves many considerations by multiple parties. However, we have categorized recent activity into three major trends: filling in the gaps, taking advantage of a hot market and expanding footprint (see table).

“- Filling in the gaps: As the number of smart grid projects accelerated following the recession, a utility could not go to a single company for a complete, end-to-end advanced metering infrastructure (AMI) or distribution automation (DA) project. There were vendors that had multiple components, but no vendor could provide all the services and expertise a utility needed to complete a project (The gap was smaller for AMI projects than DA projects but still existed.) Utilities found that they needed to select software applications and smart grid hardware from among multiple vendors. And they often needed multiple consulting and system integration firms to support their projects. As a result, there is a trend for existing smart grid vendors to make acquisitions to fill in the gap(s) of their offerings. For example, Cooper purchased Eka Systems to get a jump start in RF-based AMI. ABB expanded from their distribution and hardware focus with the addition of Ventyx’s strong software capabilities in utility operations and analytics. Schneider added an extensive software application suite to their traditional hardware expertise. Silver Springs Networks and Tendril purchased Greenbox Technology and Grounded Power, respectively, to strengthen their home energy management offerings. These acquisitions do not alleviate the possibility that the utility may need multiple vendors or need to hire project management or system integration expertise. However, they do strengthen the product offerings and product footprints of these companies, especially if they can integrate the products into a common framework and provide robust product integrations among their offerings.

“- Taking advantage of a hot market: Many smart grid companies established prior to the market capital infusion were either wholly owned by venture capital firms or had a significant venture capital investment. The surge in smart grid revenues and associated contract backlogs has provided the best opportunity in many years for venture capital firms and employee owners to realize the gains. It is no surprise, therefore, to see a number of smart grid companies being sold or pursuing initial public offerings. At the same time, venture capital continues to flow into smart grid companies, suggesting M&A activity is not finished. Most of the original companies shown in the table under “taking advantage of a hot market” are AMI companies. It is interesting to note that companies with traditional smart grid hardware offerings, such as ABB and General Electric, are not buying AMI companies, at least not at this time. And there are certainly opportunities for them to do so. It will be interesting to watch the activity for the next year to see if AMI vendors become appealing to companies looking to fill in the gaps.

“- Expanding footprint: The smart grid wave also created opportunities for forward-looking companies to expand their piece of the pie. The table shows several small- to medium-sized companies that had traction in the smart grid space who were purchased by significantly larger consulting or engineering firms. In these transactions, the larger firms sought to enhance their market presence and/or fill a strategic need. The challenge with any merger and acquisition is integration of both the personnel and the product assets and determining how best to build on the collective strength and intellectual talent.

With the regulatory environment continuing to encourage smart grid investment, we do not expect to see any decrease in M&A activity for some time.

Mark Hatfield is a principal consultant at Black & Veatch.

Eastern Interconnection Grid Planning Completes First Phase of Study

The Eastern Interconnection Planning Collaborative (EIPC) has completed the first phase of study of “resource expansion futures” defined by stakeholders as part of an electric system transmission planning effort funded by the U.S. Department of Energy (DOE).

“The EIPC has reached a major milestone in completing the macroeconomic analyses of stakeholder-defined resource futures in Phase 1 of the project and in finalizing a comprehensive report on this work. The stakeholders also have defined three scenarios to be studied from a transmission perspective in Phase 2 of the project,” said Stephen G. Whitley, president and CEO of the New York Independent System Operator (NYISO) and chair of the EIPC Executive Committee. “We are encouraged by the collaborative approach taken by the stakeholders and state representatives who form the Stakeholder Steering Committee charged with providing input and strategic guidance to the project.”

The final report from Phase 1 of the project is posted on the EIPC website at: https://www.eipconline.com/Resource_Library.html.

EPRI: January Solar Storm put Utilities on Alert

The sun hurled billions of tons of plasma at up to 5 million mph toward Earth on Jan. 24 and 25, producing a dazzling light display in northern regions of the world. Radiation from the explosion made the trip to Earth within 34 hours after the solar explosion. The event put the nation’s utilities on alert for possible power grid disruptions.

The Electric Power Research Institute (EPRI) measures geomagnetically induced currents (GIC) through its Sunburst program, a system of strategically positioned monitoring sites throughout the U.S. and Canada. It uses data from that system to provide guidance to utilities on keeping the power delivery system functioning during solar storms and to provide feedback to those developing GIC models and forecasting tools. In the future, models of the power system designed to evaluate the flow of GIC could be included to enhance the capability of the system.

The Sunburst monitoring system recorded minor levels of GIC beginning at about 10:04 a.m. Eastern Standard Time on Jan. 24. This was the result of a solar flare that erupted early Jan. 23. During this event, only one Sunburst site in the EPRI measurement system exceeded 10 amps of dc current on the neutral, and it did so for less than a minute. (GICs are quasi-dc and can cause saturation of transformer windings if the levels are high enough and last for extended periods. Currents less than 10 amps generally are considered low-risk for causing transformer problems). Low-level GICs were measured at most other Sunburst sites.

The largest dc currents generally coincided with the onset of the event. Most of the GIC activity occurred between 10:04 a.m. and about 1 p.m. Eastern Standard Time on Jan. 24. Activity continued through Jan. 25, but at much lower levels. Some sites recorded neutral dc currents that approached 5A twice during the first half of Jan. 25.

The following table lists the neutral current levels by site. Only sites that experienced significant GIC levels are included:

Central Hudson-Pleasant Valley: -5.2A to 8.6A
Central Hudson-Hurley Avenue: -6.2A to 5.5A
CMP/BHE-Chester: -6.5A to 5.5A
Manitoba Hydro-Grand Rapids: -9.1A to 9.7A
Con Edison of New York-Goethals: -9.4A to 4.7A
Tennessee Valley Authority-Paradise: -25.0A to 11.1A
National Grid Co.-U.S.-New Scotland: -2.7A to 1.5A

Figures 1 and 2 are two sample plots of data recorded during this event.

Characterizing Geomagnetic-induced Currents during solar storms

The highest neutral currents measured during this storm were at Tennessee Valley Authority’s Paradise Substation in Kentucky, which is farther south than most other Sunburst sites. Its GIC measurements have been among the highest recorded since a Sunburst node was installed there less than a year ago. EPRI is investigating the Paradise phenomenon—line impedance, length, orientation and soil resistivity—and will report any new developments. The data emerging from Paradise highlights the value and need of a wide-area network capable of collecting GIC measurement and magnetometer data.

An interesting feature in Figure 2 is the apparent transient nature of the maximum recorded GIC value. This initial spike typically occurs when the coronal mass ejection (CME) collides with Earth’s magnetic field. Figure 3 compares the Paradise site with another TVA location.

The resolution of the data shown in Figure 3 is 5 seconds; thus, the peak GIC value was reached within a span of 5 seconds. This trend is shown in both sets of measurement data.

Assessing Vulnerability: System-Planning Studies

System-planning studies can be used to determine the impact of an extreme geomagnetic disturbance (GMD) on the grid. The studies can use a probabilistic approach based on the possible severity of a solar storm or an arbitrary severity can be assumed that has a very low probability of occurrence. For instance, some suggest evaluating the system against a 100-year storm. Figure 4 provides an approach for performing such studies on the transmission network.

GICs are quasi-dc currents created by induced voltages in the transmission lines. Because GICs are quasi-dc, they can be determined using a dc model of the network. The resulting GIC flows are used as inputs to time-domain transformer models, which estimate the resulting VAR demand and harmonic current injection of the transformers. The VAR demand and harmonic current injection are then used as inputs to other system-planning studies including: ac load flow, transient stability, power quality and system protection.

Thermal models of the transformers are used to determine if individual transformers will exceed their thermal limits during a GMD. If the thermal limits of individual transformers are exceeded, they are considered vulnerable and are removed from service for planning-study purposes. Transformer and system vulnerability assessments typically are performed in parallel because the results of the two studies are codependent.

EPRI Research

EPRI is working with the North American Electric Reliability Corp. (NERC) and the utility industry to develop, among other things, the capability for utilities to assess the impact of an extreme GMD event on the grid. A few highlights of this research regarding system planning include:

An open-source software program is being developed that can be used to determine GIC flows in the grid.
Electric field values corresponding to a 100-year storm are being developed for numerous geographic locations in North America. In addition, research is being performed to determine the maximum electric field values that are physically realizable.
Time-domain transformer models are being developed in EMTP-RV to estimate VAR demand and harmonic current injection of transformers subjected to the flow of GIC.
Guidelines for performing system-planning studies to determine the impacts of a GMD are being developed.
EPRI is working with transformer manufacturers to develop criteria to assess the vulnerability of transformers subjected to GIC.
Model validation (and improvement) using data from the EPRI Sunburst network will be performed.

EPRI also is pursuing research in the following areas to assess and reduce the risk of geomagnetic disturbances:

Improved storm warning to increase forecasting accuracy and lead times. This effort involves collaboration among experts, with EPRI Sunburst data providing key inputs into improved forecasting models. EPRI also is working with NERC on a project to develop a continental model that will help clarify likely impacts on the grid.

Increased real-time system awareness to support informed utility operations during storm conditions. EPRI is exploring three research areas to increase such awareness. The first is research assessing the use of existing microprocessor-based relays to estimate GIC and transformer response by directly measuring harmonics and voltage in real time. The second is research to explore the use of EPRI’s existing network of power quality monitors to examine harmonic generation in transformers during solar storms. The third is research on meaningful signal analysis of these data streams to allow an accurate assessment of the risk to a specific transformer and the risk to the grid as a whole. In addition, the data will serve as valuable input into future storm forecasting and assist with forensics of failed equipment.

Increased utility collaboration. EPRI has established an interest group to shape the research portfolio, to better understand geomagnetic disturbances and other high-impact low-frequency events and to share and document current industry best practices.

EYE ON EUROPE

ENTSO-E Releases Paper on Electricity Highways

The European Network of Transmission System Operators for Electricity’s (ENTSO-E’s) paper “Framework regarding Electricity Highways” identifies the main tools enabling transmission system operators to keep up with the European Commission (EC) objective to accelerate designing, planning and building electricity highway system. The framework’s time horizon covers the period after the Ten Year Network Development Plan (TYNDP) after 2020. The tool advocated by ENTSO-E`s TSOs will assess how a pan-European electricity highway system will be built over a time horizon to 2050; this study road map is titled “Modular Development Plan on a pan-European Electricity Highways System 2050.” Based on this study, the plan will be developed by a consortium consisting of 26 European members which includes ENTSO-E and its member TSOs, relevant associations, institutes and universities within the “e-Highway2050” project.

More information at https://entsoe.eu.

ITC Holdings Leads on Planned North American Electric Transmission Investments

ITC Holdings Inc. tops the list of new projects by transmission owners through 2020 while American Electric Power leads all utilities for new substation projects. Texas continues to dominate new transmission growth among all states.

Going into 2012, ITC Holdings plans more than $24.1 billion in transmission investments, including more than 8,686 miles of new and upgraded lines, according to analytics by The C Three Group LLC and the North American Electric Transmission Project Database. Xcel Energy, Clean Line Energy Partners, American Electric Power and Western Area Power Administration round out the top-five companies with a combined total of more than $31.9 billion of planned transmission investments through 2020.

Other highlights of The C Three North American Electric Transmission Project Database show that Texas still comfortably leads all states with more than 9,175 miles of new lines planned through 2020. The C Three Group also found that the U.S. and Canada has nearly 4,000 substation projects planned over the next eight years with American Electric Power topping all utilities with 268 new projects.

C Three also noted North American electric transmission investments could top $160 billion between 2012 and 2020.

The C Three Group LLC provides strategic planning, merger and acquisition, and market development support to the energy utility industry. The North American Electric Transmission Project Database contains more than 12,000 transmission line and substation projects tracked from early development through completion.

More information is available at https://cthree.net.

More information on building transmission lines can be found in the feature on Page 26 of this issue.

More Power Engineering Issue Articles
Power Engineerng Issue Archives
View Power Generation Articles on PennEnergy.com

10 Ways to Prepare Your Grid for Solar Interconnection