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At POWER Engineers we thrive on having many irons in the fire. With strategic thinking and perseverance, Ross Pritchard and the POWER Engineers team will guide your program from conception to completion窶馬o matter the size, no matter the scope.


Ross Pritchard Director, Program Management POWER Engineers, Power Delivery

To download our brochure, scan code or visit WWW.POWERENG.COM/PM14




48 22

Features 14 Electric Energy Industry Leadership Panel Article

22 History of the United States’ Electric Utility Industry Jeff T. Hein, P.E., Sr. RTO Policy Manager,

Xcel Energy

39 A Future Vision for the Electric Grid By Ucilia Wang, Freelance Writer

44 Why Planning Studies Matter to Utilities By James D. Whitaker, PE, TRC Companies, Inc.

48 Safety vs Compliance By Ronald J. Schenk, CUSP, Director, T&D PowerSkills, LLC



Departments 06  President’s Message 08  Board of Directors and Foundation Board of Directors 10  2014 Spring Management, Engineering and Operations Conference 52  RMEL Membership Listings 56  2014 Calendar of Events 58 Index to Advertisers

Power Generation Oil & Gas



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President’s Message Dear RMEL Members and Participants; I hope 2014 has started well for all of you. At RMEL, we are particularly excited about 2014 since we are seeing an increase in utility participation at our events this year. It’s clear that our member’s education budgets are building as they understand the benefits of more professional development and networking. It’s great to see this increase in utility representation because now is an extremely important time to collaborate on ways to solve the most challenging issues facing the electric energy industry. Some of the most crucial challenges were brought to light at RMEL’s Vital Issues Forum at last year’s Fall Convention in Arizona. RMEL hosted an additional Vital Issues Forum near Austin last August that focused on Texas’s issues in preparation for the 2014 Spring and Fall Conventions taking place in Austin and San Antonio. All of this year’s RMEL programs have been designed around helping utilities tackle the issues discussed at both vital issues forums. The Spring Management, Engineering and Operations Conference has a diverse lineup of 30 presentations, including a COO Panel that features panelists from Kansas City Power & Light, Austin Energy, Nebraska Public Power District, Duke and SRP. Many topics at this conference have particularly strong implications in Texas. The conference will feature a panel on fracking, the petrochemical boom and the resulting economic impact on the utility infrastructure. In addition, ERCOT will participate in a panel discussing various approaches to regional transmission. Other topics include a presentation by Omaha Public Power District (OPPD) of their OPPD Listens campaign that facilitates engagement of stakeholders and customers in OPPD’s decision making process, and a presentation from Xcel Energy describing their experience with Boulder, Colorado’s municipalization of the electric utility. I look forward to seeing you all at the conference in Austin, May 18-20, 2014. The Fall Executive Leadership and Management Convention is set for September 14-16 in San Antonio, Texas. This program tackles industry vital issues from an executive viewpoint. If you’re concerned about grid security, fighting the industry PR battle, the lack of a U.S. energy policy, global electric energy trends, and the future of electric utilities then I strongly encourage you to attend this convention. Texas utility attendees will also benefit from a presentation on the Texas market. You’ll also enjoy premiere networking opportunities and the chance to build your contact list as you prepare to face all the industry challenges ahead. I hope you enjoy this issue of Electric Energy Magazine, and I sincerely thank you for your RMEL participation. This is going to be a fantastic year! Sincerely, Published Spring 2014 PUBLISHED FOR: RMEL 6855 S. Havana St, Ste 430, Centennial, CO 80112 T: (303) 865-5544 F: (303) 865-5548

Kathryn Hail EDITOR (303) 865-5544 Electric Energy is the official magazine of RMEL. Published three times a year, the publication discusses critical issues in the electric energy industry. Subscribe to Electric Energy by contacting RMEL. Editorial content and feedback can also be directed to RMEL. Advertising in the magazine supports RMEL education programs and activities. For advertising opportunities, please contact Deborah Juris from HungryEye Media, LLC at (303) 883-4159. P U B L I S H E D B Y: 800.852.0857 Brendan Harrington PRESIDENT Deborah Juris PUBLISHER (303) 883-4159 Lindsay Burke CREATIVE DIRECTOR / AD PRODUCTION

Alithea Doyle DESIGNER Susan Humphrey PROJECT MANAGER Dave Baker COPY EDITOR

Register for the Spring Management, Engineering and Operations Conference MAY 18-20, 2014

Dan Schmidt 2013-2014 RMEL President Sr. VP, Power Generation Services Black & Veatch Corp.




Leaders in Engineering Energy Solutions

2014 RMEL

Engineering, Surveying, and Consulting Services

Platinum Champion

Utilities need to deliver power they generate quickly and reliably. Ulteig delivers the expertise and knowledge to help make that possible. With Ulteig’s wide array of services and extensive experience, we provide solutions to help manage and upgrade existing infrastructure while building a foundation for future growth. Our in-depth knowledge of engineering services, techniques and project management provides a consistent and quality approach to your projects from start to finish.

Ulteig is proud to support future generations of engineers pursuing careers in the electric industry by providing scholarships through the RMEL Foundation. In this way, we demonstrate our enthusiasm for and commitment to the future of our industry, and the engineering professionals of the future.

Learn more about what Ulteig offers you in developing your next step in power generation and delivery systems. Visit our website at • 877-858-3449


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RMEL Board of Directors

Foundation Board of Directors



PRESIDENT Dan Schmidt Black & Veatch Corp. Sr. VP, Power Generation Services PRESIDENT ELECT Stuart Wevik Black Hills Corporation VP, Utility Operations PAST PRESIDENT Andy Ramirez El Paso Electric Company VP, Power Generation VICE PRESIDENT, MEMBERSHIP Scott Fry Mycoff, Fry & Prouse LLC Managing Director

VICE PRESIDENT, EDUCATION Tony Montoya Western Area Power Administration, COO

PRESIDENT Steve Bridges Zachry Holdings, Inc. VP & Power Executive,

CHAIR, FUNDRAISING James Helvig AMEC Director, Power Delivery

VICE PRESIDENT, FINANCE Tom Kent Nebraska Public Power District VP & COO

VICE PRESIDENT, FINANCE Rebecca Shiflea Leidos Senior Project Manager

VICE PRESIDENT, VITAL ISSUES Richard Peña CPS Energy Sr. VP, Energy Supply & Market Operations

VICE PRESIDENT Walter D. Jones Intermountain Rural Electric Assn. Assistant General Manager, Operations & Engineering


VICE PRESIDENT, MEMBER SERVICES Mike McInnes Tri-State Generation and Transmission Assn. Interim Executive Vice President & General Manager

Directors Doug Bennion PacifiCorp VP, Engineering Services & Asset Management Tim Brossart Xcel Energy VP, Construction Operations & Maintenance Jon Hansen Omaha Public Power District VP, Energy Production & Marketing Kelly Harrison Westar Energy VP, Transmission Mike Hummel SRP Associate General Manager Tom McKenna UNS Energy Corporation VP, Energy Delivery


Board of Directors H. Kent Cheese TestAmerica Laboratories, Inc. VP Sales

Tammy McLeod Arizona Public Service VP, Resource Management

Paul Compton Kiewit Sr. VP, Business Development

Cheryl Mele Austin Energy COO

Dennis Finn Wärtsilä North America, Inc. General Sales Manager, Mtn Region

Mike Morris Zachry Holdings, Inc. VP, Business Development, Engineering

Mike McInnes Tri-State Generation and Transmission Assn. Interim Executive Vice President & General Manager STAFF LIAISON Natalie Andersen RMEL Manager, Member Services & Retention Rick Putnicki RMEL Executive Director

Jackie Sargent Platte River Power Authority General Manager Neal Walker Texas New Mexico Power President Secretary Rick Putnicki RMEL Executive Director


Electric Energy available in digital format - email, share, link. ACCESS FROM THE RMEL.ORG HOME PAGE

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Attend RMEL’s Spring Management, Engineering and Operations Conference in Austin, Texas Join 300 members of RMEL’s trusted community to learn, network and discover solutions at RMEL’s Spring Management, Engineering and Operations Conference, May 18-20, 2014 in Austin, TX. IF YOU ARE MANAGING people or projects, engineering, planning or operating systems in the electric utility industry, this conference is for you. The Spring Management, Engineering and Operations Conference has been a tradition since RMEL’s early beginnings. Known for providing outstanding continuing education and networking opportunities, this conference is a must attend event for engineering, operations and management personnel in the electric energy industry. With 30 presentations, this conference covers issues in generation, transmission, distribution, safety, customer service, human resources and other management topics. The timely topics and breakout structure of the conference allows attendees to customize their education experience to focus on presentations and resources that address their needs. Ample time is also provided to network with industry peers and visit with exhibitors. The event will feature keynote presentations from Brian Lloyd, Executive Director, Public Utility Commission of Texas, Gurcan Gülen, Ph.D, Senior Energy Economist, Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin and an Executive Leadership Panel including Scott Heidtbrink, COO, Kansas City Power & Light; Cheryl Mele, COO, Austin Energy; Tom



Kent, VP & COO, Nebraska Public Power District; Phillip Grigsby, VP, Commercial Transmission, Duke American Transmission Company; and Mike Hummel, Associate General Manager, SRP. Educational breakout sessions will take place in three tracks: generation; transmission and distribution; and management. The slate of generation track presentations will guide attendees through topics like co-generation vs. selfgeneration, multi-pollutant control, energy efficiency in

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plants, challenges and potential solutions of wind power, sodium bicarbonate dry sorbent injection at Kincaid generating station, pending regulations and carbon capture technology and NERC reliability. In the T&D Track, look forward to details on approaches to regional transmission planning, energy storage, data collection for asset management, information and operation technology considerations for volt VAR optimization, route selection, protecting assets, renewable impacts on transmission and distribution and causes of underground cable failure. The third track of presentations, focused on management, covers transitioning the workforce, workforce issues, economic impact of fracking and petrochemical boom on the utility infrastructure, reaching the public with an accurate electric utility message, NERC, competition, successful project management panel and geographic data. This event offers something for every person in the utility industry, whether you need to make the right contacts or find the right answers. Utilities of all types of ownership participate including IOU, G&T, municipal, cooperative and others. Vendors of all types are valued participants in the conference and community dialogue to improve operations and enhance customer service.

NETWORKING GOLF OUTING Enjoy a golf outing at Wolfdancer Golf Club on May 18th. The format will be a four-person scramble and proceeds will benefit the RMEL Foundation scholarship program. Call RMEL at (303) 865-5544 to register.

GUESTS AND SPOUSES ARE WELCOME Bring your guest to the 2014 Spring Management, Engineering and Operations Conference. If your guest registers for the full conference, they are registered for all meals and the Champions Receptions on Sunday and Monday. If they register for an individual day, they will be registered for meals and the Champions Reception for that day only. Guest registration prices simply cover the cost of meals. Guests can also register for the Guest Activity, which includes a tour of the Lady Bird Johnson Wildflower Center, lunch at Z Tejas on Austin’s historic 6th Street, SoCo shops and attractions and (time permitting) a visit to Mount Bonnell, which is a prominent point alongside Lake Austin portion of the Colorado River. All attendees will receive a continuing education certificate. The certificate provides professional development hours based on participation. For more information and to register for the Spring Management, Engineering and Operations Conference, go to or call (303) 865-5544.

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he barrage of pending regulations, economic uncertainty and ever-increasing speed of communication are pushing electric utilities to act faster than ever before. In this panelstyle article, CEOs from three utilities share their strategies for moving forward with today’s biggest industry challenges.

Mark A. Gabriel is

David Emery is Chairman, President and CEO, Black Hills Corporation. He has 24 years of experience with Black Hills. Black Hills Corp. is a diversified energy company with a tradition of exemplary service and a vision to be the energy partner of choice. The company is based in Rapid City, S.D., and has corporate offices in Denver and Papillion, Neb. Black Hills serves 765,000 natural gas and electric utility customers in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company also has a business segment called non-regulated that generates wholesale electricity, produces natural gas and crude oil, and mines coal. The more-than 2,000 employees partner to produce results that improve life with energy.

Administrator, Western Area Power Administration. He has more than two decades of leadership experience in the electric sector and was most recently the Chief Executive Officer and President of Power Pundits LLC. Previously, he was the Senior Vice President for Black and Veatch management consulting, developing industry solutions in the areas of electricity, water, oil and gas and cyber security. Western Area Power Administration is one of four power marketing administrations within the U.S. Department of Energy whose role is to market and transmit electricity from multi-use water projects. Its service area encompasses a 15-state region of the central and western U.S. in which its transmission system carries electricity from 56 power plants operated by the Bureau of Reclamation, U.S. Army Corps of Engineers and the International Boundary and Water Commission, and one coal-fired plant. Together, these plants have an installed capacity of 10,505 megawatts.

Jackie Sargent is General Manager, Platte River Power Authority. She brings over 25 years of experience in the energy industry, including electric and gas utility operations, power generation, energy marketing, rates and regulatory affairs, strategic planning, acquisitions and mergers, and project development. Jackie is also a member of RMEL’s Board of Directors. Platte River Power Authority is a not-for-profit wholesale electricity generation and transmission provider that delivers safe, reliable, environmentally responsible and competitively priced energy and services to its owner communities of Estes Park, Fort Collins, Longmont and Loveland, Colorado for delivery to their utility customers. Platte River’s Headquarters is located in Fort Collins and its generation and transmission facilities are located along Colorado’s Front Range and in northwestern Colorado. »



What is your biggest area of focus? Describe your current initiatives in that area. DAVID EMERY: At Black Hills Corporation our focus is on profitably growing earnings at a rate significantly higher than most of our utility peers. During the next three years, we plan to invest $1.2 billion on capital projects to grow our business. We’ll invest more than half of that in our regulated utility business alone. Last year, we began construction on our next major project that will drive future earnings growth. The Cheyenne Prairie Generating Station is a $222 million, 132 megawatt, natural-gasfired power plant being constructed in Cheyenne, Wyo. It will serve growing electricity demand in Cheyenne and replace older, coal-fired power plants that have been retired in Wyoming and South Dakota to comply with new Environmental Protection Agency emissions regulations. The project is on schedule and on budget, and we expect that it will begin serving our Black Hills Power and Cheyenne Light, Fuel & Power customers in October 2014. In Colorado, the Public Utilities Commission granted our Black Hills Energy electric utility subsidiary approval to build a 40 megawatt, natural gas-fired turbine to replace the capacity deficit lost from the coal-fired W.N. Clark plant that we retired to meet ever increasing EPA regulations. Throughout our utility service territories, we grew our customer base and revenue through small municipal gas system acquisitions — adding 900 customers and $6 million in rate base during the past year. We announced another small acquisition in January 2014, which will add another 400 customers in Wyoming when the transaction closes later this year. We continue to evaluate other, similar opportunities and plan to make similar acquisitions when they make business sense.



JACKIE SARGENT: The possibility of disruptive technology is greater now for our industry than at any time since the invention of the electric meter. That’s why my focus is on developing adaptive strategies to help our organization be better prepared for a future with many unknowns. Adaptive strategies such as generation portfolio diversification, increased utilization of energy efficiency, and reliable demand response may not fully prepare us for the disruptive technology that we do not currently foresee, but creating an environment that accepts and embraces the inevitability of transformational change will best position Platte River Power Authority to meet the challenges of the future. This sort of cultural shift involves buy-in throughout the organization. With this end in mind, the most immediate initiative that I began

shortly after coming to Platte River in 2012 was strategic planning with our board and senior management team. We have been through an extensive planning process with our four owner municipalities—Estes Park, Fort Collins, Longmont and Loveland, Colorado—and now we’re working on a new integrated resource plan that will help us look at further diversifying our generation portfolio. At the same time, we’re offering more services to the city utilities, and we’re collaborating on programs such as energy efficiency and demand response. It’s an exciting time for Platte River. MARK GABRIEL: Western is working together with our customers and stakeholders to support a new energy frontier. In order to fulfill our mission of marketing and delivering clean, renewable, reliable, cost-based


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federal hydroelectric power and maintain and protect the national electric grid, Western is currently focusing on key initiatives including: • Strategic Planning • Asset Management • Sustainable Funding • Human Capital Management Our greatest responsibility is to manage the assets, some $4 billion strong that are entrusted to us and ensure they are deployed wisely for our nation and our customers to keep the power flowing safely and reliably, to more than 40 million Americans. How we manage those assets is central to Western’s success. Our challenge is to balance the need for investment and the needs of our customers against our available capital in a systematic, sensible and cost-effective way. Western customers benefit with reasonable rates today from investments made yesterday. They will benefit from reasonable rates tomorrow due to investments we are making today. Through it all, our focus remains on the safety and security of our employees, the public and our system.

How you deal with external drivers, including the regulatory environment and workforce issues? GABRIEL: Our strategic planning effort, Roadmap 2024, has been a collaborative effort with our customers, stakeholders and employees to jointly envision the future of our industry 10 years from now, how we implement our mission in that future and the pathways we must take to get there. These pathways, and the targets derived from them, link every employee and every activity to our mission. They are the foundation by which we evaluate external drivers. Through this process, we have tried to envision those drivers that will change



our industry in the next 10 years. However, we recognize that we are not able to anticipate everything, so we intend to re-examine our pathways every two years to chart our progress and evaluate changed conditions. Specifically, one important trend is an aging workforce and the growing percentage of employees eligible for retirement, particularly in the mission-critical craft fields. By using effective workforce planning and succession planning at every level of the organization, Western will ensure it has the right people in the right places across the agency. Western is looking for ways to retain the knowledge of those expected to retire by offering mentoring and rotational programs. In addition, Western continues to invest in

its employees by offering training programs at all levels. We are also working to develop apprenticeship and new student programs to help create a pool of interested people and a way to bring them on board to fill critical positions. SARGENT: Coupling the changing regulatory environment with workforce issues really tees up two issues that need management attention: the industry is facing an accelerating regulatory agenda on multiple fronts at just the time that we are losing much of our seasoned work force to retirement. The upside is that our industry is presented with an opportunity to retool for a changing world. To do so effectively, we must make our industry attractive to the next generation of

EMERY: Our employees are the key ingredient in our approach. When our employees are aligned with our strategy and we have a great workplace where they can excel, we can confidently manage through external drivers. A good portion of our success is due to our employees’ focus on getting better every day. We want to lead the industry in everything we do. Leading the industry means we’re earning solid returns and managing expenses and improving service for our customers, even as the external drivers continue to change. By providing the best service and a great workplace, we hope our customers and employees will choose Black Hills. Additionally, we pride ourselves on building and enriching our external relationships to enhance our brand value in the communities we serve, including ongoing community engagement and regulatory interactions.

engineers and technicians, and RMEL has a big role to play in this effort. There is uncertainty around pending Environmental Protection Agency regulations for new and existing coalfired power plants, coal ash, and cyber and physical security of our electric infrastructure. But at the same time, there are so many opportunities. Renewable energy resources are becoming more affordable, and customers are increasingly savvy about managing their energy use. Our region of Northern Colorado is seen by some as a laboratory for energy innovation with programs such as Drive Electric Northern Colorado and EfficiencyWorks. We’re working with our cities in their utilization of federal and state programs that will help support our region’s energy future.

When you look toward the future of your utility and the industry, how has planning changed? What do you think the industry will look like in 20 years? SARGENT: When I started my career as an electrical engineer in western South Dakota – not that long ago I might add – planning was much less dynamic. At that time the industry was focused on least cost planning. We evaluated the rate of growth in our service area, projected a commensurate growth in electricity use, and looked at our options based primarily on cost as well as fuel and transmission availability. Now planning is much more complex. Affordability is still important, but affordability is only one value in an equation that includes regulatory mandates, reliability and

security concerns, increased regional coordination, the integration of variable energy resources, and the need to accommodate innovation both on the part of the industry and our customers. Proactively integrating these new and dynamic inputs within the planning process is key to effectively using planning as a tool to prepare for the industry of the future, and will be one of the most interesting responsibilities I face as a CEO. The utility of the future will likely incorporate more distributed generation resources and demandside management programs. Fuel availability and price will be factors, as well as emerging technologies. This spring we’re reaching out to stakeholders in our communities regarding their preferences for future electricity resources. We’ve added customer service and planning staff, and we’ll be conducting modeling and analysis for various diversified energy supply scenarios. By the end of 2014, we anticipate seeking board approval of a new Integrated Resource Plan. Our owner communities are actively engaged in the planning process for the next 20 years and beyond. EMERY: The pace of change is continuously accelerating but we remain focused on the fact that providing a valued service to our customers will not change in 20 years. The challenge is to understand what will change how our customers value our service and evolve our strategy to meet their needs. GABRIEL: The days are long since gone when a utility could plan for its own project needs in isolation. As the grid has evolved in ways for which it was not constructed or designed, project planning has also evolved. Today, planning is far more collaborative, both with neighboring utilities and regionally. For Western, much of this planning requires a regional focus as we serve 15 W W W. R MEL .O RG


states. Each of our regions operates projects with different projectspecific statutory authorities, different customer bases and varying needs. Our industry looks much different today than it did 20 years ago and will no doubt look significantly different in 20 more years. The entire industry is facing several trends that will affect all of us. Our aging workforce is creating particular pressure to plan for succession in the critical-skill positions in our organizations. We face a future of more intermittent generation and behind-the-meter generation for which the existing transmission system was not designed. The emphasis on high-quality data and information will only continue to grow as will the need for integrated systems to share and communicate that information. Existing utility business models are under pressure, and new market structures are developing in the West; both factors will lead to new models for doing business. Customer engagement will remain essential as customers demand more choice and control. Finally, society as a whole will focus on the water-energy nexus and the increasing challenge of balancing water and energy.

Communication, regulations and technology are moving fast. How do you keep up with everything? EMERY: Focus is crucial to successfully leading through the changes that are impacting our industry. In 2013, we structured our strategy into four main objectives: profitable growth, valued service, better every day and great workplace. Our strategic objectives provide a lens through which we continuously evaluate and balance rapidly changing industry dynamics. GABRIEL: Western is focused on advancing its core mission in service



to our customers and the nation. Our long-range strategic framework, provides the umbrella under which we prioritize our responses to the daily demands and changes that bombard us all. We have developed a Tactical Action Plan that will help keep us focused on our priorities and delivers on our mission. As the speed of change increases, the need to collaborate and share information, both internally and externally, is heightened. The better we can share information, the better we will be able to respond to rapidly changing demands. SARGENT: Platte River is a relatively small wholesale power provider, with about 230 employees keeping the power flowing to our four owner municipalities. Our people are welltrained and committed, and we work together to keep each other informed. Investing in and maintaining our generating units and transmission infrastructure has paid dividends with excellent reliability and a solid high performance generating record. With that foundation, our team leaders are actively engaged in national, state, and local discussions on issues important to Platte River and our customers. For example, being actively involved in RMEL helps us stay abreast of the pending and evolving issues that will impact our operations and long-term business model.

How have customer expectations changed with all the new information technologies available? How does your utility deal with that? SARGENT: Customers are expecting more from their utility service providers, and as the wholesale electricity supplier to four cities, we are ready to work with the cities

on multiple fronts. Historically bill inserts, radio, local TV and the daily newspaper were how utilities communicated with customers. While there are still some opportunities where these options help support getting information to customers, they are losing market share. We’re now reaching out to our customers through other available information channels, from our website and Facebook page to interactive documents and webinars. In this, the digital age, we must be accessible to customers on the go using mobile technologies, so having information available that is easily searchable on smart phones and iPads is important. Combining in-person interactions with technological interactions is a useful way to connect with a broader audience. Maintaining an awareness of evolving trends and innovation in communication is critical to meeting the increasing challenges and rising expectations of electric utility customers now and into the future. GABRIEL: While Western does not directly serve end-use customers, the expectations of those customers are driving change throughout our industry. Customers today have unprecedented access to information and desire to have more control over their options and destiny. Addressing those needs will require investment from all of us in the industry. Western customers experience the benefit of reasonable rates today based upon strategic investments made yesterday. And, they will continue to benefit from reasonable rates tomorrow due to investments we are making with them today. EMERY: We have several ongoing projects that will improve our customers’ experiences and continue to provide valued service. Our customers expect a high level of service at a good value. They are also more connected and expect more

real-time access and information than ever before. To continue to meet their needs, we launched new, mobile-friendly websites for our seven utilities as well as for the corporation. We also unveiled our new Electric Reliability Center, which allows us to safely and reliably keep the power on for our 200,000 electric customers. Our Electric Reliability Center proved invaluable in October 2013, when the Black Hills of South Dakota endured the second-worst blizzard in the region’s history. Consequently, Black Hills Power suffered its worst outage in our 130-year history, with more than half of our Black Hills Power customers left without power. Thanks to the center, our hundreds of employees, and the help of our sister and peer utilities,

were able to restore most customers’ service within one week’s time. We will file a request with the South Dakota Public Utilities Commission to gradually recover the stormrelated costs from our customers. We've also begun using social media as a channel to broadcast information more quickly to our customers. Social media has given our customers a new channel to deliver feedback and ask questions. A step further, we host live Facebook events where our customers can ask questions in real-time to subject matter experts in our company. Additionally, we have conducted surveys and customer interviews to get a better understanding of their preferences. This has driven the development of new products and services.  We've looked at old processes and

have developed ways to make them simpler. When a customer calls, instead of listening to a series of push button options, we launched a smartphone app that allows customers to visually navigate our phone menu. We've also added new online bill payment options like a QR code at the top of our utility bill and a free bank transfer option. Additionally, we also added an energy usage graph that allows our customers to take advantage of their Advanced Metering Infrastructure meters and view their energy usage down to 15 minute intervals. Onehundred percent of our electric utility customers are utilizing AMI meters, while nearly 90 percent of our gas utility customers are utilizing AMI or Advanced Meter Reading meters. We're also working on a field service optimization project. The heart of this project will give us an automated scheduling engine which will schedule our field technicians more efficiently. This will help reduce travel time between appointments allowing us to better meet our service level agreements. This project will also give our customer service specialists more real-time information about our field technician's location and status so we can answer customer questions as they come in. Finally, this project will put mobile devices in the hands of our field technicians so they have access to more data to help answer customer questions.  Our J.D. Power and Associates customer service scores show that our efforts are working. In 2013, our natural gas customer score was 643 — an improvement of 13 points over 2012 — and beat the Midwest and industry averages. Our electric customer score was 628 — an improvement of 34 points over 2012. David Emery can be reached at david.; Jackie Sargent can be reached at sargentj@; and Mark A. Gabriel can be reached at W W W. R MEL .O RG






Three 5000 HP Westinghouse two-phase generators harness the energy of Niagara Falls, the first large-scale generating facility in the world.

the United States’ electric utility industry operated in a competitive, market-based environment. Because low voltage restricted distribution to about one mile from the generating station, many generating stations and distribution systems were built. In Chicago alone 45 electric utilities competed for customers. This industry design was repeated again and again within cities throughout the United States. COMPETING TECHNOLOGIES

1879-1895 Origins and Early Developments

Let There Be Light (at Night)… The roots of the modern day electric utility industry can be traced back to two events that occurred in the year 1879. The first occurred when Charles Brush invented a dynamo and arc lamp lighting system for street lighting, which he put to use in Cleveland, Ohio. That same year Thomas Alva Edison and his team of researchers invented the incandescent light bulb for home lighting, the predecessor of the light bulb in use today. In New York City in 1882, Pearl Street Station was the first central electricity-generating station constructed to support the light bulb invention. Using a DC, +/- 100-volt generation and distribution system (with neutral), Pearl Street Station used reciprocating steam engines to provide the mechanical energy required

to create electricity. Lighting was the first application for electricity. Edison created the Edison General Electric Company, which later merged with another company to become General Electric Co. Edison was a major stockholder. The need for electricity would grow as appliances, such as irons and even electric street cars were introduced. While their predecessors used wood or coal. Edison and others were developing a market for electricity. DEVELOPMENT & COMPETITION

Soon electricity was being hailed as a modern marvel that would revolutionize households and industry nationwide. Optimists envisioned increased demand for electricity and others sought entry into this growing market. Central generating stations and distribution systems (wires and poles) began sprouting up in many cities, after receiving approval from municipal governments. Competition between providers was commonplace. Initially,

During this same time period, another form of electricity - “alternating current (AC)” - was being developed. The primary developers were Nikola Tesla, William Stanley, Jr. and George Westinghouse. In 1883, Stanley invented the first modern-day transformer used in AC electrical. Tesla invented the AC polyphase motor in 1885. He then married the polyphase motor with the transformer. Finally George Westinghouse had the finances to promote the superiority of the AC electricity system using low-voltage generation to high-voltage transmission to low-voltage distribution. While DC power systems had a head start and were more widely used than AC systems, AC power systems were still being developed and installed. The first AC system, upon which today’s is based, was built in 1891, to provide power from the Ames hydro-power station to the Gold King Mine near Telluride, CO. These two technologies would eventually compete for control of the United States’ electricity market. This headto-head competition occurred during the development of the Niagara Falls’ Edward Dean Adams power station. The Niagara Power Commission, wishing to deliver power to Buffalo nearly 23 miles away, awarded this contract to the Tesla/Westinghouse AC generators based on their Chicago World’s Fair exhibit. This was a major defeat for Edison and the DC power systems he envisioned. W W W. R MEL .O RG


1896-1928 The Electric Industry

Evolves - Continued Competition, Consolidation, State Regulation and Tremendous Growth The next major development in the electric utility industry occurred in 1903. Chicago Edison, under the guidance of president Samuell Insull, installed a turbine-generator set that produced 5 MW of AC power at Fisk Street Station in Chicago. A turbine-generator set was revolutionary because it used a new technology known as a steam turbine as the generator’s prime mover. The steam turbine, developed in England in 1884, by Charles Parsons was far superior to its predecessor, the reciprocating steam engine. The new steam turbine was much smaller in size, produced equal amounts of energy, and could be scaled up to produce more power for little additional capital cost providing economies of scale. These new machines could now produce more electricity at a cheaper cost. By 1912 the cost to produce electricity and the resulting cost to the customer dropped substantially. With turbine-generator sets producing low-cost AC electricity, transformer technology allowing voltage control (high-voltage for long-distance transmission and lowvoltage for end-use), and the ability of AC power to perform the tasks that DC power could, the downfall of the widespread DC electricity system Edison envisioned was imminent. CONSOLIDATION, REGULATION AND EARLY GROWTH CONSOLIDATION

Insull realized that competition would not allow the profit margins required to pay back infrastructure costs. So he began acquiring other utilities. This began consolidation, and by 1907, Chicago Edison, led by



La Plata Electric team raises a distribution pole with horses.

Samuel Insull, had acquired 20 other utility companies and changed its name to Commonwealth Edison. Consolidation occurred in many other cities with the local electric utility controlling the market. This natural monopoly had to be regulated. Using the railroads as precedence, state legislatures and city municipalities created independent regulatory commissions to oversee electric companies to protect consumers. In exchange for this regulatory protection from outside competition, electric utilities were obligated to serve all customers without discrimination. During the 1910s and 1920s, utilities saw tremendous growth and were able to charge their expanding customer base for all services they provided. Utility generation and transmission expanded dramatically

from 5.9 million kWh in 1907 to 75.4 million kWh in 1927 while per unit costs of electricity declined 55 percent.

1929-1936 Holding Companies:

Benefits and Abuses, and Federal Intervention HOLDING COMPANIES: BENEFITS AND ABUSES

Commonwealth Edison and other utilities soon began to form an operational structure known as a holding company. Holding companies acquired various utilities (electric and railway), known as operating companies. Organized into a pyramid scheme, sometimes up to 10 layers deep, holding companies acquired sub-holding companies and the corresponding operating companies

Many investors lost their investments in holding companies due to the weak house of cards organizational architecture susceptible to complete collapse. Franklin Roosevelt, campaigning for the presidency in 1932, promised to: Reform the corrupt electric utility industry, which was controlled by too few against the good of the common citizen and; create government agencies to provide electricity to rural areas to improve their standard of living of many Americans, long ignored by the electric utilities because it was not cost-effective. FEDERAL INTERVENTION

with a minimum of capital investment. Holding companies owned and controlled operating companies and their assets over many geographic regions. During this time, three holding companies controlled 45 percent of the entire U.S. electric utility industry. The holding company structure offered many benefits. Operating companies used the holding company’s centralized engineering, management and purchasing services. This was cheaper than each OC providing these functions on its own. Additional benefits occurred when holding companies interconnected their smaller operating companies, to create a more reliable system for their customers. As a result, the electricity system grew rapidly. This most likely would not have happened if not for the holding companies. Holding companies however,

lost sight of these benefits and began abusing the holding company structure in the mid-to-late 1920s to maximize profits. The holding company controlled many different operating companies, which relied upon electricity like city streetcars. The holding companies were essentially monopolies and abused the system by charging exorbitant service fees and over valuing purchases, which were then added to the service rate. This wide geographic, interstate operating structure allowed holding companies to evade state-based regulatory commissions because these issues were under the jurisdiction of the federal government and Federal authorities provided no industry oversight. Public hatred and distrust of these holding companies was further fueled by the stock market crash of 1929.

Roosevelt was true to his campaign promises. With Congressional approval, he created government agencies that generated and delivered electricity to rural areas long ignored by the holding companies (because it was thought that the return on investment would be inadequate from these sparsely populated areas). Roosevelt and Congress created the Tennessee Valley Authority in 1933 and the Rural Electrification Administration and the Bonneville Power Administration in 1935. These government agencies proved that electricity could be generated and delivered cost effectively to remote, rural areas. As a result of these actions, the standard of living in these remote areas rose tremendously. These rural loads proved to be the largest customer base in the country at the time and continue to be today. In addition, and to prevent future similar abuses, Congress passed the Public Utility Holding Company Act of 1935 (PUHCA). PUHCA created effective state and federal regulatory guidelines for the holding Companies to prevent future abuses. FEDERAL POWER ACT - 1935

Enacted by Congress in 1935, the Federal Power Act increased the Federal Power Commission’s responsibilities to oversee and “regulate the transmission and sale of electric energy in interstate commerce.” Originally, the FPC was W W W. R MEL .O RG


At the 1893 Chicago World’s Fair and Exhibition, Westinghouse successfully demonstrated the safety, economics and practicality of Tesla’s Pholyphase or alternating current method of generating and transmitting electricity.

established to oversee/regulate power projects on navigable waterways under the Federal Water Power Act. VERTICALLY INTEGRATED ELECTRIC UTILITIES AND REGULATED OPERATIONS

This post-federal intervention era created the foundation for vertically integrated electric utility companies. Operating as natural monopolies primarily in or near urban areas, they were vertically integrated or responsible for providing generation, transmission and distribution of electricity to customers. To control the balance of energy supplied and used, each utility created a control area. Regulatory oversight was the responsibility of state PUCs for IOUs and municipal leaders for city municipal power agencies. Service rates were under constant scrutiny through the Uniform System of Accounts method to ensure customer abuses did not occur. Operating in a regulated, cost-based environment, utilities would plan and build infrastructure to meet the needs of the customers they were obligated to serve. The utility would recover its operating costs plus regulated profit (approximately 10 percent) through their approved service rates. Electric utilities were under state PUC oversight, in practice, due to their Vertical Integration structure and bundled services operation. Therefore as the demand for electricity grew, utilities could add to their system infrastructure with a return on their investment guaranteed. Utilities would add facilities and get paid for this investment from service rates paid by their customers. The utility industry continued to grow and grow quickly. Utilities would construct generation as close to their customers, typically densely populated urban areas, within state borders, to reduce system losses which were (and still are) very costly. The electric utilities were primarily under state PUC oversight and control since their activities remained predominantly intrastate



in nature. PUCs reviewed every aspect of utility operation from siting, to service requirements, through final rate development. Each utility operated a control area for the area of the country they served (i.e. Commonwealth Edison’s control area was Chicago). Control areas match electrical generation to load requirements and use

1937-1964 Technology Improvements and Regional Interconnection

Over a relatively short period of time however, improved efficiencies of scale in the generation sector were realized by making generating units larger. Electricity could be generated more efficiently and therefore cheaper with larger generators. At the same, time transmission

voltages increased in order to reduce system losses. To provide their customers with the cheapest electric power possible, these two factors were combined. Larger generating stations, centrally located and nearer their fuel supply connected to high voltage transmission lines began replacing the smaller, distributed generating stations connected to lower voltage power sub-transmission/distribution lines. Utilities were building very large, central generating stations that produced electricity cheaper and coupled this with higher voltage transmission for reduced losses. This resulted in cheaper electricity costs. As a result of the centrally located, large generating stations and high/extra-high voltage transmission systems the United States’ electric system evolved from many locally operated, geographically smaller grids, to one where interstate transmission lines interconnected many

different utility systems. This increased interconnectivity at much higher voltages offered more reliability and improved system economics to provide lower cost electricity. Each utility served its respective customers either with its own generation or through purchases with neighboring utilities called wheeling using contract path pricing. The individual control areas still played a very important role in electricity sales to neighboring utilities. The Federal Power Act and individual state laws controlled how the utility industry operated through regulatory oversight primarily at the state level and to a lesser extent the federal level. Reliability of the electric system was now both a regional and local CA concern.

1965-1969 Northeast Blackout and Regional Reliability

The great Northeast Blackout of 1965, uncovered a weakness in the United States’ and Canada’s interconnected electric grid. One disturbance in one section of a large interconnected grid could cause a cascading effect that could interrupt service across a wide geographical area. Specifically, the 1965 Blackout interrupted electric service over 80,000 square miles (eight states) in the Northeastern U.S. and large parts of Canada. This blackout started with a single 345kV transmission line relaying failure near Toronto, Canada. It was determined a regional coordinating body should be created to ensure regional reliability over a large geographic area. As a result of this major blackout the North American Electric Reliability Council (NERC) was formed, June 1, 1968, under the authority of legislation termed the Electric Power Reliability Act in 1967. Today, NERC is responsible for overall reliability, planning and coordination of electricity supply in North America. NERC is



The birth of the Rocky Mountain electric system infrastructure.

organized as a non-profit agency comprised of 10 regional councils. The regional councils represented smaller regions of North America. Through this model, the North American interconnected electric power system became the most reliable system of its kind in the world. This is essentially how utilities operated before deregulation legislation began to appear – and that is now changing.

1970-1977 Environmental &

Conservation Concerns, and Department of Energy Organization Act The 1970s was the start of difficult times for the electric utility industry. Prices of electricity would quadruple between 1970 and 1985. This was not due to poor management of utilities; they generally continued to operate with their customers’ best interest in mind by employing techniques (large central stations and HV/EHV transmission) to continue delivering reliable, cheap electricity. It was due to a perfect storm of unforeseen and uncontrollable events that no one predicted. These

events were environmental and conservation concerns, poor U.S. economic performance and reduced anticipated load growth, inflation and occupational safety concerns. In 1970 the Clean Air Act was passed by Congress. This act forced substantial reductions in allowable emission levels (SO2) from coal-fired power plants because of acid rain concerns. This was followed by the Water Pollution Control Act of 1972. Both acts substantially reduced the amount of electrical power the state-of-the-art, large, central generating stations could create, thereby reducing the amount of generation reserve capacity available to the interconnected power system. The energy crisis of 1973, brought on by the OPEC oil embargo, raised fuel prices used to generate a substantial amount of electricity. This crisis also initiated the start of a conservation and improved energy efficiency usage mindset in the U.S.. The Energy Supply & Environmental Coordination Act of 1974 (ESECA) required utilities to stop using natural gas or other petroleum based products to generate electricity. Followed by the Resource Conservation & Recovery Act of 1976, amendments to the 1970 Clean Air Act issued in 1977, the Powerplant & Industrial Fuel Use Act of 1978,

S Only

Energy Generation Operations Program Update Southeast Community College’s Energy Generation Operations program, located in Milford, Neb., has been in operation since January 2011. Students graduate with a two-year degree in 18 months (six quarters). SCC starts and graduates two groups of students every calendar year. The program offers face-to-face, online and hybrid delivery systems. This Associate of Applied Science degree program was designed to train students to be operators in a variety of processing plants, including nuclear power, fossil-fueled power plants and general processing facilities. Core courses, required of all program students during their first five quarters, include speech, writing, math, physics, computers, and humanities. Program-specific courses include safety courses, mechanical and fluid systems, boilers, steam turbines, SCADA, instrumentation, process dynamics, technical diagrams, electrical and HVAC fundamentals, electric power generation, motor controls, green energy technology, and backup power. Focus courses are offered during the sixth and final quarter. The focuses currently offered are nuclear, fossil and process operations. Specific courses in these focuses include, for nuclear: atomic structures, nuclear plant layout, reactor safety, reactor plant materials, and radiation detection and protection.

The fossil focus includes classes on coal plant operations, gas turbines and HRSG systems, pipeline operations and plant operations, and troubleshooting. The process operations focus includes pipeline operations, biofuels fundamentals, microbial ecology, process plant chemistry, and ethanol operations. Students also are required to complete an internship course consisting of 40 hours at each of three industry facilities for non-paid job-shadowing. As of December 2013, 55 students have graduated from the program. These graduates are working as power plant operators in nuclear, coal, combined cycle, and wind facilities. In addition, a number of graduates are operating pipeline systems, ethanol plants and fertilizer manufacturing, as well as working as boiler operators in pet food processing plants and a hospital heating/cooling facility. Companies that have hired SCC graduates include Nebraska Public Power District, Omaha Public Power District, Lincoln Electric System, Abengoa Bioenergy, Green Plains Renewable Energy, Poet Ethanol, Koch Fertilizer, Flint Hills Resources, HOA Solutions Water Treatment, Purina Pet Food, and Archer Daniels Midland. The average starting wage for program graduates is around $22 per hour.

For more information or to list your company as a potential employer and/or internship site, contact: John Pierce Program Chair 600 State St. Milford, NE 68450 402-761-8394

and the National Energy Conservation Policy Act of 1978 all contributed to further reductions in generating capacity of the large power plants. In this precarious environment, several Federal agencies, including the DOE and the FERC were created by the Department of Energy Organization Act in 1977. FERC was given the jurisdictional authority assigned to the FPC. This was also a difficult time for the U.S. economy. Inflation grew and economic expansion slowed to a crawl or stopped altogether. This was reflected in utility industry as very low or zero load growth. However many state-of-the-art, large, central station power plants were under construction to supply the anticipated increase in load growth, as predicted in load growth forecasts. These powerplants were primarily coal and nuclear which were very costly and took years to build. Not only did these plants cost more as a result of inflation and increases on financing costs, extended construction time due to occupational safety concerns and regulatory requirements, there was no need for them once completed due to the drastically reduced load growth. The result was excessive generation capacity reserve margins. These additional costs incurred by the utility were legitimately passed onto the customers which resulted in the dramatic price increases for electricity seen between 1970 and 1985.

1978 Public Utility Regulatory Policies Act (PURPA)

Public Utility Regulatory Policy Act’s provisions created a tremendous ripple effect throughout the electric utility industry that would impact it for many years to come and which continues today. The intent of PURPA was to introduce more efficient, cheaper, and environmentally friendly generation



Typical power plant control room of the 1950s.

to the power system. New generation technologies could produce electricity more cheaply than their large predecessors. Economies of scale favored these new technologies - bigger was no longer better. Reduced U.S. dependency on foreign oil and more generation capacity was needed. PURPA accomplished this through the introduction of FERC approved, non-utility generation called Qualifying Facilities (QF). Utilities were required to purchase this generation from the QFs. The additional capacity QFs supplied was relatively small due to limitations imposed upon them. Other PURPA provisions included the addition of sections 210, 211 and 212 to the FPA, which gave FERC authority over QF interconnections and transmission wheeling.

Near-term results of PURPA legislation was cheaper and cleaner generation technology development, which was also added to the power system via QFs and larger Independent Power Producers (IPPs). There were other more subtle effects – winds of deregulating the regulated generation sector. At this time, the natural gas sector was also being deregulated under FERC’s oversight. This led many to believe the same could be applied to the generation sector, given the new generation technologies. Many believed the generation sector was no longer a natural monopoly since most companies could now afford to construct smaller, cheaper powerplants. Many believed replacing the regulated, cost-based sector with

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a deregulated, or competitive, marketbased approach would result in cheaper electricity through improved business decisions combined with the cheaper generation technologies. Not knowing the direction the industry would take, utilities began to reduce costs related to generation, transmission, and distribution infrastructure, employment levels (i.e. many layoffs and early retirements). As a result generation reserve margins and transmission capacity reserves began to decline. Between 1978 and 1987, other regulated industries in the U.S. began to be deregulated. These other industries included the airline industry in 1978 and telecommunications (AT&T) in 1984. Further deregulation efforts in the natural gas industry opened access to the pipelines and spot market for price in 1986 and 1987. All attempts, it was theoretically believed, would lower cost through competition.

Co-op members gather in a local gym to discuss electrical issues.

lation of transmission system operations, both still under the control of VIUs and their control area operators. It was believed by FERC and Congress that without access to the transmission system, the anticipated benefits of new generation technologies (cheaper Energy Policies and more environmentally friendly Act (EPAct) electricity) would not be realized. Primary provisions of EPAct The primary intent of the EPAct was to included FERC approval of Exempt create open access to the transmission Wholesale generators (EWGs) and system for all generating companies, added section 213 to the FPA. EWGs both utility and non-utility (QFs and were allowed to sell electricity to the IPPs). There were instances reported to bulk power market and section 213 FERC of vertically integrated utilities extended FERC jurisdictional authority (VIUs) preventing QF and IPP generaand oversight over transmission access tion being dispatched through manipuissues. As a result of EPAct, transmission tariff structures improved and open access tariffs had to 1939-2014 be filed (with FERC) before lucrative ac801 North Broadway cess to wheelPost Office Box K ing contracts Cortez, CO 81321 would be granted by Phone (970) 565-4444 FERC. In Toll Free (800) 709-3726 1992, for the first


Celebrating 75 Years of Service

Empire Electric Association, Inc.



time, generation added by nonutility generators exceeded that added by traditional utilities. After the EPAct and up through 1995, transmission system access discrimination by VIUs continued to be reported to FERC. In response the FERC, admitting that transmission is still a natural monopoly and should be treated as such, issued several policy statements. These policy statements were Comparability Standard, Stranded Cost Notice of Proposed Rulemaking (NOPR), Transmission Pricing Policy Statement, Pooling Notice of Inquiry, Regional Transmission Group Policy Statement, and Merger Policy.

1996 FERC Orders No. 888 & 889 (April 1996)

These two orders were issued concurrently and were the first attempt at wide-sweeping changes to promote deregulation of the generation sector. Order No. 888 addressed open access to transmission issues. Order No. 889 addressed the issue of access to transmission system information by all interested parties. Why deregulate the U.S. electric

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utility industry, the world’s most reliable and cheapest system of all developed nations? There were three primary reasons: to reduce the cost of electricity through new technologies and improved business decisions; to accelerate the introduction of new generation technologies; and to provide access to cheaper electricity as seen in other U.S. regions. It is important to note that deregulation efforts apply to the generation sector at the national level. The transmission sector will still be regulated, while the distribution sector will be deregulated on a state-by-state basis. With that said, Order No. 888’s primary objective was to once again provide non-utility generators (EWGs, IPPs, QFs) and utility generators open access to the transmission system. FERC was still receiving reports of transmission system operation and generation dispatch abuses by VIUs. The



main provision of the order designed to accomplish this were: all jurisdictional utilities were required to file an open access transmission tariff; required IOUs to functionally un-bundle wholesale power services (generation) from transmission services nationally; reciprocity for non-jurisdictional utilities; recovery of generation-related stranded costs; and allow other areas of utility operations like ancillary services, comparable service, mergers, etc. Functional unbundling would separate the ties Vertically Integrated Units had between generation and transmission assets. Deregulation, FERC said, would result in the generation sector, utility and non-utility alike, competing against each other. The transmission sector would be restructured to support the deregulated operation of the generation sector. It would be controlled by newly established, non-profit Independent System Opera-

tors. Order No. 888 outlined 11 ISO operational principles and guidelines. It made ISOs responsible for operating: the transmission system, OASIS, generation dispatch (& queue) and the ISO control area power markets (generation and transmission). Under Order No. 888, FERC asserted it had jurisdictional authority over retail transmission service, specifically wholesale transmission (wheeling) and unbundled transmission as defined within Order No. 888. The state of New York (along with eight others) disagreed and filed suit. The case was brought before the U.S. Supreme Court. On March 4, 2002, the U.S. Supreme Court ruled in FERC’s favor. In fact, in dissenting remarks, three of the justices stated they believed the FERC should also have jurisdictional authority over bundled transmission. Order No. 889 addressed the issue of insufficient sharing and knowledge of transmission system information, which was previously exclusively held by Vertically Integrated Units. Titled “Open Access Sametime Information System,” or OASIS, it made transmission system information, including available transmission capacity, available to all interested parties wanting access. This was designed to prevent one avenue of possible transmission system access discrimination. ISOs proposed after Orders No. 888 and 889, typically were organized by state boundaries or areas slightly larger. FERC also called for ISOs to be operational by July 9, 1996. This proved to be a very short timeframe for such a very complicated task. After operating under the provisions of Order No. 888 for several years, it was determined that substantial barriers to functional deregulation continued to exist and would need to be corrected. As a means to that end, FERC issued Order No. 2000 on Dec. 20, 1999.



FERC Order 2000 (December 1999) Order No. 888 had two primary shortcomings: inefficient operation and expansion of the transmission system; and continued limits to transmission system access continued to be reported to FERC. Order No. 2000, FERC’s second attempt at wide-sweeping changes in how the electric utility industry operated, was issued primarily to address these two issues. Other benefits were anticipated -- specifically the continuous goal of lower electricity prices plus creating a form of lighter handed regulation. FERC believed that transmission would be more effective and efficient (cheaper) if it were addressed on a regional, multi-state scale. This is important because electricity doesn’t stop at state borders set by man. All states within an interconnection are impacted by disturbances within it, as evidenced by the Western interconnection disturbances in the summer of 1996. ISOs should be larger than just the state boundaries, FERC asserted. To that end, the Commission created Regional Transmission Organizations. Under FERC’s plan, RTOs would




operate the transmission facilities of the transmission owners that comprised an RTOs control area, but these organizations would be larger, appropriately-sized versions of their ISO predecessors. Continuing transmission system discrimination activities would be addressed in the RTO guidelines. FERC-approved RTOs would have to meet, at a minimum, the four characteristics and 8 functions FERC identifies as required for proper RTO operation. The four characteristics are: independence, scope (geographic) and regional Configuration, operational authority, and short-term reliability. The eight RTO functions are: tariff administration and design; congestion management; parallel path flow; ancillary services; OASIS calculations (ATC); market monitoring; planning and expansion; and interregional coordination. The ISOs already in operation were required to prove they met these criteria to receive FERC approval. There were differences between RTOs and ISOs. RTOs could be operated to earn a regulated profit for financing infrastructure expansion. FERC outlined a voluntary approach was taken for transmission owners to hand over control of their facilities to an RTO of which they

were a member. At or near this time Independent Transmission Companies began to appear. An ITC is a collection of transmission owners combining to form one large transmission company (e.g. – TRANSLink). FERC specified that ITCs could participate within an RTO or form their own. Therefore an RTO could be a non-profit organization which was previously an ISO or it could be a regulated for profit Transco. RTOs proposed after Orders No. 2000 typically were geographically larger than their ISO predecessors, but were still not as large as FERC believed necessary to be truly effective. Learning from the ISO restructuring process, which was underestimated, Order No. 2000 allowed more time for completing transmission sector restructuring. FERC requested the resulting RTOs be operational by Dec. 15, 2001. Under this scenario, FERC envisioned five RTOs for the entire U.S. transmission system – Northeast, Southeast, Midwest, Texas and the entire Western Interconnection. This did not occur. Instead 13 separate, non-continuous RTOs were initially proposed, each with its own unique transmission and wholesale market rules. FERC did not approve several of these RTOs and requested they combine with a neighboring RTO. The number of proposed RTOs decreased to nine, but each still retained its own operating rules. The result was a problem referred to at the RTO boundaries or seams. Due to their different operating rules, seams are problems related to scheduling and paying for electrical service when coordinating power flows between RTOs. As reported to FERC, seams issues allowed continued open access discrimination and impediments to wholesale power competition. To correct this, FERC issued the Standard Market Design NOPR on July 31, 2002. The primary goal of SMD was to eliminate seams issues by standardizing the way generation and transmission markets would work. This design

would also create an effectively larger geographic region, which FERC also preferred. It was believed SMD would also better mitigate market power, promote transmission planning and expansion, lower the cost of electricity and create a framework for cooperative state and federal regulation. To accomplish this goal, major provisions of SMD called for the introduction of independent transmission providers to replace RTOs. ITPs would retain many RTO responsibilities plus others to accomplish the primary goal of SMD. Under the SMD proposal, jurisdictional utilities must file new transmission tariffs. Non-jurisdictional utilities would follow reciprocity guidelines established under Order No. 888. Locational marginal pricing and congestion revenue rights were introduced as new transmission pricing policies. FERC continues to assert it had jurisdictional authority over bundled transmission, to oversee market power and, if required, to mitigate abuses of market power. Finally, FERC proposed to develop resource adequacy guidelines and a regional planning process to sustain a viable electrical power system.

and NERC are dealing with include critical infrastructure protection, carbon regulations, substation security and sabotage incidents. Recently, grid vulnerability has become front page news in the media. As more renewable generation sources are added to the system, grid reliability and aging infrastructure are also

major concerns for utilities today, and the pace of new technology solutions to address industry challenges is faster than ever before. About the author: Jeff Hein, P.E., is the Sr. Manager, Regional Transmission Policy, Xcel Energy. He can be reached at

2003-PRESENT Northeast Blackout

of 2003, CIP, Carbon Regulations and Grid Vulnerability Regulations and reliability became an even bigger focus for the industry in 2003 when a widespread power outage occurred throughout parts of the Northeastern and Midwestern United States Ontario, Canada. An estimated 10 million people in Ontario and 45 million people in eight U.S. states were affected by the blackout. Other vital issues that utilities, the EPA W W W. R MEL .O RG


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[This article originally appeared in the 2013 Summer Edition of the EPRI Journal. It is being reprinted here with permission from the Electric Power Research Institute.]


as the backbone of our energy network, is undergoing a transformation—a metamorphosis driven by renewable energy, smart technologies, distributed resources, and the underlying capacity to manage more data from more sources than ever before. Utilities increasingly agree on what the new grid will look like, but they are less certain about the best strategies for getting there. EPRI launched a project in 2011 to develop an overview of this significant shift and to evaluate potential technical solutions that will enable utilities to continue to deliver electricity reliably and affordably. The project’s goal is

to prepare the utilities for the nextgeneration grid, sometimes referred to as Grid 3.0, which will require more computing power and better software to process and analyze massive amounts of data, to forecast demand, and to meet that demand with supply from a combination of centralized, baseload power generation and distributed, intermittent power generation. With Georgia Institute of Technology as a research partner, EPRI is focusing on developing software applications for running this new and more complex energy management system. The goal is to create a more seamless process for planning, operations and postoperational analysis of the systems—a process based on high-performance, parallel comput-

ing power, which will deliver faster and more accurate results. The beefed-up computing power will enable utilities to carry out contingency analyses that incorporate multiple scenarios at the same time while also reducing redundant efforts. To make more effective use of the data and to improve planning and execution, utilities will benefit from 3-D visualization tools for forecasting energy demand and the capability of the power plants and grid to meet it. “We are putting together core pieces to demonstrate the balance that has to take place between load and generation on a real-time basis,” said Paul Myrda, the EPRI technical executive in charge of the project. “Wind, for example, is extremely variable. How W W W. R MEL .O RG


does one plan ahead to dispatch the appropriate units to compensate and react to it in real time?” EPRI and Georgia Tech researchers have progressed from sketching ideas to developing proof-of-concept designs. They plan to bring those designs out of the lab in 2015 and make them available to software companies, which can then develop them into commercial products.

From Grid 1.0 to 3.0

The grid has come a long way since its birth in the 1800s. Supervisory control and data acquisition (SCADA) systems emerged in the 1950s to manage the growing number of power plants and power lines that were spilling from cities into rural regions. Back then, utilities manually controlled the ramp-up and output of their power plants. Today, with Grid 2.0, much more powerful SCADA systems have been integrated into comprehensive energy management systems to manage the expansion and interconnection of regional grids that emerged in the 1960s. The computers became powerful and sophisticated enough to manage multiple interconnections between centralized power plants and to ensure a balanced supply and demand among the many utilities in the market. The technology has also given utilities and grid operators indications



of power plant and grid performance about 20 to 30 seconds after the fact. Now comes the start of a new stage for the grid. The regulatory push and funding in recent years to modernize the grid by installing smarter meters, digital communication networks and sensors are enabling more precise grid monitoring and generation of a growing amount of data on energy production and grid performance. The emergence of renewable energy generation, with intermittent sources such as solar and wind, makes it more difficult to predict and manage the electricity supply and balance of this more complicated system. Renewable energy sources increasingly include both large, centralized power plants and distributed units, such as rooftop solar panels. Policies to promote the sale of excess electricity from these small power generators in the distribution network drive the need for a more powerful and sophisticated energy management system. The gradual increase in sales of electric cars and the use of batteries or other types of energy storage by consumers and solar and wind plant owners will require additional planning to make them fit well into the grid’s operation. Grid 3.0 will require new computing hardware, sensors and software to integrate all these new additions to the grid, ensure their interoperability, and manage new market mechanisms for buying and selling renewable electricity and power from energy storage systems.

The Attack Plan

Enhancing the system is a daunting task. For the Grid 3.0 project, EPRI is focused on four areas where new software development will enable its utility members to work with some of the key changes and, more im-

portant, to use a model designed to manage many more moving parts.

Current Limitations

Research in the first area looks at the limitations of applications used for planning and operations and for conducting postoperational analyses, with the goal of creating a more seamless planning and management model for the power plants and grid. Currently, the process uses disparately developed software and protocols for each of the three segments, which makes it difficult to do comparative analyses and create a unified strategy from planning to execution. Given the complexity of Grid 3.0, it is more important than ever for utilities and grid operators to have a systematic approach that allows them to work more efficiently and save money and time.

High-Performance Computing

The second research focus is on ways the utility industry could adapt the high-performance computing commonly used by financial institutions, Internet companies and automakers in carrying out the heavy data processing and analyses needed for engineering and financial transactions. High-performance computing makes use of supercomputers, which typically run on tens of thousands of traditional processors and incorporate graphics processors to speed up the more intensive parts of the calculations. These configurations excel at parallel computing—running multiple computational calculations at the same time—to divide a big problem into smaller pieces and to solve them concurrently. This approach is very different from the computing architecture commonly employed in the utility industry, which uses less powerful computers with traditional processors that can solve only one problem at a time. “With the growing amount of data from sensors and smart meters and the need for better energy production and consumption forecasts to run




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the grid, utilities should take advantage of parallel computing to get the real-time analyses needed to operate more efficiently,” said Leilei Xiong, a Georgia Tech researcher. Switching to a different computing architecture will require new software designed to meet utilities’ needs. The researchers will first identify the scale and availability of the computing power necessary to deliver real-time analyses and then consider which algorithms are best suited for processing utility data.

Contingency Analyses

The project also aims to improve contingency analyses of the power grid. Contingency analyses currently simulate and quantify potential problems linearly, one at a time, to anticipate possible causes of system failures and blackouts and help utility staff identify effective repair solutions ahead of time. These analyses typically run repeatedly every few minutes with the same types of data input. Because the analyses are carried out for both planning and operations, they often create unnecessary redundancy. And though this method has worked well in the past, it won’t be as efficient or provide sufficiently accurate predictions in the more dynamic grid of the future. Managing the two-way flow of electricity between centralized and distributed renewable generation will require software that can simulate multiple scenarios across different parts of a utility’s territory, equip utilities to better coordinate planning and prevention, and support effective planning to fix equipment failures and deal with emergencies.

Visualization Tools

The fourth part of the project sets out to develop better visualization software. Visualization tools are useful for understanding complex data and homing in on information that is critical for planning and for operating power plants and the grid. Current visualization programs usually present data in two dimensions and lack the ability to



project potential scenarios in the hours or days ahead, which will be necessary for managing the integration of distributed resources and renewable energy into the grid. The improved web-based visualization tools can create 3-D views of the data and provide navigational features that will enable utilities to examine real-time performance data more closely and create forecasts from different parts of their operations at different times. To develop the prototype, researchers will select sample data sets and experiment with algorithms for retrieving and processing utility data. At the end, the researchers will combine these elements—new computing power, dynamic contingency analyses, and 3-D visualization and navigational tools—to create a prototype architecture for the nextgeneration energy management system.

What Lies Ahead

Today, the utility industry recognizes this wholesale transformation of the grid to be in its early stages. Many utilities are already carrying out pilot projects to target specific trouble spots, such as the impact of electric car charging, and are designing solar inverters for better voltage control. But the grid of tomorrow will require even more sweeping changes in its planning and operations, from power generation to delivery. EPRI recognizes the difficulties in redesigning energy management systems to respond to future needs. The Grid 3.0 project takes this huge challenge and divides it into four manageable parts that will eventually be integrated to create a new

model. To reach this goal, utilities and software developers alike will have to be willing to join in the effort to stay ahead of major developments rather than merely react to them. “With the existing management system designs, the software is still based on legacy concepts of mathematical processes and computation,” Myrda said. “Our utility members are really challenged, and we are trying to bring everyone along the learning curve to develop these tools and make it clear to vendors what they will ultimately need to deliver.” Some of the underlying resources needed for Grid 3.0 already exist. Supercomputers that use graphics processors for parallel processing are not rare animals. Software for collecting, analyzing and storing data has become a hot area of technology development at companies such as Oracle and EMC, thanks to the explosion of Internet data from ecommerce sites and social networks. What utilities will need are applications that can build on such computing and database management technologies. “What we are doing is taking the various building blocks and connecting them to create innovative solutions for our industry,” Myrda said. This article was written by Ucilia Wang. Background information was provided by Paul Myrda.


Why Planning Studies Matter to Utilities BY JAMES D. WHITAKER, PE, TRC COMPANIES, INC.



Collaborate to Avoid Overload


States are broadening their renewable energy portfolio as a result of state-mandated Renewable Portfolio Standards and federally available renewable energy Production Tax Credits. This is especially true in the Southwest and New England, where states have ramped up solar energy project development, and in Texas and the Midwestern states, where wind energy sources continue to come online. At times, it can seem like the California Gold Rush, but modern-day prospectors have a powerful tool that the Forty-niners did not: planning studies to help guide their way to success. There is no question that new-onthe-scene renewable projects will add strain to an already over-taxed power grid at both the transmission and distribution levels. Increased loading, congestion, voltage and dynamic stability are all weighty concerns. Interconnection planning studies executed well in advance of bringing renewable projects online are of utmost importance in informing utilities about how their systems will respond to contingencies, planned outages and varying loads. They examine regulatory requirements, costs, timelines, project developers, peak and off-peak variability, and a host of technical aspects including equipment loading, voltage response, voltage flicker and dynamic stability. Smart utilities are getting more mileage from their planning study activity by working with developers early in the process to target projects in critical areas of their transmission or distribution systems.

It’s not unusual for utilities to have mature study processes. In-house distribution planning engineers model their feeders with study software as transmission planners have always done. The distribution models are updated regularly via their GIS or SCADA systems, making them highly accurate. But many utilities are overwhelmed with interconnection requests and have issued highly detailed request for proposals (RFPs) to avoid project gridlock and engage partners in a more collaborative planning role. Most distribution companies are now developing models as part of their interconnection processes but usually only when an interconnection request to that feeder arises. Procuring as much data as possible through the RFP process is highly recommended. Some project developers have elected to skip or minimize the “upfront” investment of modeling, causing delays later. A need to circle back for additional information may affect the project’s position in the interconnection queue and cause headaches for the utility. The worst result is the rejection of a project even before it begins. To avoid that, developers should complete a preliminary (10–20 percent) engineered interconnection.

The Golden Rules New connections to the transmission grid undergo rigorous screening to ensure that NERC reliability standards are met and maintained. FERC Order 2003 and its subsequent modifications established the Large and Small Generator Interconnection Process requirements. Additionally, studies must consider regional, state and other local reliability requirements. In some regions, state regulators, who also serve as de facto consumer protection agents, must be engaged in the process because faulty projects may affect their rate-setting responsibilities. For example, states such as New

Mexico and New York obligate the utilities and developers to address all problems up front (resulting in protections for utilities if they meet obligations—and problems if they don’t). Studies are critical to determining system impacts—either positive or negative—particularly to distribution voltage levels. Taken individually, distribution-connected generation may have a small impact when compared to the feeder load, but cumulatively the impacts to a local area can be dramatic, such as unplanned voltage swings or dynamic instability. That’s why all parties—private, public and government—are best served by taking a holistic and total-systems approach.

Beware for Budget Busters Utilities are smart about interconnectivity. Rather than build to fill the gaps in their systems, which is costly, working cooperatively with renewables developers to bridge the divide is a more efficient and effective approach. Connecting a new energy source to the grid is expensive. The costs for interconnection range from a few hundred thousand to millions of dollars, depending on the interconnecting utility, ISO or RTO policies. Adequate planning via interconnection studies helps ensure that any costs are minimized, whether they are for the interconnection itself or for any required system upgrades. Planning costs that were once optional are now required in some cases. Recently, for example, during an operational study for a Texas wind project, a sub-synchronous control interaction issue was discovered between the project and the utility system, causing instability when connected. The problem occurred as a result of a unique system condition that the developer and turbine vendor thought were a low risk and did not need to be addressed through additional studies and control modifications. Two weeks later, these unique conditions presented themselves, causing all 200 MW of turbines W W W. R MEL .O RG


to burn up. If the project planners had recognized the potential impact of the flaw through the operational study and investigated it with further studies, the mishap could have been avoided. As a result, ERCOT now requires these types of studies for all wind farms. As for system upgrades for reinforcements, the final costs are difficult to predict. Some entities require the generator to pay for all upgrades, while others will divide the cost based on the number of MW in a study cluster. Some entities may also approve rolling the cost into the rate base. Knowing in advance what is allowed can help a developer or utility budget appropriately for the studies and provide more robust data to aid in decision-making. As with anything in life, study costs vary based on the size and details. To eliminate speculative projects or those without power purchase agreements or site control, some regulators and utilities require developers to deposit a percentage of the project’s interconnection cost and system upgrade costs. The deposits are held by the utilities and can bear interest at a FERCdetermined rate. The deposit amount will increase as studies progress and network upgrades become known. Developer deposits, as expected, can total millions of dollars. To serious developers, this shouldn’t be a concern because they get their money back in the form of credits or even total repayment over time. If they decide to withdraw the project from consideration, the deposit, minus the study costs, is refunded.

Adequate Planning Can’t Be Rushed The time frame to complete a study depends on the location at which the developers are requesting interconnection, the number of interconnections a utility has to process and the voltage at which the interconnection will take place. As the influx of interconnection requests continues to grow, careful attention to timing and the myriad study details will ensure that utilities are able to successfully bring online



the resources their systems need. Transmission voltage interconnection studies can take anywhere from a few months to two years or more because of FERC Order 2003, which defined the transmission study process. Again, the location of the requested interconnection is a factor but not the only factor. Under FERC Order 2003, the process starts with a feasibility study that examines the transmission system with load flow and short circuit analysis to determine the basic interconnection requirements and identify any possible mitigations or network upgrades as well as their costs. Upon acceptance of the results determined by the feasibility study, the completion of a system impact study follows to identify the interconnection requirements, network upgrades or mitigations, as well as a good faith estimate of project costs. It uses the same analyses as the feasibility study, and adds dynamic stability and transient analysis. At this stage, the significance of the modeling accuracy rises to the surface. A good, working, dynamic model can define a low-cost interconnection system versus one that will cost millions. A poor model may indicate dynamic voltage support for mitigations when in reality nothing would be required. Custom models provided by turbine vendors not only slow down the study process, but also may not work with existing models in the system. Results have shown that generic models will perform just as well as the custom models, unless the custom model is part of the standard model library for the software. If the system impact study results are accepted, a facilities study is the next step that will finalize the interconnection and network upgrades and the associated costs. The results are the detailed interconnection requirements such as relaying, metering and communication as well as network upgrades. Some utilities produce a fully engineered facility study. Most facility studies are a 10–30 percent engineered package

with cost estimates for these facilities. Distribution studies take from three weeks to three months to complete, depending on scope and specificity. For example, if more than one interconnection on the feeder or if the interconnection causes problems that must be mitigated, the study becomes more complicated. It is rare for a transmission project to be interconnected within a year of a request, but it is possible that distribution projects can be interconnected within six months. Preparing extensive site development research with no significant system mitigations needed allows the project to move much faster through the regulatory approval process.

Technical Considerations Not to Be Overlooked Significant technical challenges abound when conducting renewables interconnection studies. Dynamic stability and voltage flicker caused by cloud shading are just a few of the areas that must be addressed by engineers. When studies are conducted at the distribution level, the generation dispatch is against an infinite bus. At the transmission level, the renewable source is dispatched against specified gas or coal generation. In the next step, the pre-project case is compared to post-project case for differences, and engineers are on the lookout for study criteria violations. For thermal or loading, they look for equipment exceeding their amperage ratings. For voltage,

specific criteria must be met depending upon if the interconnection is connected via distribution or transmission. For transmission, the engineers look for voltages less than 95 percent of nominal or 110 percent of nominal. They also look at changes in voltage (delta) as well. A voltage delta of 5 percent or more can mean a dynamic instability or a voltage collapse issue that could cause a widespread system outage. For distribution systems, voltages must remain within specific limits during maximum and minimum load conditions for the normal feeder configuration when the project is operating at its rated capacity and power factor. During a contingency feeder configuration, distribution system voltages are allowed to remain within a wider range of limits during minimum load periods. However, if during maximum load periods the voltages fall outside a specified range, these voltages violations are considered pre-existing issues. The project must not exacerbate the problem beyond the specified limits when operational. For photovoltaic (PV) systems, voltage flicker is an additional concern. Voltage flicker is defined as a voltage variation sufficient in duration to allow visual observation of a change in electric light intensity of an incandescent light bulb. A graph developed by GE can help indicate where fluctuations over a given time may be viewed with borderline of visibility and borderline of irritation. Some entities’ operating criteria require the magnitude of voltage flicker to be limited to less than 6 percent, and the frequency of flicker fluctuations must be less than the border line of irritation boundary shown in the GE Flicker Limit Curve. Clouds shading PV panels adversely affect the output of a PV system. As a cloud shadow passes over a PV system, the output will decrease because of the reduction in sunlight. The change in PV system output on a distribution circuit may cause a fluctuation of voltage that can be seen by electric customers. This fluctuation would be classified

as a voltage flicker; however, the most common cause of voltage flicker on the distribution system is motor starting. The last study component that is examined is dynamic stability, which includes angular stability as well as posttransient voltage stability. The angular stability examines changes in rotor angles and whether a generator recovers after a contingency. When a generator is tripped for a contingency, system frequency is also examined. In some areas of the country, post-transient voltage stability is examined as well. What the engineer examines is the voltage and VAR support at critical buses. If sufficient VAR support is present, the system will remain stable and the lights remain on to generate revenue. Overall dynamic stability is critical not only to the system but to the entire grid.

The Eureka Moment Only a few prospectors in the late 19th century hit the “mother lode.” It’s amazing that some were even able to find a gold nugget or two given the crude mining and exploration tools (pans and hands). Today, robust and comprehensive studies are the rich veins that supply data. A good planning study will help predict system issues, and allow engineers to design mitigation strategies that accommodate irregularities. Relying on “luck” risks a utility’s reputation, reliability, performance and, ultimately, its bottom line. The path to success is working with the utilities to target interconnection opportunities within their systems and provide the most cost-effective and efficient sources. James D. Whitaker, PE, oversees TRC’s Power Systems Studies Group. He has more than 27 years of experience in transmission and distribution planning, substation, transmission and distribution engineering. Before joining TRC, Whitaker worked for Xcel Energy, Peak Power Engineering, Tucson Electric Power and Virginia Power. He can be reached at W W W. R MEL .O RG





Labor, OSHA, considers a power line crew a “mobile workforce.” This describes well the typical day of the utility or contractor crew out working on power lines. Their work site literally changes every day and sometimes several times a day. Managing crew worker safety, in this kind of environment, is challenging, to say the least, but the crew leader can be successful by applying a few best practices in T&D safety management. These best practices, however, begin with the right attitude and safety as a value within the company culture.



Safety Attitudes and the Corporate Culture

Many crew foremen may ask, “Isn’t safety management the responsibility of the safety department?” Crew members may be wondering the same thing. In one sense they are right, aren’t they? Management has a broad corporate and legal responsibility for safety, and quite often organizations will have a separate department to help manage their responsibilities. But in another sense—the bigger picture— safety is everyone’s responsibility. If the crew foreman and crew members are asking this question, they haven’t internalized the concept of safety as a personal responsibility. It could be that the corporate culture is to blame.

“Culture” is a word we often associate with the society of a nation or region. However, culture is also a concept that can be applied to a single company or even a department within a company. Every utility and every contractor has a company culture. Each department within that organization is likely to have its own culture as well. That departmental culture can mirror the culture of the larger organization or be at odds with the broader culture of the company. Often, cultural differences within the various departments of an organization are greatest when it comes to safety. For example, safe work practices may be enforced in the office or at the generating plant, but may be relaxed during field operations involving transmission

and distribution (T&D) crews. It is, however, the T&D operations department of a utility or the field operations of a contractor that are frequently exposed to the greatest risk. Crews are expected to repair lines and equipment at night or during storms. But even during routine maintenance of the system, high-voltage electricity is unforgiving, allowing no mistakes without serious consequences. The lack of safe work practices often poses lifethreatening hazards to line workers. The safety culture of the organization’s T&D operations department, as we will see, is a key performance driver that determines how the employee internalizes safety as part of his or her job.

An Attitude of Compliance

We often find an attitude of compliance within the field operations of utilities and contractors. That sounds pretty good, right? If our people would just comply with the rules and regulations, everything would be fine. Why don’t they just obey the rules? When management has this attitude, we naturally see it permeate the culture of the organization from top to bottom. OSHA, NESC, DOT, the safety department, the safety manual—everyone has rules and regulations that need to be complied with. “It is my responsibility to comply with the rules and regulations,” employees think, and the company culture reinforces

that thinking. The crew foreman becomes the champion of compliance, because too often, that is the only thing by which he or she is measured. However, does management truly want the workers focusing on compliance, or does management want the workers doing what’s required to stay safe in the workplace? It seems it should be the latter. Is compliance with rules and regulations part of staying safe in the workplace? Most likely, but it is a means to an end and in reality just one of the tools used in staying safe. Compliance is not an end unto itself. When we demand that employees focus on compliance with rules and regulations, we miss the point. The industry’s relationship with W W W. R MEL .O RG


OSHA regulations is a good example. The agency has accumulated a wealth of important information about safety and safe work practices for our industry since its inception 40 years ago. The information is specific, often detailed and can be a valuable resource for a crew foreman in managing safety. Unfortunately, during that same 40 years, OSHA has earned a reputation for being a policeman—an enforcer of regulations—rather than the partner in safety that it truly wishes to be. Too often, our crew foremen are forced to worry about OSHA inspections and fines rather than how OSHA regulations can be another tool for them in their safety tool bag. Compliance with everyone’s rules and regulations has a place in crew safety management—just not first place.

Where to Begin

The safety culture in any organization must begin with acceptance of personal responsibility for safety—your own and that of others. Safety for all workers is truly a value within an organization, and the culture begins to change immediately when management accepts it as such. We talk about our values. We display our values. We are proud of our values and tell our



customers why our values make us special. We expect our employees to adopt our values. Safety is a value, and each employee has a responsibility to perform to the expectations of our values. When the crew foreman has crew members who have accepted responsibility for safety and embrace safety as an important value for success, the foreman’s job is much easier. It’s then like he’s preaching to the choir. Safe work practices become an integral part of the job and are not seen as something extra or burdensome. Consideration for safety is integrated into everything the crew members do. Safety becomes front of mind, where it needs to be for superior performance. On this foundation of personal responsibility and safety as corporate values, the crew foreman can create a safety tool bag that will serve him and his crew members well.

The Safety Tool Bag

Safety for power line crews is not a thing—it’s a process, and a rather creative one at that. Crews are expected to work on multiple job sites within a typical day, and each one is likely to be different. This variety makes the job more interesting but can be a safety hazard in itself. So, the crew foreman

and crew members must not become complacent. They all must remain alert to the unique hazards that they face at this site that they didn’t face at the last one. For the foreman, this means that our plan for staying safe on this job is unique. A good pre-job briefing can help here. With everyone involved in observing and planning, hazards can be identified that are both typical to the work and unique to this job. We discuss the tools, equipment and work processes we’ll use, and who is responsible for each part of the job. We’ll also discuss emergency action plans and not assume everyone automatically knows what to do if the worst happens. Good preparation can be a good safety practice. Does the foreman need to know all the rules and regulations applicable to the work required for this job? Absolutely. Does he need to know this in case OSHA drives by or a company manager may be watching? Those concerns should be the last things on his mind. If the crew leader is following all the rules out of fear of retribution, he’s following them for the wrong reason. The rules and regulations are wonderful tools to help him keep crew members safe. Encourage the foreman to not just read them, but look beyond

the printed words. Each rule, each regulation has a deeper message—a spirit, if you will. For example, OSHA’s 1910.269(a)(2)(vii) regulation states, “The employer shall certify that each employee has received the training required by paragraph (a)(2) of this section.” OK, so we’ll make sure that our workers are trained. We’ll talk about PPE at the next safety meeting. The foreman may be in compliance with the letter of the law by doing this, but he has completely missed the spirit of what is needed. Training, in this sense, is referring to proficiency in both knowledge and skills. For power line workers this will almost always be the case. Rather than just recite something,

they need to perform it, to become proficient at it. For example, it’s not enough for a crew member to explain proper care, use and maintenance of PPE—he needs to demonstrate proficiency at it to truly be trained. Each rule and regulation has a deeper meaning and expectation that the foreman should understand. Compliance with the letter of the written word is not good enough. The company safety department is another wonderful tool often available to the crew foreman. A tool? The safety department is a tool? Yes. The safety department is another resource for the crew foreman. The best performing organizations have established the safety department as a support function to operations. They should not be the police department. The safety department is there to help the crew foreman do his job. Legally, management has the responsibility to enforce safety regulations within the company, but operationally, the foreman should be the enforcer. When the safety department is tagged with enforcement, it too often becomes the enemy of the crew rather than the partner in safety that it should be. This means safety managers and representatives must have a servant attitude and recognize that their success is in direct correlation to how operations perceives and uses them. The crew foreman’s safety tool bag

is probably bigger than he realizes. We’ve mentioned a few resources above that are likely not considered a resource by the foreman. Sometimes the crew foreman’s own attitude may be his biggest hurdle in safety management. Often, when we look at things differently, they suddenly become different for us.

Begin With the End in Mind

Author Stephen R. Covey suggested that one of the seven habits of highly effective people is to begin with the end in mind. That’s a good idea for crew safety management as well. Where do we want to end up? What does success look like in crew safety management? In defining that success, most people will include the attitude of the worker. We want the worker on that crew to have a good attitude about safety. Another element of success may be personal responsibility. So many things become easier when we accept responsibility for safety. Being accident- or incident-free, and sending our people home each evening with the same health they started with that morning, is usually a measure of success as well. The power line crew foreman will have much influence on the success or failure of any measure we put in place. Let’s arm these crew leaders with the best management and supervisory practices available to help them succeed. About the Author: Ronald J. Schenk, CUSP, is Executive Director of the Institute for Safety in Powerline Construction (ISPC), an electric utility industry association focusing on safety and training for line workers, and Director of T&D PowerSkills, LLC, a lineman training program. Schenk has conducted seminars and training sessions for utilities and contractors across the country on crew safety management. For more information, call 866-880-1380 or email Schenk at W W W. R MEL .O RG



RMEL Member Companies



ABB, Inc.

51 City of Yuma

101 Harris Group, Inc.


ABCO Industrial Sales, Inc.

52 Co-Mo Electric Cooperative

102 Hartigan Power Equipment Company


ADA-ES, Inc.

53 CoBank

103 HDR, Inc.


Advanced Motor Controls

54 Colorado Energy Management, LLC

104 High Energy Inc. (HEI)


Alexander Publications

55 Colorado Highlands Wind LLC

105 Highline Electric Assn.


Altec Industries, Inc.

56 Colorado Powerline, Inc.

106 Holy Cross Energy


57 Colorado Public Utilities Commission

107 Howard Electric Cooperative


American Coal Council

58 Colorado Rural Electric Association

108 Hubbell Power Systems


American Trainco Inc.

59 Colorado Springs Utilities

109 Hughes Brothers, Inc.

10 AREVA Solar Inc.

60 Colorado State University

110 IBEW, Local Union 111

11 Arizona Electric Power Cooperative, Inc.

61 Commonwealth Associates, Inc.


12 Arizona Electrical Apparatus

62 ComRent

13 Arizona Public Service

63 The Confluence Group Inc.

112 Incorporated County of Los Alamos Department of Public Utilities

14 Arkansas River Power Authority

64 Continental Divide Electric Cooperative

113 Independence Power & Light

15 Asplundh Tree Expert Co.

65 Cooling Tower Depot

114 Industrial Cooling Solutions

16 Associated Electric Cooperative, Inc.

66 Corporate Risk Solutions, Inc.

115 Integrity Consulting Services

17 ATCO Emissions Management

67 CPS Energy

116 Intercounty Electric Coop Association

18 Austin Energy

68 D.C. Langley Energy Consulting, LLC

117 Intermountain Rural Electric Assn.


69 Delta Montrose Electric Assn.

118 Irby

20 Babcock & Wilcox Company

70 DIS-TRAN Packaged Substations, LLC

21 Babcock Power, Inc.

71 Dowdy Recruiting LLC

119 Irwin Industries, Inc.- Power Plant Services

22 Basin Electric Power Cooperative

72 E & T Equipment, LLC

23 Beta Engineering

73 E3 Consulting

24 Black & Veatch Corp.

74 El Paso Electric Company

25 Black Hills Corporation

75 Electrical Consultants, Inc.

26 Black Hills Electric Cooperative

76 Emerson Process Management

27 BMT Acquisition, LLC

77 The Empire District Electric Company

28 Boilermakers Local #101

78 Empire Electric Association, Inc.

29 Boone Electric Cooperative

79 Encompass Energy Services LLC

30 Border States Electric

80 Energy & Resource Consulting Group, LLC

31 Bowman Consulting Group

81 Energy Reps

32 Brooks Manufacturing Company

82 Enovation Partners

33 Burns & McDonnell

83 Equal Electric, Inc.

34 Butler Public Power District

84 ESCÂ engineering

35 C.I.Agent Solutions

85 Estes Park Light & Power Dept.

36 Carbon Power & Light, Inc.

86 Exponential Engineering Company

37 Casey Industrial, Inc.

87 Finley Engineering Company, Inc.

38 CB&I

88 Foothills Energy Services Inc.

39 CBS Arc Safe

89 Fort Collins Utilities

40 Center Electric Light & Power System

90 Foster Wheeler


91 Fuel Tech, Inc.

42 Chimney Rock Public Power District

92 Gallup Joint Utilities

43 City of Alliance Electric Department

93 GE Power & Water

44 City of Aztec Electric Department

94 Golder Associates, Inc.

45 City of Cody

95 Grand Island Utilities

46 City of Farmington

96 Grand Valley Rural Power Lines, Inc.

47 City of Fountain

97 Great Southwestern Construction, Inc.

48 City of Gillette

98 Gunnison County Electric Association, Inc.

49 City of Glenwood Springs

99 Hamilton Associates, Inc.

50 City of Imperial

100 Hamon Research - Cottrell


120 J.L. Hermon & Associates, Inc. 121 Johnson Matthey Stationary Emission Control 122 Kansas City Board of Public Utilities 123 Kansas City Power & Light 124 KBR 125 KD Johnson, Inc. 126 Kiewit 127 Kirk Erectors, Inc. 128 Kit Carson Electric Cooperative 129 Kleinfelder 130 Klondyke Construction LLC 131 La Junta Municipal Utilities 132 La Plata Electric Association, Inc. 133 Lake Region Electric Coop Inc. 134 Lamar Utilities Board 135 Laminated Wood Systems, Inc. 136 Las Animas Municipal Light & Power 137 Lauren Engineers & Constructors 138 LBI, Inc. 139 Leidos 140 Lewis Associates, Inc. 141 Lincoln Electric System 142 Llewellyn Consulting 143 Longmont Power and Communications 144 The Louis Berger Group 145 Loup River Public Power District 146 Loveland Water & Power 147 Luminate, LLC




148 Magna IV Engineering Inc.

198 Reliability Management Group (RMG)

246 Total-Western, Inc.

149 Marsulex Environmental Technologies

199 Reliable Power Consultants, Inc.

247 Towill, Inc.

150 Missouri River Energy Services

200 Rkneal, Inc.

248 Trachte, Inc. “Buildings & Shelters”

151 Mitsubishi Hitachi Power Systems Americas, Inc.

201 Sabre Tubular Structures

249 Trans American Power Products, Inc.

202 Safety One Inc.

250 Transmission & Distribution Services, LLC

152 Morgan County Rural Electric Assn.

203 San Isabel Electric Assn.

251 TRC Engineers, Inc.

153 Mountain Parks Electric, Inc.

204 San Luis Valley Rural Electric Cooperative

252 Trees Inc

154 Mountain States Utility Sales 155 Mountain View Electric Assn.

205 San Marcos Electric Utility

253 Tri-State Generation and Transmission Assn.

156 Mycoff, Fry & Prouse LLC

206 San Miguel Power Assn.

254 Trimble

157 NAES Corp.

207 Sangre De Cristo Electric Assn.

255 Trinidad Municipal Light & Power

158 Navopache Electric Cooperative, Inc.

208 Sargent & Lundy

256 U.S. Water Services

159 Nebraska Public Power District

209 Savage Services Corporation

257 UC Synergetic

160 NEI Electric Power Engineering, Inc.

210 Sega Inc.

258 Ulteig Engineers, Inc.

161 New Mexico State University

211 Siemens Energy Inc.

259 United Power, Inc.

162 Nol-Tec Systems, Inc.

212 Sierra Electric Cooperative, Inc.

260 Universal Field Services, Inc.

163 Nooter/Eriksen, Inc.

213 Solomon Associates

261 University of Colorado

164 Norris Public Power District

214 South Central PPD

165 North Platte Light & Power

215 Southeast Colorado Power Assn.

166 Northeast Community College

216 Southeast Community College

262 University of Idaho, Utility Executive Course, College of Business and Economics

167 Northwest Rural Public Power District

217 Southern Pioneer Electric Company

168 Novinda Corporation

218 Southwest Energy Systems LLC

169 NRG Reliability Solutions LLC

219 Southwest Generation

170 NV Energy

220 Southwest Public Power District

171 O I C Outage

221 Southwest Transmission Cooperative, Inc.

172 Omaha Public Power District

222 Southwire Company

173 Omnicon Technical Sales

223 Springfield Municipal Light & Power

174 Osmose Utilities Services, Inc.

224 SPX Cooling Technologies

175 Otero County Electric Cooperative

225 SPX Transformer Solutions, Inc.

176 PacifiCorp

226 SRP

177 Panhandle Rural Electric Membership Assn.

227 St. George Energy Services Department 228 Stanley Consultants, Inc.

178 PAR Electrical Contractors, Inc.

273 Western Line Constructors Chapter, Inc. NECA

229 Stantec Consulting

179 Peterson Co.

274 Western Nebraska Community College

230 STEAG Energy Services LLC

180 Pike Electric, LLC

275 Western United Electric Supply

231 Storm Technologies Inc.

181 Pine Valley Power, Inc.

276 Westinghouse Electric Company

232 Sturgeon Electric Co., Inc.

182 Pioneer Electric Cooperative, Inc.

277 Westwood Professional Services

183 Pipefitters Local Union #208

233 Sulphur Springs Valley Electric Cooperative

278 Wheat Belt Public Power District

184 Platte River Power Authority

234 Sundt Construction

185 PNM Resources

235 Sunflower Electric Power Corporation

186 Poudre Valley Rural Electric Assn.

236 Surveying And Mapping, Inc.

187 Power & Industrial Services Corp

237 Switchgear Solutions, Inc.

188 POWER Engineers, Inc.

238 T & R Electric Supply Co., Inc.

189 Power Equipment Specialists, Inc.

239 T&D PowerSkills, LLC

190 Power Pole Inspections

240 Technically Speaking, Inc.

191 Power Product Services

241 TestAmerica Laboratories, Inc.

192 PowerQuip Corporation

242 Tetra Tech

193 Precision Resource Company 194 Provo City Power

243 Thomas & Betts Steel Structures Division


244 Thomas & Betts, Utility

196 Quanta Services

245 Timken Motor & Crane Services, dba Wazee a Timken Brand

197 REC Associates



263 UNS Energy Corporation 264 URS Energy & Construction Inc. 265 Utility Telecom Consulting Group, Inc. 266 Valmont Newmark, Valmont Industries, Inc. 267 Victaulic 268 Wärtsilä North America, Inc. 269 WESCO 270 Westar Energy 271 Western Area Power Administration 272 Western Electrical Services

279 Wheatland Electric Cooperative 280 Wheatland Rural Electric Assn. 281 White River Electric Assn., Inc. 282 White River Valley Electric Cooperative 283 WHPacific, Inc. 284 Willbros Engineers 285 William W. Rutherford & Associates 286 Wyoming Municipal Power Agency 287 Xcel Energy 288 Y-W Electric Association, Inc. 289 Yampa Valley Electric Association, Inc. 290 Zachry Holdings, Inc. TOTAL NUMBER OF MEMBERS: 290



In-house Design and Engineering

Global Engineering Service Provider Energy. Environmental. Transportation. Water.

Full Scale Structure Testing State-of-the-Art Facilities Latest in Hot-Dip Galvanizing

Project Complete.

• • • • • • 800.878.6806

• • •

Feasibility Studies Siting & Permitting Power Plant Design Plant Upgrades & Retrofits Air Quality Control Services Transmission & Distribution Substations & Switchyards Construction Management & Inspection Services Owner’s Engineer

Install it, Align it, Forget it!


Time is


Use E-LAM® NeverTwist® laminated wood switch structures as an economic alternative to round wood or steel poles for all switch applications through 161kV.

your project’s success depends on staying on time and on budget.

• Pre-drilled per switch manufacturer specifications • Will not twist or deep check • Easily modified in the field • Made from “green” abundant renewable timber resource • 6 - 8 week lead times

Leverage the expertise and experience of the Border States Grid Solutions team to procure product for your next project and complete it on time and on budget. Toll-free: 877.273.3323 |

Call for a quote today! 800-949-3526 Laminated Wood Systems, Inc.

10-061 (2014-03)

10-061 (2014-03)

Construction • Industrial • Utility W W W. R MEL .O RG



2014 Calendar of Events January 14, 2014

March 14, 2014

San Antonio Introduction to the Electric Utility Workshop San Antonio, Texas

Distribution Vital Issues Roundtable Lone Tree, CO

January 15, 2014

March 27, 2014

Austin Introduction to the Electric Utility Workshop Austin, Texas

Electric Utility Workforce Management Conference and Roundtable Lone Tree, CO

January 21-22, 2014 Utility Financing for Non-Financial Personnel Workshop Lone Tree, CO

Advanced Substation Design Workshop Lone Tree, CO

February 13-14, 2014

April 23-25, 2014

Distribution Engineers Workshop Lone Tree, CO

Health, Safety and Training Conference Lone Tree, CO

February 21, 2014

April 25, 2014

Safety Roundtable February 2014 Westminster, CO

Safety Roundtable - April 2014 Lone Tree, CO

March 6-7, 2014

May 18-20, 2014

Power Supply Planning and Projects Conference Lone Tree, CO

Spring Management, Engineering and Operations Conference Austin, TX

March 7, 2014

June 12, 2014

Generation Vital Issues Roundtable Lone Tree, CO

NERC Training Conference and Roundtable Lone Tree, CO

March 11-12, 2014

June 26, 2014

Transmission Planning and Operations Conference Lone Tree, CO

Transmission Operations and Maintenance Conference Omaha, NE

March 12, 2014

July 29-30, 2014

Transmission Vital Issues Roundtable Lone Tree, CO

Plant Management,

March 13-14, 2014 Distribution Overhead and Underground Operations and Maintenance Conference Lone Tree, CO


April 10-11, 2014


Engineering and Operations Conference Salt Lake City, UT

July 30, 2014 Generation Vital Issues Roundtable Salt Lake City, UT

August 2014 Safety Roundtable August 2014 Kansas City, MO

September 14-16, 2014 Fall Executive Leadership and Management Convention San Antonio, TX

September 25, 2014 2015 Spring Management, Engineering and Operations Conference Planning Session Lone Tree, CO

October 9, 2014 Asset Management Conference Lone Tree, CO

October 16, 2014 Renewable Planning and Operations Conference Lone Tree, CO

November 6, 2014 Review of Industry Standards for Distribution Workshop Lone Tree, CO

November 14, 2014 Safety Roundtable November 2014 Fort Collins, CO

CONTINUING EDUCATION CERTIFICATES Continuing education certificates awarding Professional Development Hours are provided to attendees at all RMEL education events. Check the event brochure for details on the number of hours offered at each event.

The Design Behind Power for 40 Years Since 1973, Sega Inc. has been a dedicated provider of quality engineering and technical services to the power industry, specializing in areas of: Electrical and Steam Generation Plant Betterment Controls Upgrades Power Delivery Field Services Plant Information Management

Sega Inc.

913-681-2881 • 16041 Foster • Overland Park, KS • 66085

Safety First ... Service Always! For over 60 years Trees, Inc. has been providing professional vegetation management services to cooperative, municipal and investorowned utilities nationwide. We strive to lead the industry in safety, efficiency, reliability and affordability. Give us a call to experience the Trees, Inc. difference for yourself!

Since 1912, we have built the transmission lines, distribution systems and substations that power our nation. This legacy, coupled with an extensive collection of resources, a strong financial backing and industry-leading safety programs provide clients with the expertise and stability they demand. Connecting Power to People for Over a Century.

An MYR Group Company

Trees, Inc.






Advanced Motor Controls AMEC

Inside Front Cover

(972) 579-1460

(770) 810-9698

Black & Veatch Corp.


(913) 458-2000

Border States Electric


(701) 293-5834

Burns & McDonnell


California Turbo, Inc.


(800) 448-1446



(800) 542-8072

DIS-TRAN Packaged Substations, LLC


(318) 448-0274

Empire Electric Association


Fuel Tech


(630) 845-4500

Great Southwestern Construction, Inc.


(303) 688-5816

Harris Group, Inc.


(303) 291-0355

HDR, Inc.


(402) 399-1000

Mitsubishi Hitachi Power Systems


(908) 605-2800

Back Cover

(913) 928-7000

Laminated Wood Systems, Inc.


(402) 643-4708

Lauren Solar


(325) 670-9660

Nebraska Public Power District


(402) 564-8561

POWER Engineers


(208) 788-3456

Sabre Tubular Structures


(817) 852-1700

Sega, Inc.


(913) 681-2881


Inside Back Cover

(303) 696-8446

Southeastern Community College


Stanley Consultants, Inc.


(303) 799-6806

Sturgeon Electric Co. Inc.


(303) 286-8000

T & R Electric Supply Co., Inc.


(800) 843-7994

T & D PowerSkills


Total-Western, Inc.


Trees Inc.


(866) 865-9617

Ulteig Engineers, Inc.


(877) 858-3449

University of Idaho Summit


(208) 885-6265

WESCO Distribution


(303) 217-7500

Young & Franklin


(315) 457-3110

Zachry Holdings, Inc.


(210) 588-5000





Connecting mankind Balancing transmission grids means powering the world Plant-wide Power Transmission Integrated Automation Solutions for Glass & Solar

Various factors are transforming the power transmission business: the drive toward renewable energy, the expansion and interconnection of grid systems, and the need to gradually replace and upgrade aging grid infrastructures. Reliably balancing load and demand is becoming even more important with the increasing share of renewables in the energy mix and the growing importance of distributed generation.

Siemens expertly supports this transformation with power transmission products, solutions, and services designed to contribute to the development of a highperforming and sustainable global transmission infrastructure. Our solutions make it possible to master the complexity of today’s transmission systems, keep them in perfect balance, manage all interfaces, and make power available wherever and whenever it is required.

Powering the Future. An industry innovator, Kiewit Power has extensive experience in the gas-fired, air quality control systems, power delivery, renewable and nuclear markets. Kiewit serves the power industry through a number of its subsidiaries, such as Kiewit Power Constructors Co., Kiewit Power Engineers Co. and TIC-The Industrial Company (TIC). As a full EPC provider, our in-depth market knowledge and industry-leading projects show how Kiewit is committed to clients and to remaining a power pioneer.

Kiewit Power Group Inc. 9401 Renner Boulevard Lenexa, KS 66219 (913) 928-7000

Leader in EPC installations for


RMEL Electric Energy Issue 1 2014  

The official magazine of the RMEL Association. Serving the electric energy industry for over 100 years. -Electricity: The American Way of L...

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