pperspectiveserspectives - eei€¦ · and energy supply jim owen executive director, member...

Dominion’s Tom Farrell:

Troops to Energy JobsNational Template

ELECTRICELECTRICPERSPECTIVESPERSPECTIVES

J U L Y / A U G U S T 2 0 1 3

Transmission Investment Returns

Utility Ratemaking Myths

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J ULY / AUGUST 2 013 • VOLUME 38 , NUMBER 4

FeaturesELECTRICELECTRICPERSPECTIVESPERSPECTIVES

16 10 MythsHaving heard many of them during his four-decade career in the electric power industry, the author compiled his own list of the top-10 myths in utility ratemaking.

B Y B RANKO TERZ IC

20 Veteran PowerThe Troops to Energy Jobs National Template is a

“how-to” guide for energy companies to develop comprehensive programs for military outreach, education, recruiting, and retention.

B Y T HOMAS F. FARRELL I I

30 A Reasonable ReturnThe Federal Energy Regulatory Commission should provide regulatory certainty by continuing to authorize stable returns that are commensurate with the risks inherent in building transmission.

B Y DAV ID K . OWENS

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JULY / AUGUST 2 013 • VOLUME 38 , NUMBER 4

DepartmentsT H E M A G A Z I N E F O R

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ELECTRICELECTRICPERSPECTIVESPERSPECTIVES

On the cover: (L to R): Michelle Washington, a payroll support specialist for Dominion and an Army veteran; Tom Farrell, Dominion chairman, president and CEO; Diana Trammell, an associate communications specialist for Dominion and an Air Force veteran; and Daniel Boch, a nuclear quality specialist III for Dominion and a Navy veteran. (Photo: Dominion) www.eei.orgwww.eei.org/epep

6 Powering Change

A bright energy future.

8 News & Trends

EEI elects new leader-ship…Edison award winners…excellence in supplier diversity…

women executives discuss mentoring re-sponsibility…pop-up museum encourages energy effi ciency…con-solidated storage of

used nuclear fuel…smart grid with a view…utilities take aim at copper theft…and more.

40 Operations

Building a robust nuclear supply chain.

44 Construction

Banner year for new capacity additions.

48 IEE at Work

Innovations across the grid dialogue.

E L E C T R I C P E R S P E C T I V E S

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6 E L E C T R I C P E R S P E C T I V E S

powering change

Among the many highlights of EEI’s Annual Conven-tion in June, the focus on electrifi cation provided ample opportunity for attendees to learn about electricity’s role in transforming our transportation

sector. After hearing the excitement in these discussions, I am now even more enthusiastic about the opportunities

for the electric power industry to build powerful connections through trans-portation electrifi cation.

Driving the Future The industry leaders on our electrifi ca-tion panel presented a compelling case for the bright future of electric trans-portation. Panelists included EEI’s vice chairman Ted Craver, chairman, presi-dent and CEO of Edison International;

Tony Earley, chairman, CEO and president of PG&E Corpora-tion; Kim Greene, president and CEO of Southern Company Services; Alan Perriton, COO of VIA Motors; and Jim Piro, CEO and president of Portland General Electric.

To begin, our customers already are connected: The typi-cal American home has, on average, 25 electric devices—99 percent of which must be plugged in or recharged. Mov-ing to electric vehicles (EVs) is a natural progression and fi ts with consumers’ routine of charging other essentials in their lives.

When consumers begin to consider owning an EV, they quickly learn the great benefi ts that EVs deliver, including convenience, driving experience, and fuel savings. The De-partment of Energy’s new “eGallon” metric makes it easy for consumers to see the cost advantage of fueling with electricity. On average, it costs about three times less to drive an EV than a gas-oline-powered car. And, thanks to new research from EPRI, we also know that EVs are competitive with both conventional and hybrid vehicles in terms of their life-time costs.

In fact, customer satisfaction is so high that many EV drivers talk about the “EV grin” they get from driving these great cars. I could see that enthusiasm in con-vention attendees who were checking out exciting new EVs from Nissan and Ford, plus an extended-range electric truck from VIA with exportable power, and cutting-edge electric motorcycles from Brammo. With these and many other EVs in the market, it is clear that these vehicles strike a responsive chord.

The benefi ts of electrifi cation extend from individuals to businesses, too.

A BRIGHT ENERGY FUTURE

Many businesses, including electric companies, are seeing a positive return on investment from electric fl eet vehicles thanks to lower operating costs. Plus, employees using these vehicles love their quiet and clean operation, which fosters a safer work environment.

Better yet, electric transportation is about more than just cars and trucks. In non-road applications, electricity signifi -cantly improves business operations by reducing fuel costs. For instance, the electrifi cation of diesel-powered equip-ment at ports in Savannah, GA, and Mobile, AL, saved 6.6 million gallons of diesel.

Looking ahead, innovations in battery storage and smart grid technology may create opportunities for vehicle-to-grid programs that aid in grid stability and reliability. The testing of energy storage using EV batteries already is under-way, and is yet another example of our industry’s push to advance technologies that benefi t the grid and society.

Our industry must continue to be a leader in the move-ment to drive electric transportation, by promoting electric fl eets, educating and supporting customers who are inter-ested in electrifi cation, and working with policymakers to encourage policies that advance adoption. Electric trans-portation is a win-win proposition for industry, consumers, business, and the country—and that is the connection to a bright energy future we all want to make. ◆

Brian L. WolffSenior Vice President, Edison Electric Institute

120,000 New Monthly Sales

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20112010 2012 2013

Source: www.hybridcars.com.

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news+trends

Courtesy: Westinghouse

EDISON AWARD WINNERS

American Electric Power, Oklahoma Gas & Electric Company, and AES-SONEL were named the recipients

of the 2013 Edison Award, the elec-tric power industry’s most presti-gious honor, during EEI’s convention in mid-June.

AEP received the Edison Award for the company’s completion and com-mercial operation of the John W. Turk, Jr. Power Plant located in Hempstead County, AR. Starting operations on December 20, 2012, the Turk Plant is the first U.S. power plant to employ an advanced ultra-super-critical steam cycle.

AEP’s Southwestern Electric Power Com-pany (SWEPCO) committed $1.7 bil-lion (the largest capital investment in Arkansas history) to construct the

Turk Plant that now serves as a principal source of baseload electricity for the three-state operating region of Louisiana, Arkansas, and Texas. Through-out the course of the project, AEP surmounted

major siting challenges and crafted solutions and contingency plans to maintain overall progress. The 600-megawatt plant was designed with state-of-the-art emission con-trol technologies, and the ultra-su-percritical steam cycle uses less fuel and produces fewer emissions to create the same amount of power as other pulverized coal-based power plants.

OG&E received the Edison Award for the company’s highly successful

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The Turk Plant is the first U.S. power plant to employ an advanced ultra-super-critical steam cycle.

EEI Elects New Leadership

Michael W. Yackira, president and CEO of NV Energy, was elected chairman of the Edison Electric Institute (EEI) in mid-June. Also elected were three vice chairmen: Theodore F. “Ted” Craver, Jr., chairman, president, and CEO of Edison International; Nicholas K.

“Nick” Akins, president and CEO of American Electric Power; and Thomas A. “Tom” Fanning, chairman, president, and CEO of Southern Company.

“We are delighted to welcome Michael as EEI chairman,” said EEI President Tom Kuhn. “Michael’s industry experience, his focus on communicating the value of electricity, and his drive toward innovation make him the perfect choice to lead EEI as chair during this transformative time for our industry.”

Kuhn also praised the vice chairs who will be supporting Yackira as part of EEI’s leadership team, calling Craver, Akins, and Fanning a “superbly talented trio of executives whose expertise and commitment are recognized throughout the industry.”

Yackira joined NV Energy in January 2003 and was elected CEO effective Au-gust 1, 2007. In February 2007, Yackira was elected president and COO and also to the board of directors. Prior to that, he was corporate executive vice presi-dent and CFO (December 2003 to February 2007) and executive vice president, strategy and policy (January 2003 to December 2003).

He spent more than a decade as an executive with FPL Group, serving in sev-eral positions, including president of FPL Energy; vice president of finance and CFO of FPL Group; and senior vice president of market and regulatory services for Florida Power & Light Company. His experience includes extensive roles in operations, finance, and regulatory matters in other industries.Yackira also is a board member of the Nevada Development Authority and the Council for a Better Nevada; vice chairman of the UNLV Foundation Board of Trustees; and chairman of the Nevada Cancer Institute Foundation. He holds a bachelor of science degree in accounting from Lehman College, City University of New York, and is a certified public accountant.

(L to R): Michael Yackira, president and CEO of NV Energy, is EEI’s new chairman. Also serv-ing on the leadership team are three vice chairmen: Ted Craver, chairman, president, and CEO of Edison International; Nick Akins, president and CEO of American Electric Power; and Tom Fanning, chairman, president, and CEO of Southern Company.

J U LY / A U G U S T 2 013 9

implementation of its innovative SmartHours program.

By using smart grid technology and involving its customers—along with adding wind, new transmission, and demand-side management—OG&E will delay the need to build a new fossil fuel power plant and also reach its 2020 goal of achieving more than 200 megawatts of annual peak-load reduction.

The company installed more than 823,000 smart meters throughout its service area and exceeded its targets by enrolling more than 44,000 custom-ers in its SmartHours program—achieving a collective 72 mega-watts of load reduc-tion on peak-use days. SmartHours is a vol-untary program that offers OG&E customers a free programmable communicating ther-mostat and a vari-able price plan with significantly reduced

off-peak pricing and variable peak pricing during summer months.

Knowing that customers would be an important partner in achiev-ing the 2020 plan goal, OG&E focused on putting them in control of their electricity use. The company com-municated to its customers with a significant educational campaign that allowed them to better under-stand smart energy consumption and how to monitor their energy usage and costs. The result: 99 per-cent of Oklahoma customers in the

program saved, on average, $191 per year on their electricity bills.

AES-SONEL received the Interna-tional Edison Award for the com-pany’s extraordinary investment program in Cameroon, greatly increasing access to electricity, improving system reliability, and providing jobs and social programs. AES-SONEL, an affiliate of global power company AES, entered the Sub Saharan country of Cameroon in 2001 and began investing in the country’s electricity sector in an ef-fort to refurbish and add capacity.

The company’s investment of $1 billion to renew and expand Cam-eroon’s electricity sector between 2001 and 2012 represents the single largest investment in the country over the past 10 years. The improve-ment resulting from the investment plan enabled more than 60,000 new families each year to get electricity for the first time, nearly doubling the number of families in Camer-oon with access to electricity. AES-SONEL’s electricity sector investment also included community-oriented programs focused on job readiness, health, education, environment, and economic development.

OG&E’s SmartHours program offers customers a variable price plan with signifi cantly reduced off-peak pricing.

AEP’s SWEPCO committed $1.7 billion to construct the 600-MW John W. Turk, Jr. Power Plant in Hempstead County, AR.

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Excellence in Supplier Diversity

For the past 30 years, EEI has recognized those elec-tric companies that have demonstrated leadership

in advancing purchasing opportu-nities for minority- and women-owned businesses. These efforts have resulted in more than building goodwill in the community. They

also have led to greater profitability, supply chain competitiveness, gov-ernmental/regulatory compliance, strong customer service, and good corporate citizenship.

At this year’s annual Supplier Di-versity Conference in late May, EEI presented Kansas City Power & Light (KCP&L), a wholly owned subsidiary of Great Plains Energy, with the industry’s 2013 Excellence Award. KCP&L was recognized for its con-sistent, organization-wide commit-ment to encouraging an inclusive procurement system that identifies and develops relationships with di-verse suppliers.

For their creative efforts to promote a diverse supplier base, CenterPoint Energy and Southern Company were named first- and second-place winners, respectively, of the industry’s Innovation Award.

In addition, EEI presented a num-ber of special category supplier diversity awards: Pacesetter Award—Jewel Smith, CenterPoint Energy; Prime Supplier Award—Burns & McDonnell; Vendor Opportunity Award—John Eley, DTE Energy; and Diverse Supplier Award—Richard Hath & Associates.

POP-UP MUSEUM ENCOURAGES ENERGY EFFICIENCY

An outdoor museum of vintage refrigerators popped up recently at Charlotte’s Wells Fargo

Atrium to educate and encourage Duke Energy customers to recycle old, energy-guzzling secondary re-frigerators and freezers.

“Duke Energy is excited to bring this event to the Charlotte com-munity,” said Gayle Lanier, Duke Energy senior vice president and chief customer officer. “Besides nostalgia, these vintage appliances offer a valuable reminder for Duke Energy customers looking for ways to take control of their energy usage and costs.”

WOMEN EXECUTIVES DISCUSS MENTORING RESPONSIBILITY

The turnout for the 6th Annual Women Executives Forum Lunch, which was held in June in conjunction with EEI’s Annual Con-vention, was quite impressive. Nearly 100 women came together to network, motivate, and help lead the energy industry of the

future. EEI’s Chief Administrative Of cer Mary Miller welcomed the attendees, and PNM Resources Chairman, President, and CEO Patricia Vincent-Collawn introduced the featured speakers. During the lunch, jour-nalist and commentator Campbell Brown, Southern Company Services President and CEO Kimberly Greene, and PG&E Executive Vice President of Electric Operations Geisha Williams discussed the important role that women can play as mentors in leadership positions across the industry.

(L to R): PNM Resources Chairman, President, and CEO Patricia Vincent-Collawn; Southern Company Services President and CEO Kimberly Greene; journalist Campbell Brown; and PG&E Executive Vice President of Electric Operations Geisha Williams.

KCP&L’s Supplier Diversity Manager

Valerie Coyazo and Chairman, President, and CEO Terry Bassham accept the 2013 Excellence Award.

J U LY / A U G U S T 2 013 11

The museum highlights the fact that older units can use as much as three times more electricity than newer models built to higher energy-efficiency standards. Duke Energy customers can recycle older, second-ary units by taking part in the com-pany’s appliance recycling program. Customers can save as much as $150 a year in energy costs and receive

Global Shale Resources

Estimated shale oil and shale gas resources in the United States and in 137 shale for-

mations in 41 other countries represent 10 percent of the world’s crude oil and 32 per-cent of the world’s natural gas technically recoverable resources, or those that can be produced using current tech-nology without considering economic pro tability, accord-ing to a recent report released by the Energy Information Ad-ministration.

More than half of the identi ed shale oil resources outside the United States are concentrated in four coun-tries—Russia, China, Argen-tina, and Libya—while more than half of the non-U.S. shale gas resources are concen-trated in ve countries—China, Argentina, Algeria, Canada, and Mexico. The United States would be ranked second after Russia for shale oil resources and fourth after Algeria for shale gas resources if com-pared with the 41 countries assessed.

a $30 incentive for having the old units hauled away.

After pickup, customers’ outdated appliances are transported to a de-manufacturing facility in Charlotte operated by JACO Environmental to be recycled. During the recycling process, JACO converts 95 percent of each appliance into recyclable met-als, glass, and plastics.

CONSOLIDATED STORAGE OF USED NUCLEAR FUEL

Eighty-two per-cent of Ameri-cans living near commercial

nuclear energy facilities believe that the used nuclear fuel assemblies that are the byproduct of electricity generation at nuclear power plants should be consolidated at temporary storage facilities while the De-partment of Energy develops a permanent repository, according to a recent survey con-ducted for the Nuclear Energy Institute. Ninety percent of those who participated in the June survey agree that the

government should de-velop a disposal facility for used nuclear fuel, as long as the site meets the Nuclear Regulatory Commission’s protec-tive requirements.

The survey found that 62 percent of nuclear plant neighbors

have con dence that used nuclear fuel rods are safely stored at re-actor sites. Eighty- ve percent agree that used fuel rods can be trans-ported safely as long as secure containment and proper procedures are used.

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Spent fuel storage pools at Duke Energy’s Harris Nuclear Plant near New Hill, NC.


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RISING COAL EXPORTS

Rising exports of U.S. coal to Europe and Asia added $16.6 billion to the U.S. economy in 2011, making signi cant contributions to America’s

economic recovery and job creation in many industrial sectors, as well as in regions far be-yond the nation’s coal elds.

In a report released recently by the Na-tional Mining Association, Ernst & Young analysts found that the 107 million short tons of American coal exported in 2011 supported 141,270 high-wage jobs paying nearly 50 percent above industry averages. According to the report, “U.S. Coal Exports: National and State Economic Contributions,” an estimated 168,430 jobs were supported by the 125.7 million tons exported in 2012, a record vol-ume. Each million tons of coal exported sup-ported 1,320 jobs, according to the study.

Rising off-shore demand has steadily boosted the share of domestically mined coal sold abroad. From 2000 to 2010, U.S. coal mines exported about 5 percent of total pro-duction on average but have since doubled the export share to average 10 percent of production.

The bene ts have been especially rich for the top exporting states, including Virginia, Louisiana, and Maryland. Particularly valuable for job creation has been the export from Ap-palachian mines of metallurgical coal used in steelmaking, which comprised 65 percent of total coal exports. Average annual income per worker in the coal export market is $96,100.

SMART GRID WITH A VIEW

The future arrived in Oregon in late May with the opening of Portland General Electric’s (PGE’s) new Salem Smart Power Center, an 8,000-square-foot facility in Salem, OR, that offers a unique insider’s view of a working smart

grid demonstration project.Out tted with a large-scale energy storage system, the center

is designed to help PGE test how to store and better integrate vari-able renewable energy sources like solar and wind into the elec-trical grid, along with several other smart technologies as part of its Salem Smart Power Project. The technologies work together to create a highly reliable “micro-grid” that serves about 500 busi-

ness and residential customers in southeast Salem. An onsite visitor center offers educational exhibits about the project and smart grid.

PGE collaborated with Eaton and EnerDel on the $23-million effort that received Department of Energy matching funds as part of the largest regional smart grid demonstration project in the nation—the Paci c Northwest Smart Grid Demonstration Project.

“Together with our project partners and customers, we are dem-onstrating smart grid technologies to help Oregon and the nation learn how to build intelligent energy resources for the future while continuing to deliver long-term value for customers,” said Jim Piro, PGE president and CEO. “We are proud of the collaboration, hard work, and ingenuity that went into this project, and thank our Salem customers who volunteered to participate in this study.”

The PGE project will test energy storage, dispatchable standby generation, remotely operated power line switches, demand re-sponse, renewable energy integration, and transactive control.

To test demand-response technologies, PGE business custom-ers are volunteering to cycle their heating, cooling, and other sys-tems on and off throughout the day or shift their use to off-peak. In addition, residential customers are letting PGE automatically cy-cle their water heaters on and off for brief periods during the day. Dre

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The Salem Smart Power Center, outfi tted with a 5-MW lithium-ion energy storage system, will help PGE test how to store and better integrate renewable energy sources.

J U LY / A U G U S T 2 013 13

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A NEW ENERGY METRIC

The Depart-ment of Energy (DOE) recently released a new

metric, the eGallon, that makes it easy to com-pare the cost of driving an electric vehicle (EV) to a conventional gaso-line-powered car.

To determine the eGallon price, DOE cal-culates how much elec-tricity the most popular EVs would require to travel the same distance as similar vehicles that use gasoline. That amount of electricity is then multiplied by the average cost of electricity. Using data from July, the average eGallon price was $1.14 while a gallon of regular gasoline was three times higher at $3.65.

The eGallon tool on DOE’s website (www.energy.gov/maps/egallon) al-lows consumers to calculate eGallon prices by state or on a national basis. DOE updates the eGallon monthly as the Energy Information Administra-tion reports on electricity and gaso-line prices.

While the eGallon makes it easier

for drivers to estimate average elec-tric and gasoline vehicles’ operating costs, it may actually overestimate the costs EV drivers pay in the real world. In many states, consumers can take advantage of time-of-use rates or special EV rates for off-peak fueling, and this makes driving elec-tric even less expensive.

DO

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Thieves receive relatively little money for the stolen copper but can cause hundreds of thousands of dollars in damage. These crimes also often result in power outages that can be a costly inconvenience to customers. Westar and other electric companies are taking steps to prevent copper thefts, including using copper weld, a material similar to copper but with no scrap value; install-ing camera and alarm technology at substations; increasing security patrols; working with law enforcement on public awareness; and reaching out to scrap dealers to help them better identify stolen materials.

However, alert neighbors are one of the best ways to protect neighborhoods and electric infrastructure. The public is encouraged to be alert to suspicious activity that might include bicycles leaning up against utility poles or electric substation fences, backpacks or duffel bags in or around substations and near poles, and people performing work who do not appear to be utility employees.

For more information about preventing metal thefts and how to identify suspicious activity, visit www.WestarEnergy.com/copper. AEP Ohio also has produced an excellent video that explains why metal theft is such a problem for electric companies (www.aepohio.com/safety/CopperTheftKills.aspx).

AIR CONDITIONERS REDUCE PREMATURE DEATHS

As the heat of summer set-tles upon us, and we take refuge in our air-condi-tioned homes and offices,

it might be time to think about what summer life was like before air con-ditioning: hot and uncomfortable for most people. But it could be deadly for many elderly and sick persons who could not stay cool on extremely hot days. “Very few U.S homes had air conditioning before 1960; by

2004, that figure had climbed to 85 percent,” accord-ing to an article last winter in The Washington Post.

The article highlighted a study conducted jointly by Tulane University, Carn-

egie Mellon University, National Bureau of Economic Research, and MIT that analyzed U.S. heat-related deaths between 1900 and 2004. “The group found that days on which temperatures rose above 90 degrees Fahrenheit accounted for about 600 premature deaths annually between 1960 and 2004, one-sixth as many as would have occurred under pre-1960 conditions,” the article said.

“It’s all due to air condition-ing,” MIT environmental economics professor Michael Greenstone told the newspaper, adding that factors including increased electrification and health-care access did not affect heat-related mortality.

“The likelihood of a premature death on an extremely hot day be-tween 1929 and 1959 was 2.5 per-cent, the academics found, dropping to less than 0.5 percent after 1960,” the article continued. “The [study]…compared days on which tempera-tures exceeded 90 degrees Fahrenheit with days when they ranged between 60 and 69 degrees Fahrenheit.” ◆

The study analyzed U.S. heat-related deaths be-tween 1900 and 2004.

Utilities Take Aim at Copper Theft

Thieves are stealing copper from transmission utility poles in Montgomery County, KS—and across the

country—crimes that could endanger both the criminals and the public. Westar, the local electric company, is asking for the public’s help in stopping metal thefts by remaining vigilant and reporting suspicious activity to local law enforcement.

“Stealing copper from energized equipment is a dangerous game of roulette. Serious injuries and death are a real possibility,” said Mike Willis, manager of operations for Westar. “Even if the thieves escape uninjured, our employees and the public could be put in harm’s way if they encounter equip-ment that is no longer grounded.”

Contacting energized equipment, including power lines, is dangerous. In June, a man was electrocuted in Wichita for allegedly trying to steal copper from a power line.

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BY BRANKO TERZIC

Having heard many of them during his four-decade career in the electric power industry, the author compiled

his own list of the top-10 myths in utility ratemaking.

Thomas Edison’s first electricity rate was a monthly fee for each light bulb installed. This was fine until new uses for electricity were invented such as running an electric motor, heating a tea pot, or powering a radio. Then electricity ratemaking became more compli-

cated with the need to define electricity services in terms of voltage levels, energy use, and reliability factors (firm versus interruptible). The first “rate engineers” struggled to define: What exactly are the ‘electricity services’ provided? What costs and what level of those costs are rea-sonable to be included in the rates paid by customers? The answers to these complex questions are found in a regulatory system that evolved over the past 100 years. Indi-vidual rate orders issued by state regula-tors yesterday and today are built on years of ratemaking decisions and history.

Those in the regulated utility business—managers, regulators, investors, and con-sumer advocates—usually know and understand this system and its nuances

well. The public, the press, and politicians understand it less so. Hence, sometimes, from the outside looking in, utility ratemaking looks murky and difficult to understand. This leads to myths or misconceptions about what is and what is not, often differing greatly from actual ratemaking practice.

The utility gets a guaranteed return.Consider that if this were true then any utility would only need to apply for rates once and from then on the “guaranteed” return on equity (ROE)

would be received by the util-ity. Not true. Utilities report an “achieved” return at the end of each year and that number can be above or below the return “authorized” in the last rate case. No one can guar-antee that energy demand, weather, or expenses will be as estimated when the rates were set. Utilities are not guaranteed a given ROE. They must manage efficiently to increase the chances of earning the ROE they were authorized.

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The ratepayer paid for that asset.While it’s true that revenue from customers is used by the utility to pay for operating ex-penses, invest in its system, service its debt, and earn a return for its shareholders, these payments do not imply that the customers

in any way “own” the utility’s assets. The utility’s customers pay for electric service at rates set by regulators and that’s i t . Customers take service dur-ing the month, the meter is read, and a bill for the month’s service is sent. The power plants, transmis-sion lines, distri-bution system, and al l other assets provid-ing that service must be built and financed by capital in order that the service can be provided. Those assets are financed by debt and equity, and the ensuing service is “paid for” with cash fl ows from rev-enues from customer services. No customer is asked to fund new assets. Customers are required to pay for electricity ser-vices provided by the utility’s assets, including the regulator-approved depreciation expense and return on rate base. To claim otherwise would be the same as an apartment renter claiming that he/she “paid” for and “bought” his/her unit due to paying rent over the years and thus has an ownership interest.

I was on vacation last month so my electric bill should be zero.Electric utilities are required to provide “reli-able and adequate” service—meaning that when the light switch goes on the power will be there. In order for that to happen, the utility

must have perma-nent assets with sufficient capac-ity 24/7 to supply customers’ needs. So even when a customer goes on vacation for a month the elec-tric system is still there and costs

Branko Terzic is executive director of the Deloitte Center for Energy Solutions and a former commissioner of both the Wisconsin Public Service Commission and the Federal Energy Regulatory Commis-sion. The views expressed here are the author’s.

are incurred. Otherwise, this same consumer could call the home mortgage company and say that there will not be a payment made for last month, when he/she was on vacation, since he/she did not use the house. The same claim could be made to the car lessor: “Sorry, the car never left the garage, so I didn’t use it, hence I am not paying this month’s lease.” It is true that if the customer was not home for a month, his/her bill probably will be lower because he/she used less electric-ity, which means less fuel was used (variable cost) to serve him/her. But the fixed costs were still incurred.

Time-of-use rates are a back-door way of raising rates.Electricity production costs (and wholesale electricity prices) vary during the day, with the highest prices usually in late afternoon and early evening when demand is greatest and the lowest prices in the middle of the night when much less power is used. The Public Utility Regulatory Policies Act

of 1978, passed after the first “oil” price shock, directed state regulators and electric utili-ties to review the feasibility of time-of-use (TOU) rates for the purposes of encouraging energy conservation, reducing

demand, and encouraging efficiency. The state regulators all complied with the “review” and some experiments in TOU rates were implemented in the 1980s. Today, the idea reappears in terms of “real-time pricing” to refl ect these costs in retail prices. In reviewing TOU rates then and now regulators were looking at evi-dence as to how the new rates would affect var-ious classes of consumers. For some consum-ers, monthly bills could be higher under TOU rates and for some lower. However, the purpose of the new rates was not, and is not, a targeted increase on any customer class. Rather than paying a blended rate that refl ects the difference in prices during the day, TOU rates allow customers to see the cost of electricity at various times of the day and to vary usage ac-cordingly. In my review of such studies in Wisconsin (while serving as a public service commissioner from 1981 to 1986), consumers as a class were as likely to get a decrease as an increase.

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4THE PURPOSE OF TIME-OF-USE RATES WAS NOT, AND IS NOT, A TARGETED INCREASE ON ANY CUSTOMER CLASS.

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The electric utility is a monopoly so it has no competition or business risk.Electric utilities compete for some uses with other sources of energy (natural gas and fuel oil for home heating; natural gas and propane for cooking; and numerous energy sources

for industrial users). Electric utilities also compete with the option that large and some smaller customers have

to use on-site generation (conventional and renew-able) or combined heat and power systems. In re-structured states, utilities no longer own generat-ing plants. In these states customers can choose among third-party suppli-ers, or they can continue to be supplied by the util-ity, which procures its power through a competi-tive auction in the whole-sale electricity market. There also are the normal

business risks of loss of sales due to economic downturns, structural changes in the economy, weather, and adverse regulatory decisions, which are contrasted with the fixed costs necessary to maintain the system and provide electric-ity on demand. Capital markets price business risk into the returns needed to attract capital to this industry. The risks have gone up and down over the years but have never been, and never will be, zero.

Net metering is a fair way to trade power produced at home for power from the grid.Not necessarily. Net metering refers to a type of incentive program that generally allows customers to receive a credit from the utility for any generation they produce in excess

of their own needs. The concern is that customers using distributed genera-tion (such as roof-top solar panels, microturbines, etc.) under this system may not be paying their full share of

the cost of the electric system, which results in other custom-ers paying more. Every electricity bill pays for two distinct services. First, there is a price for the power itself, includ-ing the costs of assuring that the power is always available. This is often valued in a competitive market. Second, there is the cost of delivering the power to the customer through transmission and distribution facilities that are designed

to deliver power safely and reliably. A customer producing power at his/her home or business uses the delivery and reli-ability systems in a more complex way than other customers because he/she still needs wire systems, reliability services, and generation from the utility while adding complexity by selling power over the system. Yet, under net metering as ap-plied in many locations due to how the rates were designed, the customer avoids paying for these back-up grid reliability and delivery services. Instead, these costs are imposed on the remaining customers. Utilities are not opposed to distrib-uted generation but the playing field must be level so that all customers pay their fair share of the fixed costs so that the reliability of the system can be maintained for all customers. A proper rate design is the key element of fairness.

Nuclear power plants are the most expensive to build so the rates are the highest.The question before a regulator or utility man-agement when it comes to power plants is, “what will be the fully loaded cost of electric-ity produced from that plant?” That cost of

electricity is based on four main cost components: operating and maintenance expense, depreciation, taxes, and return

on investment. The construction cost of the power plant enters the calculation in the form of annual depreciation expense and return on investment. Power plants that have higher capital costs will have higher depreciation rates (if the same economic life is applied) and higher returns (if the

same rate of return is applied). How-ever, other costs, such as the cost of fuel per kilowatt-hour, may be lower. New nuclear power plants may have higher construction costs by unit of installed capacity than alternatives but they also may have much lower fuel costs per unit of output and/or

higher capacity utilization, spreading fixed costs across more units of output. Thus, high capital costs alone do not auto-matically imply high cost of electricity production.

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HIGH CAPITAL COSTS ALONE DO NOT AUTO-MATICALLY IM-PLY HIGH COST OF ELECTRICITY PRODUCTION.

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The electricity industry has been deregulated.The electricity regulatory scheme in the United States is a bit complicated but is ba-sically composed of a combination of state and federal regulation. The Federal Energy Regulatory Commission (FERC) has, under the Federal Power Act, regulated the wholesale sale of electricity and electricity trans-mission charges since 1935. Un-der that law, ev-ery power plant and power broker selling electricity at wholesale, and every wholesale power market in interstate commerce, is regulated

by FERC. No exceptions. FERC regulates wholesale sales in two ways: cost-of-service rates, usually for transmission, or issuance of a market-based pricing certificate, usually for generation. His-torically, the state regulatory agencies, public service commissions, or public

utility commissions regulate the sale of electricity to end-users within their state borders, which includes the cost of the distribution lines and the electricity itself. When certain states required utilities to divest or sell their power plants, called restructuring, the regulation of the generation or elec-tricity component in those states shifted from the state com-missions to FERC. Many of these same states also introduced competition in the retail sale of electricity, which some view as deregulation. The market-based pricing allowed by FERC in the wholesale market is conducted in a context where FERC approves many complex rules to assure that generators are not engaging in behavior that could unfairly affect the markets. All power markets are thus still heavily regulated by FERC.

New electricity demand can be met completely with new wind and solar power, which are free.We can’t meet cus-

tomers’ total power needs with only wind and solar because these technologies produce power that is variable in nature, depending on whether the wind is blowing and/or the sun is shining. Thus, solar and wind are added to the electricity production mix where the systems already have adequate conventional, fossil, nuclear, and hydro-electric capacity. While great

for avoiding greenhouse gas emissions, solar and wind, when used in large amounts, require the construction of new, usu-ally natural gas-fired generating units that can be ramped up and down quickly to respond when the wind stops, the sun sets, or clouds appear. Wind and solar also are not really free. They require expensive facilities, lines, and safety controls; and, in the case of wind, which is usually more prevalent outside of populated areas, expensive transmission lines to transport the electricity generated by wind to customers. To date, wind and solar have made it into the market because they are heavily subsidized through the tax code and through rate policies such as net metering. The cost of solar, in par-ticular, is declining rapidly and is expected to reach “grid parity” soon. For this reason it may be time to wind down some of the subsidies.

I am subsidizing industrial customers who pay a lower rate than I do.Not really, as regulators are gener-ally prohibited from approving rates that are “unjustly discriminatory,” but “just” discrimina-tion is allowed. The fact that a class of customers has a different rate for electricity on a kilowatt-hour basis does not imply, per se, any cross-subsidy. The cost-of-service

ratemaking methodology used by regulators tries to follow a “cost causer is the cost payer” principle. For example, if industrial customers take service off the transmission system they avoid using the dis-tribution system and thus those costs would not be

included in their rates. Consider that most consumers accept that buying in bulk affords a lower per unit price than small purchases. Rates can be different for different levels of elec-tric service if the regulator finds a reason for such a difference and that reason is spelled out in the orders of the regulator.

Moving Beyond the MythsThe electric regulatory system in the United States has evolved over the past 120 years and has been successful in providing the necessary incentives for private investment in the nation’s electricity infrastructure. State and federal regu-lation has successfully balanced the interests of consumers and investors. It’s a complicated, involved, and sometimes obscure process. It does not need to be so. The basic prin-ciples of electric regulation, however, are easy to understand and yet difficult to implement. The myths distract from the real issues of what constitute “reasonable” costs of providing electricity services and how the costs of the complex electric system should be appropriately assigned to various cus-tomer services. There are plenty of issues to analyze, discuss, and decide but these 10 myths should not be among them. ◆

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10ALL POWER MARKETS ARE STILL HEAVILY REGULATED BY FERC.

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The Troops to Energy Jobs National Template is a “how-to” guide for energy companies to develop comprehensive programs for military outreach, education, recruiting, and retention.By Thomas F. Farrell II

Occasionally, an idea comes along that leaves

you wondering, “Why haven’t we always done this?”

The Troops to Energy Jobs National Template that

was unveiled at EEI’s annual convention in June is

one such idea.

The Troops to Energy Jobs program, which began

as a pilot initiative in March 2011 with my company,

Dominion, and fi ve other electric companies (Amer-

ican Electric Power, Arizona Public Service, National

Grid, Pacifi c Gas & Electric Company, and South-

ern Company) along with 15 sponsor companies

and the Center for Energy Workforce Development

(CEWD), is the proverbial win-win effort. Through

the program, dedicated, well-trained, and highly

disciplined servicemen and servicewomen have

a pathway toward stable, well-paying jobs in the

private sector that closely fi t their military skills. At

the same time, Dominion and the rest of the electric

power industry gain access to a much-needed pool

of potential employees who are both skilled and

eager to work.

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This last point is particularly important since upward of 200,000 electric and natural gas utility workers, an estimated one-third of all utility em-ployees, are eligible for retirement over the next few years. As an industry, we simply cannot ignore this issue; we need to meet it head-on and find a means of replacing these valued employees. Tap-ping into the pool of ready and able veterans and soon-to-be veterans will play a crucial role in help-ing the electric power sector build the workforce of tomorrow.

Not only is the Troops to Energy Jobs program a good solution to a pressing problem, but it is also the right one as well, since it will help the industry do its part to address the unacceptably high un-employment level among veterans, especially the younger ones. It is a national disgrace that jobless rates for veterans are often double what they are for the rest of the population—but this is an issue that we in the electric power industry can help solve.

Tom Farrell is chairman, president and CEO of Dominion.

While the industry already has an enviable track record in military recruiting, these efforts previously have been scattered and uncoor-dinated. The goal of the Troops to Energy Jobs pilot program was to develop an effective national model for connecting veterans to rewarding energy careers, and we have done just that. The National Template the industry is rolling out now builds heavily on the lessons we have learned in the past two years.

The overarching lesson driven home by our experi-ences in the two-year pilot is that the program must in-

volve much more than simply recruiting veterans through “want ads” on military and industry job boards. Recruiting is part of the answer, but only part.

Among the specific lessons we learned at Dominion are:

the process of transitioning and training vet-erans needs to begin even before they leave the military;

changes within the utility are needed to make the program work; and

everyone needs to speak the same language.To reach potential military employees, we are

working with the Virginia Employment Commis-sion to have its local area veterans’ representa-tives serve as career coaches for the Troops to Energy Jobs program.

Beyond this, we have reached out to edu-cational and veterans-support organizations throughout the state to let them know that Do-minion is ready, willing, and able to hire qualified employees with military backgrounds. We also have refined our planning and recruiting efforts to target specific military occupations. These

DominionDominion

efforts are designed to function as something like a reverse boot camp for veterans—just as their military boot camp prepared them for life in the service. These initiatives, if undertaken by the in-dustry on a large scale, can ready veterans for jobs in the private sector.

Reaching potential military hires requires a dif-ferent approach, one that is adaptable and mili-tary-friendly. As we have learned at Dominion, this is particularly true after bringing vets on board—the corporate culture must change to provide these deserving new hires the resources they need to make their transition from military to civilian life a success. If veteran employment is a priority, the corporate culture must back it up; electric compa-nies must remove the barriers and open up the em-ployment pipeline. Hiring and retaining military veterans really is a two-way street—it takes work on the company side, as well as from prospective employees.

As part of creating this military-friendly corpo-rate culture, Dominion has established a mentor-ing program to ensure that new military hires get the support they need once on board. Mentors must have both prior military experience and ten-ure at the company, as well as knowledge of its various business units. Perhaps most important, mentors need the ability to listen and the willing-ness to work with the new employee for at least a year. The program should smooth over many of the bumps associated with transitioning from military service to the civilian workforce and help these in-coming employees with military backgrounds find the right fit at the company.

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Another key component of this new cor-porate culture is understanding that we don’t speak the same language. While a veteran may have all the skills needed to transition imme-diately into a utility lineworker’s job, his/her credentials will be in military jargon not utility lingo. This makes it a challenge for veterans—and company executives need to realize this includes not just new vets, but older service veterans, as well as members of the National Guard and the military reserves—to translate their skills to the commercial sector and find the right job fit.

To make sure that veterans can secure the credentials they need at the lowest cost and with the least time, Dominion has teamed up with the Virginia Energy Workforce Consortium (which includes the Virginia community col-lege system) to match the military training vets have received with the credentials they need to get good-paying energy sector jobs in Virginia. This approach could serve as a model for the industry as a whole, and electric companies nationwide can help speed the transition by working with policymakers in the states they serve to encourage their community college systems to be flexible about granting credit to veterans for prior learning.

J U LY / A U G U S T 2 013 23


The two-year-long pilot program created a road-map for veterans interested in energy-sector jobs, and electric companies interested in hiring them. The next phase involves rolling out the National Template that can be used throughout the industry to strengthen military outreach, education, recruit-ing, and retention.

The National Template has four basic elements that can be used by companies either in building a Troops to Energy Jobs program from scratch or strengthening an existing military-hiring initiative:1. Preparing—evaluating where your company is now, what your company hopes to accomplish, and how you will get from here to there. This stra-tegic planning gives the corporation a roadmap comparable to the one developed for use by vets beginning their utility job search.2. Building—putting the corporate infrastructure in place to make the program a success and under-standing that the endeavor involves much more than simply recruiting and hiring. In particular it is vital that outreach support services for veterans, new-hire on-boarding and transition initiatives, and retention efforts targeted to current employees be incorporated into the program for it to succeed.3. Implementing—supporting the program and interested veterans during each step of the process, from initial exploration, to required education and certification, and then recruiting, hiring, and reten-tion. 4. Measuring—a two-step process. The first step is to examine whether the program has been built and implemented. Is the necessary infrastructure in place and, if not, what else needs to be done? The second step involves looking specifically at the company’s success in hiring and retaining military veterans. Is the program working? How many vet-erans have been hired? Are they still working at the company? And so on.

The National Template, which is available online at www.cewd.org, includes a host of toolkits, readi-ness checklists, implementation ideas, and other resources for electric companies across the indus-try to use in developing their own Troops to Energy

Jobs initiatives. The template also was designed to coordinate with a comparable roadmap created for use by men and women in the military who are be-ginning their search for post-service employment.

As you look through these resources you will see that there are plenty of steps involved in establish-ing a Troops to Energy Jobs initiative, but the high-level goals are straightforward:

make it easier for veterans to find jobs in the industry and to translate their military skills and training to the civilian sector;

reduce the time it takes to earn required creden-tials or degrees;

provide full value for training and experience garnered in the military;

create a military-friendly environment within the industry; and

increase the number of veterans who are recruited, hired, and retained.

We must do better by our servicemen and women who volunteered to defend our country at such great risk and personal sacrifice. There is no better way to honor our nation’s returning veterans than by providing them with the tools they need to transition successfully to civilian life.

I am confident the Troops to Energy Jobs pro-gram can make a significant difference in the lives of unemployed veterans and those about to leave active duty. We are helping disciplined, civic-minded, and safety-conscious individuals trade their fatigues and combat helmets for flame-retar-dant pants and hard hats. The program also can help our companies address a strategic workforce challenge. In other words, it is a win for all of us, and I encourage you to lend your support to the program.

4

There is no better way to honor our nation’s returning veterans than by providing them with the tools they need to transition successfully to civilian life.

“Hiring and retaining veterans require changes by the utility companies,” says Tony Earley, chairman, CEO, and president of PG&E Corporation. “We created our Power Pathway program to make sure Pacifi c Gas & Electric was doing all it could to meet the needs of incoming veteran hires. One key component of this PG&E program is veterans-only classes dedicated to ensuring that these former military men and women have the skills and support they need to succeed at the utility.

“We have graduated 160 veterans from these internal programs thus far, and 70 percent of them have nailed down jobs either with PG&E or another utility,” adds Earley. “Overall, the company is looking to increase its veteran hiring by 10 percent this year, and we are confi dent we will be able to meet that goal. We think that the Troops to Energy Jobs program is a great way to be able to help expand the number of veterans in our work force.”

J U LY / A U G U S T 2 013 25

“Veterans are an excellent fi t for the kind of work we do in our industry,” says Nick Akins, president and CEO of American Electric Power. “The experience that veterans gain in the fi eld requires discipline, dedication to their work, and leadership skills. Utilities need exactly the same skills and the Troops to Energy Jobs initiative is a natural fi t.

“To support our veteran employees, we felt it was important to create a military vet-erans employee resource group,” Akins continues. “To help the employees within the group, you not only have the connections with jobs, but you also create connections among employees who have similar life experiences and backgrounds. You can’t beat that when you want to encourage very positive individuals to join and succeed as part of your company.”

“We have found that many military veterans are immediately able to take on a very important role with the company,” notes Tom Fanning, chairman, president and CEO of Southern Company. “There are four areas where Southern sees particular overlap between veterans’ military experience and the industry’s needs: lineworkers, plant operators, security operations, and information technology.

“The Troops to Energy Jobs program is an effective model for identifying and attract-ing outstanding talent for careers in the utility industry,” Fanning continues. “It’s a model that all of the companies in our industry should adopt.”

To that end, Southern Company annually participates in more than 30 military recruitment events and employs a dedicated military recruiting strategist to support military hiring.

frequently have trouble coping with the different pace of work when they join the corporate sector after having served in the military. As a rule, things happen much quicker in the military—particularly for troops on active duty—than they do in the civil-ian sector.

Companies need to be aware of this potential issue, as do vets, he says. But for companies such as AEP or industries such as the electric and natural gas industries that are in growth mode, the ability of veterans to think critically and solve problems is a perfect match.

“Companies like AEP need people who can solve problems,” says Stinnett. “The industry needs people who can think outside of the box, who can think on their feet. Vets can do that and more.”

One natural fi t for vets in the utility industry is in the security arena. Michael Hart, a former military police offi cer in the Army, now serves as a nuclear security offi cer for APS. “When you fi rst get home it hits hard that you don’t have a job, but the match with APS was perfect,” Hart says. “The skills that I developed in Iraq will support my family for the long run.”

“The Troops to Energy Jobs initiative is a pre-mier program from both the veteran’s perspective and the industry’s,” says Linda Sykes, a military recruiting strategist at Southern Company who

It is vital for both sides of the hiring equation to understand just how similar many of the jobs in the electric power industry are to those in the mili-tary sector. As Matt Kellam, supervisor of staffi ng strategy at Dominion and a veteran of the Marine Corps reserves points out, for example: “Power sta-tions are like submarines or ships that don’t move.”

It also is essential for utilities to understand the intangibles that veterans acquire during their service in the military, says Kellam, citing safety consciousness, work ethic, character, and integrity. These are traits that translate anywhere and need to be factored into the hiring equation.

Fred Kuebler, a U.S. Navy vet who is now direc-tor of U.S. media relations at National Grid, makes a similar point. “The military is very process-ori-ented, very service-oriented, and these attributes translate very well into the utility industry,” he says. “Working in the utility industry gives veter-ans the opportunity to continue to serve—you are just serving in a different way.” These similarities in service and in process made the transition a relatively easy one for him, he continues, adding that the things you learn how to do in the military really translate quite nicely into the utility industry.

“Missions change,” echoes Dominion’s Kellam, “but warriors don’t. When you hire a vet you are getting a warrior that brings his or her best to work every day.”

Getting a warrior is not without its challenges, however, adds Matthew Stinnett, manager of transmission contracts and outsource engineer-ing for AEP. Stinnett, also a contracting offi cer for the Army National Guard, notes that veterans


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J U LY / A U G U S T 2 013 27

served previously in the Marine Corps as a recruit-ing instructor and maintenance mechanic. “The veterans that companies will be looking to hire through this program are genuinely interested in the industry and willing to do the work needed to get hired. The program will be a great resource for any company looking to tap into the pool of avail-able veterans,” she adds.

One key to making the program a success, veter-ans emphasize, is the establishment of an effective mentoring program—both for new hires and exist-ing veteran employees.

Julia Wong, a Marine veteran who is now an electrical maintenance coordinator at PG&E, stresses the importance of the company’s mentor-ing program. Her mentor, she points out, helped her transition from her initial position at the utility to her current one. Wong says that her mentor, also a former Marine, helped her to relearn how to use her military leadership skills in the civilian sector, benefi tting both herself and PG&E.

Joe Sayles, a Navy vet who is now a system protection technician at Do-minion, makes a similar point about the importance of mentoring programs. Having supervisors and coworkers look-ing out for you and helping you make the transition much easier, he said. They know where you’ve been in the mili-tary and what you have done, and that makes all the difference.

“It makes you feel good that you have a team that supports you, that knows what you’ve done in the military, and what you’ve done for the company thus far,” he concludes.

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“It is important to note that even without the benefi t of the new Troops to Energy Jobs National Template, utilities have long had a strong interest in hiring military veterans,” adds Edison Electric Institute president Tom Kuhn. “This year, for example, nine EEI member companies are on GI Jobs’ 2013 list of top military-friendly employers.

“When the pilot program was launched, the participants initially thought the focus would be on recruiting,” Kuhn continues. “But what we have learned since then is that Troops to Energy Jobs is about so much more than just recruiting. It is about providing support for veterans all the way through their transition from the front lines to the power lines.”

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Dominion


“National Grid’s support for the program was a natural,” says Tom King, president, National Grid U.S. “Veterans are a well-trained workforce that can help the industry develop the future. The Troops to Energy Jobs pro-gram just makes sense.”

King emphasizes that veterans have skills that transfer seamlessly to the utility industry. “Veterans can take their military skills into civilian control rooms and out on the line and bring value to the company immediately,” he continues. “The community-oriented nature of the utility industry also provides the sense of service for which so many veterans are looking. It is a nice fi t, and National Grid is proud to be a part of this program.”

“We are proud to be one of the original six pilot participants,” says Donald Brandt, chairman, president and CEO of Pinnacle West and Arizona Public Service. “The program has been a huge success at APS. Our experience with hiring veterans here at APS has taught us that no one trains better than the U.S. military.

“The business case for the program is without question—veterans are highly trained, disci-plined, and make out-standing employees,” Brandt concludes. “It’s also good for the country. These men and women deserve an opportunity for employment.”

Not only is the Troops to Energy Jobs program a good solution to a pressing problem, but it is also the right one as well.

To learn more about Troops to Energy Jobs, please contact Ann Randazzo at 703-237-7927 or [email protected].

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to safely and securely meet the needs of a 21st-century digital to safely and securely meet the needs of a 21st-century digital economy, among others. Yet today transmission remains the economy, among others. Yet today transmission remains the smallest portion of an electric customer’s bill. On average, smallest portion of an electric customer’s bill. On average, transmission costs are approximately 11 percent of the price transmission costs are approximately 11 percent of the price of electricity when compared to generation and distribution of electricity when compared to generation and distribution costs. (See Figure 1.)costs. (See Figure 1.)

30 E L E C T R I C P E R S P E C T I V E SE L E C T R I C P E R S P E C T I V E S

J U LY / A U G U S T 2 013 31J U LY / A U G U S T 2 013J U LY / A U G U S T 2 013 31Bigstock, Fotolia


The nation’s shareholder-owned ele-tric utilities have been investing in transmission to make the benefi ts of a 21st-century grid a reality. Since 2001, Edison Electric Institute (EEI) members’ year-over-year transmission investment has nearly doubled from $5.8 billion in 2001 to $11.1 billion in 2011. Looking ahead, these utilities are projected to spend an additional $54.6 billion on transmission infrastructure through 2015.

These investment dollars already are providing cost savings and other benefi ts for electric utilities and their customers around the country:

Investments made by transmission owners in ISO-New England have re-sulted in annual savings of approxi-mately $700 million in reduced energy and capacity market costs for electric customers.

In PJM, the Trans-Allegheny Inter-state Line (TrAIL) project that entered service in 2010 resulted in a 50-per-cent reduction of congestion costs and saved customers millions of dollars during 2010 and 2011.

In the MISO region, the Multi-Value Projects (MVPs) portfolio is expected to create thousands of jobs and provide additional energy-cost savings. Spe-

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F I G U R E 1

MAJOR COMPONENTS OF U.S. AVERAGE ELECTRICITY PRICE (2011)

Transmission 11%

Distribution 31% Generation 58%

due to a transmission issue starting on August 14, 2003, an estimated 50 million people in the Midwest and northeast United States and Ontario, Canada, experienced an area-wide blackout lasting up to four days in some areas. Total estimates of business and other losses for this event ranged from $4 billion to $10 billion for the outage periods.

However, with interest rates at his-toric lows, many electric utilities are at risk of getting squeezed by federal regulators on their returns on equity (ROEs) for transmission investment. In view of the low interest rates, some have requested a narrow, mechanistic application of the discounted cash fl ow (DCF), the Federal Energy Regulatory Commission’s (FERC’s) preferred fi nan-cial model for determining authorized returns. This narrow application can produce ROE results that, under current economic and fi nancial conditions, are downward-biased and insuffi cient to meet legal and regulatory standards.

In its new white paper, “Transmis-sion Investment—Adequate Returns and Regulatory Certainty Are Key,” EEI argues for a reasonable and practical solution to a strict application of these challenges. In the past, FERC, like many

It is critical now that FERC reaf rm its commitment to transmission investment by mak-ing necessary adjustments in its approach to setting a just and reason-able ROE for trans-mission investment.

cifi cally, MISO estimates that the 2011 portfolio of 11 transmission projects will provide benefits between $15.6 and $49.3 billion, approximately 1.8 to 3.0 times the projected capital costs of $5.2 billion.

Investing in transmission infra-structure also provides grid resiliency, which helps to avoid major electric-ity blackouts that can result in signif-icant economic losses. For example,

J U LY / A U G U S T 2 013 33

other regulatory commissions, has adjusted its regulatory methodologies to refl ect changes in economic and fi -nancial realities to ensure that ROEs remain within the range of reasonable-ness. It is critical now that FERC reaf-fi rm its commitment to transmission investment by making necessary ad-justments in its approach to setting a just and reasonable ROE for transmis-sion investment.

Transmission Investment Needs GrowRecent statements and actions by gov-ernmental and regulatory bodies make clear that the public policy benefits of transmission investment are with-out dispute, and the need for greater transmission investments is clear. For example, with the issuance of its Or-der No. 1000 in 2011, FERC stated that “[t]he need for additional transmis-sion facilities is being driven, in large part, by changes in generation mix.” In January 2011, the fi ve sitting FERC commissioners also endorsed the need for transmission investment in a letter to the editor of The Wall Street Jour-nal, disputing an editorial critical of FERC’s proposed rule covering trans-

mission planning and cost allocation. The commissioners stated “investment in transmission promotes efficient and competitive electricity markets, which hold down prices for consum-ers. Transmission investment also en-hances reliability and allows access to new energy resources.”

In addition, the Environmental Pro-tection Agency is promulgating and implementing evolving regulations that are driving signifi cant generation retirements in some regions. Managing these generation retirements will in-crease the need for new and upgraded transmission assets. For example, PJM recently approved more than $5 billion of transmission enhancements driven by power plant retirements, generation projects switching to natural gas, and the growth of wind power projects.

Moreover, transmission develop-ment to integrate and support renew-able energy resources remains critical, especially those remotely located re-sources that need access to the market and load centers. As noted in a recent report, the American Wind Energy Association highlighted that “trans-mission is ‘extremely important’ to

Since 2001, Edison Electric Institute members’ year-over-year transmission investment has nearly doubled from $5.8 billion in 2001 to $11.1 billion in 2011.

Southern California Edison


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the future of the wind industry in the United States, and, as noted previously, is the ‘industry’s number one barrier’ to integrating more wind energy.”

Meanwhile, the North American Electric Reliability Corporation and FERC continue to develop and approve a growing list of mandatory standards aimed at ensuring Bulk Power System reliability, requiring incremental capi-tal investments for all utilities that own transmission. In addition, the cyber and physical security needs of the na-tion’s critical infrastructure, including the electric grid, also require increased attention and investment.

Financial Model Raises ConcernsFor many years, and continuing through the current period of artifi-cially low record interest rates, FERC has relied upon the DCF financial model to determine utility cost of equity for transmission. But that model has not been adjusted to refl ect the fundamen-

tal shift between the cost of debt and equity that has occurred during the current slow economic recovery.

As currently applied by the commis-sion, the DCF methodology may result in transmission ROEs that are below currently authorized state ROEs, as sev-eral parties advocate. In some cases, these differences may amount to 200 or more basis points. For example, EEI data show that the average state-approved ROE in 2012 was 10.15 per-cent, which—even being at the lowest level in decades—is signifi cantly above levels of ROE proposed by these ad-vocates in cases pending before FERC, or is currently applied as a result of initial FERC orders (such as FERC ini-tial actions in PG&E and PNM case fi l-ings requiring use of median ROE that dropped ROE below 9.00 percent for both utilities).

Rational markets would not pro-duce such signifi cant and abrupt ad-justments to existing ROEs; if anything,

Due to concerns with continued nar-row application of FERC’s preferred nancial model, timely development of needed trans-mission may be impeded.

J U LY / A U G U S T 2 013 35

such irregular results should signal that the commission must reexamine its application of the DCF model and recognize that the model is not work-ing in the current environment.

Due to concerns with continued narrow application of FERC’s preferred fi nancial model, timely development of needed transmission may be im-peded. With supportive FERC policies in place since the Energy Policy Act of 2005, the industry is moving forward to devote even more capital to building transmission. EEI’s 2013 “Transmission Projects: At A Glance” report highlights more than 150 planned transmission projects, totaling approximately $51.1 billion planned through 2023. Impor-tantly, these projects do not include investments in transmission upgrades or replacements to existing facilities. (See Figure 2.)

Although the industry’s proposed transmission investment numbers are signifi cant, The Brattle Group es-

timates that the need for additional transmission investment through 2030 is in the range of $240 billion to $320 billion. The industry’s continued high levels of transmission investment, however, are now at risk. Adequate long-term returns are important to sustaining long-term investment in the transmission system in support of FERC’s policy goals.

Still a Risky BusinessFERC’s DCF model also does not recog-nize that the risks involved in build-ing transmission have not diminished. Compared to other assets, transmis-sion investments are extremely risky and require long lead times for the planning process and stakeholder in-volvement.

Prior to construction, for example, transmission projects generally are evaluated using a commission-ap-proved transmission planning process, which rigorously evaluates the costs

and benefi ts of each project, assesses the forecasted changes in regional supply and demand, and consid-ers alternative solutions such as new generation or demand-side energy-effi ciency measures. Once projects are selected, they still are subject to ad-ditional evaluations as part of federal agency and state commission reviews and siting processes.

In some jurisdictions, projects also are subject to additional reviews in subsequent planning cycles and may be delayed, scaled back, or cancelled. In addition, there is a wide disparity in how different planning processes evaluate the benefi ts of transmission, with some jurisdictions evaluating a significant number of the benefits while others rely mainly on reliability or narrowly defi ned analyses. However, these reviews and benefit analyses contribute to the riskiness of develop-ing effi cient transmission projects.

Since multiple federal, state, and lo-

F I G U R E 2

ACTUAL AND PLANNED TRANSMISSION INVESTMENT BY SHAREHOLDER-OWNED ELECTRIC UTILITIES (2001-2015)

p = preliminaryNote: The Handy-Whitman Index of Public Utility Construction Costs used to adjust actual investment for infl ation from year to year. Forecasted investment data are adjusted for infl ation using the GDP Defl ator. *Planned total industry expenditures are preliminary and estimated from 85% response rate to EEI’s Electric Transmission Capital Budget & Forecast Survey. Actual expenditures from EEI’s Annual Property & Plant Capital Investment Survey and from the FERC Form 1 reports.Source: Edison Electric Institute, Business Information Group

($ Millions [Real $2011])

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2015p2014p2013p2012p20112010200920082007200620052004200320022001

Actual Planned*

5,821 5,9666,514 6,585

8,627 8,876

10,314 10,680 11,070

13,075

13,973

7,822

9,460

15,152

12,424


cal government agencies often are in-volved in right-of-way authorizations and related environmental permitting, the lack of inter-agency coordination forms another obstacle to permitting and siting. The challenge of locating lines across states and across federal lands, coupled with targeted, strong opposition from a variety of public in-terest groups, make the process even more daunting. Rerouting lines occurs with regularity, which increases con-struction costs.

Southern California Edison’s Devers-Colorado River (DCR) transmission line project illustrates the signifi cant chal-lenges that utilities face in developing transmission. The DCR project includes the construction of new 110-mile and 42-mile 500-kilovolt (KV) transmission lines and a new 500-KV switchyard to facilitate, primarily, the development of renewable generation resources.

The project originally was estimated to cost $545.3 million; however, this es-timate has increased to $701.3 million. A wide variety of factors contributed to the cost increases, including extensive environmental measures; the costs of preparing permits; requests for vari-ances and determinations of National

Environmental Policy Act adequacy; and project refi nement reports.

Federal agencies have agreed to co-ordinate permitting efforts on federal lands, and a Department of Energy-led Rapid Response Team for Transmission has engaged in an effort to streamline the federal approvals for seven large-scale transmission projects. Yet, these efforts have not been implemented broadly to expedite permitting on fed-eral lands. Moreover, depending on the location, there may be demands to place transmission underground, which can increase cost and construc-tion times dramatically. This, when coupled with other challenges such as political opposition, exacerbates the already long lead times for developing transmission and adds another layer of fi nancial risk.

There are additional fi nancial risks. For example, EEI members invested $90.5 billion in generation, transmis-sion, and distribution systems in 2012 and are projected to invest approxi-mately $85 billion annually through 2015 with the expectation of retain-ing currently existing ROEs. However, industry free cash fl ow, or internally generated cash flows less capital in-

Transmission investments are unlike investments in any other utility infrastructure where the projects tend to be smaller in size, shorter in duration, and located in one area.

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J U LY / A U G U S T 2 013 37

($ Billions) 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Net Cash Provided by Operating Activities 42.1 55.4 56.3 57.0 58.1 50.2 69.4 61.1 61.3 82.9 77.7 84.4 84.2

Capital Expenditures (47.7) (57.2) (49.0) (43.0) (41.1) (48.4) (59.9) (74.1) (82.8) (77.6) (74.2) (78.6) (90.5)

Dividends Paid to Common Shareholders (14.6) (13.1) (13.4) (12.3) (13.2) (15.1) (16.1) (15.4) (16.5) (17.1) (18.0) (19.3) (20.5)

Free Cash Flow (19.9) (14.8) (6.0) 1.7 3.8 (13.2) (6.6) (28.4) (38.0) (11.8) (14.4) (13.5) (26.7)

TA B L E 1

INDUSTRY FREE CASH FLOW (2000-2012)

Note: Totals may not equal sum of components due to rounding. Source: SNL Financial and EEI Finance Department

vestments before fi nancing, has been negative since 2005, given the high de-velopment costs and long lead times inherent in building transmission. (See Table 1.) This requires utilities to access the equity and debt markets to fund investments. Furthermore, transmis-sion assets generate low levels of cash fl ows for reinvestment, since a primary source of cash fl ows from utility assets is depreciation, and many transmis-sion assets are at the end of their de-preciable lives.

These fi nancial challenges put pres-sure on a utility’s fi nancial metrics that are used to determine interest rates and terms for accessing needed capital. As a result, they may limit the utility’s ability to access capital on favorable terms. This potentially can drive up a utility’s borrowing costs or limit a util-ity’s overall capital expenditures. Since the cost of accessing capital ultimately is borne by customers, it is clearly in everyone’s interest that this outcome be avoided. These challenges are sig-nifi cant when viewed in the context of planned capital expenditures.

In summary, given these risks, transmission investments are unlike investments in any other utility infra-structure where the projects tend to be smaller in size, shorter in duration, and located in one area.

Competing for CapitalTransmission projects also must com-pete with other infrastructure projects for capital. For example, the American Petroleum Institute projects oil and natural gas industry investments of $5 trillion through 2035. And a 2012 study on drinking-water infrastructure

needs estimates that the most urgent investments could be spread over 25 years at a cost of approximately $1 tril-lion. A review of FERC’s historical de-cisions indicates that, in 2011, FERC’s approved ROEs for natural gas pipelines were 264 basis points higher, on av-erage, than those of electric utilities. ROEs proposed by complainants and FERC staff in current section 206 fi lings before the commission would imply a dramatic and unwarranted increase in this differential between electric utility and gas pipeline ROEs.

If returns on transmission infra-structure are not sufficient and sta-ble, sophisticated investors will avoid such investments and instead will seek better and more stable returns else-where. Apart from other investment opportunities in the energy industry, capital markets offer a wide variety of comparable risk alternatives in other sectors of the economy that compete with transmission investments for in-vestors’ scarce capital. As a result, there will be signifi cant competing demands for capital and fi nancing.

Principles for Determining Adequate and Stable ROEsGiven the numerous risks and chal-lenges associated with developing large-scale transmission, it is critical that FERC take the opportunity to con-sider the practical and necessary ad-justments to its DCF methodology, as well as the insight offered by alterna-tive approaches and the competition for capital. Rather than sending unin-tended investment signals with sharp downward adjustments to utilities’ ROEs, EEI recommends that the com-

mission adopt the following principles to ensure that adequate and stable ROEs are maintained:

To provide a more stable regulatory framework for investment, requests to lower existing returns should be re-quired to demonstrate that these returns fall outside of the range of reasonable-ness. Under Section 206 of the Federal Power Act, parties requesting revi-sions to existing utility rates bear the burden of demonstrating that exist-ing rates are not just and reasonable before FERC may consider whether a new rate should be established. Ac-cordingly, these parties must meet this initial burden of proof: Specifically, they must show that the existing ROE falls outside of the statutory range of reasonableness in determining an ROE using the FERC-preferred DCF method-ology. This range of reasonableness is bound by a low-end ROE calculation and a high-end ROE calculation, which result from the DCF fi nancial model. The evaluation of whether an existing rate can be considered to be unjust and unreasonable should continue if, and only if, the complainant demonstrates the existing rate falls outside of this range of reasonableness. Without this standard, there is no real measure as to whether an existing rate is just and rea-sonable and calls into question every previously authorized return, depend-ing on market conditions.

Rigid application of FERC’s analyti-cal method of determining ROEs should not be allowed to undermine its policy objectives and hinder needed transmis-sion investment. While FERC has relied solely on the results of a specifi c ap-plication of the DCF model to determine


ROEs for electric transmission opera-tions, dependence on a single, me-chanical approach heightens the risk that the evidence considered by the commission will not reflect realities in the capital markets accurately. The DCF methodology is a useful tool in es-timating investors’ requirements, but there is no “perfect” method to calcu-late a fair and reasonable ROE. Volatile and anomalous capital market condi-tions further increase the risks that a single, formulaic DCF application alone will not produce a just and reasonable ROE, particularly when those capital market conditions are the result of ab-normal intervention.

There is considerable evidence that current financial market conditions spurred by the Federal Reserve’s mon-etary policy in response to the 2008 recession have seriously undermined the commission’s ability to rely on its DCF approach as the sole determinant of a just and reasonable ROE. The re-sults of FERC’s DCF analysis, as it has evolved, can vary dramatically de-pending on:

whether the key metric of central ten-dency is the median or the midpoint;

the makeup of the proxy group; and the criteria used to eliminate outliers.

Even when there is general agree-ment on these parameters, the DCF model can produce results that are not suffi cient to support transmission in-vestments and can undermine FERC’s policy objectives. Legal precedent and the rule of reason support the commis-sion’s careful consideration of current financial market conditions and the results of alternative methods. FERC should exercise fl exibility, within or as an adjunct to, its existing DCF meth-odology, to account for the extraordi-nary fi nancial environment now extant (such as continuing Federal Reserve actions to stimulate the economy by keeping interest rates low, purchasing bonds, etc.) and ensure that ROEs are suffi cient to support needed transmis-sion investment.

The commission must recognize limi-tations of the DCF methodology and ad-just implementation. Today’s economic and financial conditions contribute to inconsistent results in DCF analysis as it currently is applied. Further, DCF proxy group result screens and other implementation aspects of the meth-odology that have been put into place over time have biased the DCF model to produce lower results in the current interest rate environment, which do not refl ect fi nancial market conditions in the future.

Enhancements and RecommendationsSince investors’ required equity risk premium has expanded under current economic conditions, EEI recommends enhancements to provide the com-mission flexibility to accommodate shifts in capital market conditions, to ensure that its public policy goals are achieved, and to ensure that utili-ties can continue to make the level of transmission investment needed. FERC should make these practical adjust-ments to its ROE methodology imme-diately to better align it with current market conditions and facilitate rea-sonable returns. Furthermore, these changes have the benefi t of being rela-tively simple and straightforward and, therefore, should not require a signifi -cant overhaul of the DCF methodology.

EEI recommends enhancements to provide the com-mission exibility to accommodate shifts in capital market conditions, to ensure that its public policy goals are achieved, and to ensure that utilities can continue to make the level of transmission invest-ment needed.


EEI, along with several economic and financial experts in individual FERC proceedings, supports the follow-ing recommendations:

Consider the results of alternative approaches, such as the risk premium method and the capital asset pricing model. In addition, consider the results of the current DCF analysis performed on a proxy group of companies from other capital-intensive industries or low-risk firms from the competitive sector. Electric utilities do not compete just with other electric utilities for cap-ital; they also compete with companies from other sectors of the economy. The results of these alternative analyses may be used as benchmarks in evalu-ating a fair ROE from within the range of reasonableness established by the DCF method applied to electric utili-ties. This will allow FERC to better set base ROEs in the current environment to offset distortion of the DCF analysis. In parallel, allow fl exibility to set ROEs in the upper end of the range of rea-sonableness based on benchmarking results.

Increase the screen for low estimates in a proxy group to be higher, such as 200-300 basis points above the prevail-ing long-term utility bond yield; and/or incorporate projected bond yields and then apply the currently applica-ble 100-basis-point threshold.

Recognize that low and high DCF val-ues are independent estimates, and the fact that one is considered to be an outlier does not compromise the remaining estimate, as the two meth-ods are independent of each other. FERC should discontinue its policy of removing both results for a company from the proxy group if only one DCF estimate is identifi ed to be excluded.

There should be a shorter period of time for excluding companies with a recent dividend cut. FERC’s practice of a multi-year exclusion of these compa-nies is unreasonable, especially in in-stances where the cut was related to an external one-time event (such as storm restoration). The DCF is a forward-look-ing model relying on data that is cur-rent, using data that is no more than six months old, and forecasted growth

J U LY / A U G U S T 2 013 39

W ith previously authorized

transmission ROEs being challenged and others coming under review in pending rate proceed-ings, EEI recently issued a white paper that urges FERC to provide regulatory certainty by continuing to authorize stable returns that are commensurate with the risks inherent in build-ing transmission. The white paper, “Transmission Invest-ment—Adequate Returns and Regulatory Certainty Are Key,” may be downloaded at www.eei.org.

Edison Electric Institute is pleased to announce that The YGS Group is our new partner for Electric Perspectives’ media sales, available to support your marketing and advertising strategy for the remainder of 2013 and into 2014 planning.

When you want to talk visibility and market presence through Edison Electric Institute, call your YGS sales representative.

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A FRESH START

ng

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ds tory to s with

uild-white nvest-

rates. Therefore, a dividend cut that occurred six months prior is refl ected in the market price and a longer ex-clusion from the proxy groups is not warranted.

Finally, the commission needs to consider the long-term implications of compromising its policy of promot-ing transmission investment. The re-cord shows that utilities responded to the commission’s policy of promot-ing transmission by increasing their investments in this area signifi cantly to the benefit of wholesale markets, reliability, renewable integration, and customers nationwide. In addition, numerous utilities pursued the devel-opment of wholesale energy markets by voluntarily joining ISOs and RTOs per commission policy. For the com-mission to backtrack now would signal to the utilities and investors that its policies lack stability and durability. ◆


OPERATIONS

Building a RobustNuclear Supply ChainBy Andy Patterson and Will Smith

The devastating 2011 tsunami that struck Japan’s northeast coast and precipitated the meltdown

of three nuclear reactors at the Fuku-shima Daiichi power plant remains top of mind for the American nuclear power industry. In the disaster’s aftermath, U.S. nuclear regulators and operators took numerous steps to prevent a similar event from occurring domestically. Conservative estimates suggest that the cost of complying with the Nuclear Regulatory Com-mission’s (NRC’s) directives could reach as high as $100 million per plant.

Now, more than two years after the tsunami, electric companies grapple with how to operate in a cost-effective manner within this new regulatory environment. For merchant generators, this issue is especially dif-fi cult given forecasts for an extended period of low natural gas prices—and the fact that they must recover the cost of operating the plant from energy sales, not from ratepayers. Solutions are likely to come from their supply chain organi-zations and strategic partnerships, with key suppliers poised to assist with the response. Strategic sourcing initiatives are coming to the forefront of the indus-try’s response.

To be sure, a power company’s sup-ply chain is a perennial target when it comes to cost-saving efforts. The sheer cost and complexity of supplying a nuclear plant—involving dozens of global and domestic vendors, stringent Andy Patterson is a principal and Will Smith is a manager in the Power & Utilities Advisory practice of Ernst & Young. The views expressed herein are those of the authors and do not necessarily refl ect the views of Ernst & Young or the Edison Electric Institute.

quality assurance requirements, and myriad integrated technologies—make the supply chain a natural place to look for effi ciencies.

But the nature of the post-Fukushima regulations demands that the supply chain play a signifi cant role, including the requirement for off-site storage fa-

cilities to house equipment and supplies that could be deployed in the event of a plant emergency.

To navigate these thorny logistical issues, electric companies will rely heav-ily on their supply chain organizations for guid-ance. Thoughtful answers, informed by technical competence, operational experience, and regulatory familiarity, will provide a

roadmap to fi nancial success in a post-Fukushima world.

Responding to New RegulationsSenior nuclear experts from several electric companies engaged with NRC personnel to help shape the new regula-tions. The rules are designed to ensure that nuclear plants are able to withstand an external event stressing the facility beyond its design capabilities, such as a fl ood or earthquake. The requirements demand cooling restoration under all operating conditions, assuming a con-current loss of all electric power and normal heat sink access—the set of cir-cumstances that doomed the Fukushima Daiichi plant. Equipment to combat such an emergency must be protected and accessible.

Through careful study of the new regulations and ongoing conversations with utility executives, we believe an electric company’s response should include these elements■ an off-site storage facility to house equipment and supplies;■ routine equipment testing to ensure that equipment will function as required upon demand;■ procedures to deploy necessary per-sonnel and transport equipment to the affected station within a specifi ed time frame;■ redundant communications channels between the nuclear plant and off-site storage facility to guarantee commu-nications aren’t interrupted during an emergency; and■ protocols to govern the release of equipment from the off-site storage lo-cation, as well as the routing of it to the affected station.

Such a solution will have a profound impact on each company’s supply-chain organization during development and operation of the off-site facility.

The nature of the post-Fukushima regulations

demands that the supply

chain play a signifi cant

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J U LY / A U G U S T 2 013 41

The Off-Site Storage SolutionAs electric companies prepare their responses, they and their vendors will need to address numerous supply chain-focused questions that impact both nuclear safety and economic value.

Nuclear power plant operators often utilize warehouses inside plant grounds to store items needed for routine main-tenance. Off-site facilities promise to serve a fundamentally different purpose, housing substantial pieces of machinery that would be deployed in the event that a nuclear plant lost electrical power and cooling capability. Inventory might include portable diesel generators,

pumps, battery banks, compressors, hoses, satellite communications gear, and other emergency equipment.

The off-site warehouse’s location is critically impor-tant. The facility must be close enough to an affected

power plant to offer timely response but at a distance that offers safety from whatever disaster triggered the emer-gency.

There is no one-size-fi ts-all approach to devising an off-site storage solution; each company will need to devise a plan driven by its own particular circum-stances, in consultation with key ven-dors and suppliers. The questions they face generally fall into two categories: warehousing and emergency response.

Warehousing issues include deter-mining whether the operations of an off-site warehouse should be outsourced; identifying a location that meets safety and logistical requirements; and set-ting quality standards for supplies and

equipment and for warehouse construc-tion.

Emergency response issues include providing adequate staffi ng levels in the event of an emergency; distributing ma-terials and supplies from the warehouse in a timely manner; and developing a transportation plan that includes alter-native routes and modes.

Of course, cost also must be consid-ered. While it becomes readily apparent that the least-complex solution is for an equipment warehouse to serve a single station, this approach is likely to be far more expensive when compared to a model in which a warehouse serves multiple stations.

Other cost-related questions arise: Could an off-site warehouse be served by an existing distribution center? If so, further investigation as to the company’s or vendor’s overall warehousing and distribution strategy may yield other, more economical, options. Further, the opportunity to have a shared facility for nuclear generating stations in close proximity could also be explored as a more cost-effective alternative.

Warehouse inventory might include portable diesel generators (above), pumps, battery banks, compressors, hoses, satellite com-munications gear (lower left), and other emergency equipment.

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The Nuclear Energy Institute has offered some guidance, issuing a strat-egy—called “FLEX”—last December, which provides a useful set of guide-lines to help the industry implement the NRC’s regulations. But it is not meant to provide a specifi c solution for any par-ticular nuclear power facility.

FLEX calls for portable emergency equipment to be housed at various locations inside each plant to combat an emergency that stresses the facility beyond its design specifi cations. These on-site warehouses would be tailored for each facility, taking into account differences in plant design, and would be built to withstand events most likely to cause an emergency—the risk of fl ooding in the Midwest, for example, or earthquakes on the West Coast. Other elements of the FLEX plan include pro-cedures for emergency response per-

sonnel and controls to ensure regular maintenance and testing of emergency equipment. As a backup, the industry has discussed building regional supply centers in Memphis and Phoenix—stra-tegically located within a day’s drive of all U.S. nuclear plants. Both will serve all 100 reactors across the country in an industry cost-shared program.

A Resilient IndustryTo be sure, the nuclear power industry has been affected deeply by what oc-curred at the Fukushima Daiichi power plant. NRC’s regulations will cause utility companies and their suppliers to make

a number of changes, but the new rules promise new safeguards on top of the robust measures already in place.

The Fukushima disaster led many countries to step back and re-evaluate their nuclear power programs. Japan, for example, initially moved to shut down all 50 of its working nuclear reactors by 2040. But nuclear power still plays a critical role in helping to meet global energy demand, and signs indicate sustained interest in the tech-nology.

NEI’s “FLEX” strategy calls for portable emer-gency equipment to be housed at various locations inside each plant to combat an emergency that stresses the facility beyond its design specifi cations.

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J U LY / A U G U S T 2 013 43

About 440 nuclear power reactors operate in 29 countries, according to the International Atomic Energy Agency (IAEA), supplying about 14 percent of the world’s electricity. An additional 67 reactors are under construc-tion, including 27 in China, and IAEA says 20 more coun-tries should have nuclear power on line by 2030 as the developing world continues to modernize. New reactors are under construction in the United States for the fi rst time since the 1970s. And Japan is reconsidering its decision to back away from nuclear power. The country’s recently elected government announced that it would review the phase-out and restart any plants that pass safety tests.

Ernst & Young surveyed nuclear industry executives in Europe and the United States last year to understand the types of strategic responses con-templated in the wake of the Fukushima disaster. The fi ndings included unani-mous support for the continued safe, re-liable operation of nuclear power plants and an unwavering commitment to the construction of new plants.

Sound Supply-Chain StrategiesElectric companies have until 2016 to comply with the NRC’s new rules. As nuclear utilities and vendors prepare to meet these new requirements, Ernst

& Young advises clients to use the Supply Chain Op-erations Reference model, a product of the Supply Chain Council, to conduct a thor-ough analysis of their sup-ply chain operations when developing a strategy to meet the heightened safety standards.

For nuclear utilities, this approach should include:■ review existing emergency response systems and protocols, current ware-housing and distribution capabilities, and external utility and vendor relation-ships;■ perform a “gap analysis” to identify areas where existing facilities, equip-ment, systems, and protocols should be expanded or improved, and where facilities, equipment, and systems need to be acquired in order to comply with post-Fukushima rules—focused on maximizing nuclear safety and business value;■ conduct a cost-benefi t analysis of initiatives that would satisfy the new safety requirements, thus enabling the selection of options most favorable to the organization; and

A thorough examination of supply chain operations should include a cost-benefi t analysis of initiatives that would satisfy the new safety requirements.

■ employ strategic sourcing coupled with supplier relationship-management techniques to form effective alliance strategies with the supply base.

For nuclear vendors and suppliers, steps should include:■ assess existing equipment for emer-gency distribution, as well as current warehousing locations that meet both location and storage security require-ments;■ develop performance benchmarks by holding discussions with potential util-ity clients and regulators, and research-ing other groups providing emergency response services;■ partner with utilities to identify where current capabilities and planning are insuffi cient to support an emergency response, and then develop solutions that meet client needs in the most cost-effective manner; and■ develop turnkey solutions that bundle across the majority of needs for com-plete responses.

Whatever plans electric companies ultimately adopt, there’s no doubt supply-chain personnel will be pro-pelled into the role of key participants in the preparation of beyond-design-basis external events. Their decisions, provi-sions, and recommendations will help to shape the protocols for responding to incidents in the future, as well as how much it will cost to comply with post-Fukushima regulations. Thoughtful consideration and application of sound supply-chain strategies when dealing with this challenge almost certainly will result in improved safety and commer-cial benefi ts for existing nuclear power plants, as well as support the industry’s commitment to building new plants. ◆

Electric companies have until

2016 to comply with

the NRC’s new rules.

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of the total announced capacity additions) is the highest level announced in fi ve years and a 49-percent increase when compared to the amount announced in 2011. The rise in an-nouncements for natural gas capacity is driven primarily by increasing regulatory constraints on coal generation and the

relatively low capital costs associated with building a natural gas plant com-pared to other baseload sources.

In addition, low natural gas prices are expected to remain low for the foresee-able future, increasing the attractive-ness of the fuel. Though there remains 1,162 MW of new coal capacity that is expected to be completed in 2013 and 2014, including Southern Company’s Plant Ratcliff IGCC in Mississippi (which uses a state-of-the-art coal gasifi ca-tion design), no new coal capacity is expected beyond 2014.

Renewable Energy 2012 was a record-breaking year for wind, with new additions totaling 12,351 MW as developers rushed to get

The electric power industry added 30,352 megawatts (MW) of new generating capacity in 2012,

the most added in one year since 2003 and a 35-percent increase compared to 2011.

Shareholder-owned electric com-panies brought 13,325 MW online last year—split between new builds (7,236 MW) and expansions at existing plant sites (6,089 MW)—including 5,716 MW of new natural gas capacity and 2,025 MW of new coal capacity. Shareholder-owned electric companies canceled plans for 13,121 MW of capacity in 2012, exceeding the total amount canceled in the prior two years combined.

Natural Gas and CoalThe year saw substantial new natural gas-fi red capac-ity added to the grid (8,841 MW), as well as new coal ca-pacity (4,525 MW), as plants announced several years ago came to fruition. The new capacity is distributed throughout the United States, with most new additions located in the Southeast. Duke Energy and Southern Company led the additions in this region by add-ing new natural gas units at several sites of retiring coal units.

Shareholder-owned electric compa-nies also announced plans for 6,108 MW of new capacity last year, about 19 percent less than what was announced in 2011. The 5,099 MW of natural gas capacity announced in 2012 (84 percent

The 5,099 MW of natural gas capacity announced in 2012 is the

highest level announced in

fi ve years.

CONSTRUCTION

Banner Year for New Capacity AdditionsBy Joanne Hopkins

Joanne Hopkins is manager of energy supply for the Edison Electric Institute.

facilities online before the wind produc-tion tax credit (PTC) was scheduled to expire on December 31, 2012. Share-holder-owned electric companies added a total of 4,222 MW of wind across 17 states, with California, Kansas, and Iowa adding the most new capacity. NextEra Energy led the way with new wind ca-pacity totaling 1,378 MW.

Solar capacity additions continue to grow rapidly, with 2,882 MW added in 2012, a 79-percent increase compared to 2011. Shareholder-owned electric companies built and own 564 MW of this total, led by Sempra Energy with 238 MW and Consolidated Edison with 88 MW. The growth in 2012 was driven primarily by the completion of several utility-scale solar projects, including the 144-MW Mesquite Solar facility in Ari-zona and the 92-MW Copper Mountain

J U LY / A U G U S T 2 013 45

Solar project in Nevada, both owned by Sempra Energy. The Mesquite Solar facility was a benefi ciary of a $337-mil-lion loan guarantee from the Department of Energy. While shareholder-owned electric companies added new solar ca-pacity in 12 states, Arizona, California, and Nevada accounted for 80 percent of new capacity additions.

Renewables comprised 16 percent of new capacity announcements in 2012, but the level was 69 percent less than the previous year. Wind announcements in particular are down as a result of the PTC’s originally scheduled expiration at the end of last year. In addition to extending the PTC for one additional year in early January, Congress also made a signifi cant change to the terms of qualifi cation. Rather than needing to be operational by the expiration date to qualify for the PTC, a wind facility now must merely be under construction to

qualify for the tax credit. Announce-ments of new solar projects also are down, and no new solar capacity is cur-rently planned beyond 2016, when the investment tax credit is slated to expire.

More than two-thirds of the canceled capacity was solar (8,834 MW), the ma-jority of which was several large solar thermal facilities originally planned for the West. Concentrated solar power projects have struggled to compete economically given the rapid decline in recent years of photovoltaic prices, as well as low natural gas prices. A handful of wind projects around the country also were canceled.

Regional Transmission ExpansionSeveral regions have recently approved plans for additional investment in the transmission system.

ISO-NE released its Regional System Plan in November 2012, highlighting 256 transmission projects (valued at about $6.0 billion) in various stages of development from the early stages of conception through under-construction and nearly completed. This includes several proposed transmission lines included in Maine’s Power Reliability Program, the New England East-West Solution, and the Long-Term Lower Southeastern Massachusetts Project.

Many electric companies are retiring coal-fi red plants and building new natural gas-fi red plants, such as Duke Energy’s Buck Combined Cycle Plant in Rowan County, NC.

Duk

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Check Out EEI’s New Web Sitewww.eei.org

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information on the key regulatory and legislative issues

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MISO’s board of directors approved its annual transmission expansion plan at the end of 2011, which includes $6.5 billion in new transmission proj-ects through 2021. The projects are expected to improve reliability and to connect additional renewable energy to the grid.

New York Governor Andrew Cuomo created an Energy Highway Task Force and asked the task force to make recom-mendations to upgrade and enhance the state’s electric system through a combi-nation of generation and transmission projects utilizing both public and private investments. The plan put forth by the task force leverages nearly $6 billion in public and private funding, including more than $1 billion for transmission projects that will increase the capacity of the system by 1,000 MW, as well as additional grid upgrades to enhance

Sempra’s 92-MW Copper Mountain solar complex in Boulder City, NV, is one of the largest photovoltaic plants in the country.

J U LY / A U G U S T 2 013 47

several years. However, as the region braces for record coal-fi red generator retirements, PJM has approved 777 local reliability transmission upgrades, equal

to approximately $5 billion.In SPP, the board of

directors approved a fi ve-year plan that is anticipated to result in $1.7 billion in transmission expansion projects. The bulk of the investment is focused on enhancing reliability, but the projects will also enable additional renewable capac-ity to connect to the grid so that the states within SPP are able to meet their renewable goals.

To help achieve California’s 33-per-cent renewable portfolio standard (RPS) target by 2020, CAISO has proposed adding a new category of transmission projects that will facilitate the necessary

reliability and enable the expansion of renewable generation. As a fi rst step of this plan, the New York Power Authority has approved a $726-million project for repair and improvements to its transmission system in western, central, and northern New York.

In its 2012 Regional Transmission Expansion Plan (RTEP), PJM identifi ed $2.4 bil-lion in transmission upgrades needed to address reliability concerns associated with the deactivation of 104 generat-ing units expected between May 2012 and the end of 2015. PJM projects that ad-ditional deactivation requests will be received in 2013, necessitating additional analyses and transmission upgrades. The PJM board also voted to remove the Mid-Atlantic Power Pathway and Potomac Appalachian Transmission Highline projects from the RTEP due to updated analysis that showed that these projects would not be needed for

PJM identifi ed

$2.4 billion in trans-mission

upgrades needed to address

reliability concerns.

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INDEX TO ADVERTISERS

ACRT, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Booz & Company. . . . . . . . . . . . . . . . . Cover 2

Edison Electric Institute . . . . . . . . . . . . . . . . 46

HDR, Inc.. . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Henkels & McCoy, Inc. . . . . . . . . . . . . . . . . 15

Hubbell Power Systems, Inc. . . . . . . . . . . . . 29

Pace Global . . . . . . . . . . . . . . . . . . . . . Cover 3

Quanta Services. . . . . . . . . . . . . . . . . . Cover 4

Renewable Energy Systems Americas, Inc.. . . 2

Sargent & Lundy . . . . . . . . . . . . . . . . . . . . . . 1

The YGS Group . . . . . . . . . . . . . . . . . . . . . . 39

Wright Tree Service . . . . . . . . . . . . . . . . . . . 13

expansion of the electric grid to support renewable, variable resources. CAISO’s 2012-2013 Transmission Plan identi-fi ed 36 transmission projects with an estimated cost of $1.35 billion that are needed to maintain system reliability and fi ve smaller policy-driven upgrades. In addition, consistent with previous plans and given the transmission proj-ects already approved or progressing through the California Public Utilities Commission approval process, CAISO expects that no new major transmission projects are required to be approved by the region to support achievement of California’s RPS. ◆

Wind energy projects totaling approximately 5,549 megawatts of capacity are operating in California today.

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iee atwork Where innovation and ef cient technologies meet.

Innovations Across the Grid DialogueBy Lisa V. Wood, executive director of IEE and vice president of the Edison Foundation.

As the electric utility industry embraces the op-portunities and the challenges driven by new technologies and innovation, partnerships with technology companies will shape the grid in pro-

found ways. To discuss the innovations occurring across the power grid, IEE recently held its 2013 Partner Roundtable—a dialogue among IEE’s Management Committee of electric utility CEOs and technology company executives. The meet-ing focused on advancements in grid optimization, building effi ciency, demand response (DR), distributed generation (DG), big data, and customer engagement.

Grid OptimizationBob Rowe, IEE co-chair and president and CEO of North-Western Energy, led the discussion and pointed out that grid optimization is about making the invisible part of the grid—sensors, wires, and critical equip-ment—work in seamless fashion so that customers on the visible side can go about their lives productive-ly and uninterrupted. This perspec-tive is part of the bigger picture of a smart grid that is optimized across all supply and demand-side com-ponents.

The conversation highlighted Volt/VAR optimization and en-hanced distribution management and automation systems. For example, Duke Energy is using Pike Electric’s voltage and optimizations profi ling in the Carolinas to reduce line loss, identify low-voltage areas on the distribution feeder, and provide about 200 megawatts (MW) of energy savings on the system. OGE Energy is in the process of using Volt/VAR tech-nology in collaboration with ABB to achieve 75 MW of load reduction across 400 feeders by monitoring the distribution network and computing the optimal control settings.

Building Effi ciencyDilek Samil, COO of NV Energy, led the building effi ciency discussion that highlighted advancements in utilizing exist-ing building management systems and data, often at no- or low-cost, to improve the energy use and performance of buildings. NV Energy works with Building IQ to engage casinos, schools, hotels, and offi ces in resource optimiza-tion through the mPowered for Commercial program. This program moves away from the typical “cash for kilowatt” design, allowing NV Energy to work with its customers to make long-lasting, fi nancially sound, and technology-driven changes in large buildings. By upgrading and overlaying the

existing energy-management system with open, automated DR communications, NV Energy delivers building effi ciencies through an innovative application of HVAC optimization un-der a software-as-a-service platform. NV Energy will deliver 75 MW of savings by 2015 through this program.

Demand ResponseFor the third discussion, Joe Rigby, chairman, presi-dent and CEO of Pepco Holdings, shared how subsidiary

Pepco is utilizing two DR programs with residential customers—the EnergyWise Rewards direct load-control program that has about 250 MW of capacity and the newer price-responsive Peak Energy Savings de-mand program to manage demand via price signals.

Comverge manages the direct load-control program for Pepco and provides the technology, recruit-

ment, customer interface, and data analysis. Most impor-tant, Comverge operates the load-control events. With smart meters deployed and two years of successful pilot results, Pepco is now in the process of deploying the Peak Energy Savings program where the customer receives a price signal during peak demand times and a bill credit for responding by reducing demand. Regulatory commissions in Maryland and Delaware have approved a “peak-time rebate” for all resi-dential customers that have smart meters. The two programs combined provide about 300 MW of DR and generate about $2 million in revenue from PJM.

Big TrendsRon Litzinger, president of Southern California Edison, led the fi nal discussion on big industry trends, including DG, customer engagement, and big data. Public policy sup-port for DG, including both subsidies and DG mandates, will ensure that DG continues to grow. As the number of DG customers increases, the development of rates that are fair to all customers, as well as a grid that can handle this fl exible and growing resource, are critically important. DG customers need to get a fair price for the power they sell into the grid but also need to pay their fair share of the cost of using the grid.

Technology is driving customer engagement opportuni-ties, and several companies are working with utilities to engage with their customers and to provide actionable infor-mation. Lastly, big data is focused on leveraging data analyt-ics and IT to change the way utilities manage the power grid as well as to change the customer experience.

Electricity runs every aspect of our economy and our lives. The collaboration of electric utilities with technology companies, regulators, and other stakeholders is critical to a successful transformation of the nation’s grid. The 21st-century power grid is too important not to get it right. IEE’s Partner Roundtable is a key forum to advance the dialogue about innovations occurring across the grid. ◆

Joe RigbyJoe Rigby

Bob RoweBob Rowe

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