PIONEERING GOVERNMENT RESEARCH
VOLUME 9 // ISSUE 6 NOVEMBER 12 // DECEMBER 12 energybizmag.com
PEOPLE // ISSUES // STRATEGY // TECHNOLOGY
PENSION LIABILITIES
LOOM THE REGULATORS TACKLE THE ISSUES SOUTHERN LEADERSHIP ºº TOM FANNING
WAVE ENERGY’S BIG SPLASH THE BOULDER MUNI DEBATE
ºº POINT COUNTERPOINT
AN E N E RGY C E NTR AL PU B LIC ATION
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NOVEMBER/DECEMBER 2012
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Features
Departments
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4 Nightmare on Main Street
Pension Liabilities Loom With an aging work force rapidly reaching retirement age, utilities face a mounting challenge on the pension front. Some are prepared — others are not. Why? What are the implications?
20 The Regulators Tackle the Issues
State utility regulators must deal with a fast-changing energy world — and make sure it remains affordable. How to they do it? They tell you in EnergyBiz’s annual Leadership Roundtable discussion with regulators from across America.
26 Pioneering Government Research
Utilities, compared with other sectors, are not big spenders on R&D. The federal government, however, is supporting promising initiatives on a number of fronts.
29 New Frontiers for a Transforming Grid Researchers in the Pacific Northwest are moving in bold new directions to shape the capabilities of smart grid. A leader in that effort provides an inside account of those efforts and their significance.
O U R TA K E
6 Letters BUSINESS EDGE
8 Data Center Efficiencies 9 New Dimensions of Risk 10 Atlantic Cable Project Delays 12 Keep the Lights On T E C H N O LO GY F R O N T I E R
34 Boardman Goes Biomass 36 Strengthening the Transmission Highway
38 Wave Energy’s Big Splash INTRODUCING
44 Southern Leadership/ Thomas A. Fanning METRICS
47 America’s Nuclear Future/ Coal’s Downturn LEGAL ARENA
48 Boulder Debate
48 Point/Go Muni
49 Counterpoint/Forget about It
50 As Xcel Sees It
52 Neighbors Seize Power 53 FCC Fees for Smart Grid 54 Building New York State’s Vol. 9, No. 6. Copyright 2012 by Energy Central. All rights reserved. Permission to reprint or quote excerpts granted by written request only. EnergyBiz (ISSN 1554-0073 ) is published bimonthly by Energy Central, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Periodical postage paid at Aurora, Colo., and additional mailing offices. Subscriptions are available by request. POSTMASTER: Send address changes to EnergyBiz, 2821 S. Parker Road, Suite 1105, Aurora, CO 80014. Customer service: (303) 782-5510. For change of address include old address as well as new address with both ZIP codes. Allow four to six weeks for change of address to become effective. Please include current mailing label when writing about your subscription.
2 E N E RGYB I Z November/December 2012
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» OUR TAKE Nightmare on Main Street THE POWER GRID VERSION OF BOMB SHELTERS PERHAPS THE MOST IMPORTANT energy story of the summer deserves revisiting. India suffered through massive blackouts that spilled across regions with a combined population about twice that of the United States. The televised images of that outage were easily compartmentalized and dismissed. Here was a far-off undeveloped country. It can’t happen here. Thinking about the Indian power calamity, I recalled admonitions from grid and cyber security experts in the United States that it is only a matter of time before terrorists, criminals or a hostile state disrupts the power grid in this country. World War III, should it come, or the next 9/11, is likely to be a massive digital invasion that will be unprecedented in its ability to disrupt the normal lives of tens of millions of Americans far removed from any physical battlefield. Picture a twin assault on our power grid that would be both physical and cyber. Transmission experts have told me that small explosions that bring down remote, unprotected pylons could cause cascading mayhem on the power grid affecting distant cities and regions. Couple that with a coordinated cyber attack on the power supply system, and America’s strategic and economic strength in the world fade to darkness. The consequences can barely be fathomed. What if we had to spend days, or weeks, without email, cell phone service, electronic banking, heat in the winter or air conditioning in the summer, clean water, transportation — and light? Much is being done by utilities and government to try to put in place protections 4 E N E RGYB I Z November/December 2012
that would ward off cyber attacks. New smart grid technologies are providing powerful tools to monitor and quickly repair the transmission and distribution system, sometimes seamlessly with little or no human intervention. But a serious question needs to be asked. Perhaps, given the magnitude of the risks we are exposed to, we need to dramatically alter the way we produce and transport the electricity we need to run American society. What would be the equivalent of a bomb shelter for this looming, existential threat? Perhaps we should view distributed generation and energy storage in a new light. Perhaps we need to marshal our resources to speed development and deployment of these technologies as a matter of national security. If our homes, factories, office buildings, government facilities, water treatment facilities, hospitals and cell towers all had the ability to generate their own electricity — or call on stored supplies of power — we would be vastly more secure than we are today. It is doable. This summer I spent an afternoon visiting the National Renewable Energy Laboratory in Golden, Colo. The main building on the campus is a net zero energy consumer. It produces what energy it needs — and is designed to use very little. Dan Arvizu, the lab director, told me he discussed the energy profile of that building with the head of Xcel Energy, which is in the business of selling electricity. That executive readily conceded to Arvizu that net zero energy building has to be the way of the future. Although it may take time to realize, utilities ultimately may have no choice but to evolve their business models. Despite Al Gore’s best efforts, the threat of climate change has not ignited a “moon shot-like” effort to transform our energy grid to meet the needs of a new era. Perhaps we need to start seeing solar panels and small-scale wind turbines on our roofs, along with New Age skylights that drastically reduce lighting needs, as our bomb shelters of the future.
Martin Rosenberg, Editor-in-Chief editor@energybiz.com
ONE SMALL WESTINGHOUSE REACTOR
W E S T I N G H O U S E E L E C T R I C C O M PA N Y L L C
Another giant step by the true leader in commercial nuclear energy
Westinghouse, the world leader in the development, licensing and deployment of commercial nuclear energy plants, is again leading the industry, this time with a 225 MWe integrated pressurized water reactor that can generate electricity for a residential community of 45,000 homes without emitting any greenhouse gases. And unlike other designs, the Westinghouse Small Modular Reactor (SMR) is an outgrowth of proven, land-based nuclear reactor technology that takes safety, reliability and constructability to unsurpassed levels. To make this exciting new reactor a reality, Westinghouse, with the full support and backing of its majority owner Toshiba Corporation, is working with a distinguished group of partners, notably Ameren Missouri, the Association of Missouri Electric Cooperatives, Associated Electric Cooperative, Inc., The Empire District Electric Company, Kansas City Power & Light Company and the Missouri Public Utility Alliance. Proud of our track record of success, but always looking to the future, Westinghouse nuclear technology will help provide future generations with safe, clean and reliable electricity. Check us out at www.westinghousenuclear.com
» LETTERS Regarding your September/October
Volume 9 // issue 5 september 12 // october 12 energybizmag.com
Next GeNeratioN Nuclear
issue, it was fabulous from start to finish,
people // issues // strategy // technology
PAtHwAy to CoAl’s Future
with its key insights on utility executive
www.energybizmag.com EDITOR-IN-CHIEF Martin Rosenberg mrosenberg@energycentral.com 303.228.4725
priorities; the evolution of generation across coal, nuclear, gas, and renewables; and evolving utility technology and business models. I found it highly useful!
CHIEF COPY EDITORS Meaghan Alfier,
CAliForNiA Feed-iN tAriFFs
triuMPHiNg FiNANCiAlly
New InformatIon StrategIeS
SDg&e’s
mIchael nIgglI
AN e N e rgy C e Ntr Al Pu b liC AtioN
Chris King Global Chief Regulatory Officer Siemens Smart Grid Solutions Foster City, Calif.
Don Bishop, Martha Collins SENIOR CONTRIBUTORS
Wayne Barber wbarber@energycentral.com 703.651.2166 Barry Cassell bcassell@energycentral.com 804.466.0187 Carl Dombek cdombek@energycentral.com 970.236.6235 Rosy Lum rosy@energycentral.com 347.799.2802
I read with interest your timely editorial “Listen Up, Mitt and Barack” in the September/ October issue. You suggested that perhaps both candidates could agree on a grand energy compact in advance of the election. Unfortunately, the presidential candidates rarely agree with their opponent on any issue, let alone an important issue like energy. As Nick Akins mentioned in the “Executive Vision” article, “We need a consistent, coherent national energy policy that enables long-term investments to be made.” How true. With peak oil and climate change staring us in the face, for our children’s sake I feel we should hasten our transition to renewable energy sources. How the next president of the United States advances renewable energy, or any other energy source for that matter, versus just maintaining business as usual, remains to be seen. Joe Koch ITC Holding Dubuque, Iowa
I write in response to comments made by contributors to the July19 EnergyBiz webinar, “New Approaches to Grid Secu6 E N E RGYB I Z November/December 2012
rity.” Regarding malicious incidents — cyber and physical — affecting the grid, it may be useful for the industry to be made aware of the unclassified Energy Incident Data Base (EIDB). It contains some 200,000 incidents worldwide, and is updated daily. By comparison, the National Counterterrorism Center’s database of incidents affecting the energy sector contains a fraction of what is contained in the EIDB, due in large measure to the criteria NCTC requires be met for including incidents in it. I can supply much more about the EIDB concerning how it is structured and what is in it. Robert K. Mullen Bisbee, Ariz. Editor’s note: The Grid Security webcast can be accessed at energycentral.com/events/26072.
To contribute to the Letters column, please email your submission to editor@energybiz.com. Provide your name, address and daytime phone number. Letters may be edited for style and space.
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» BUSINESS EDGE
Data Center Efficiencies CHICAGO UTILITY SETS INCENTIVES // BY VAL JENSEN WITH THE EXPONENTIAL INCREASE in data available through digital channels and the enhanced need to store this information, the need for data centers is growing along with the associated energy requirements. Data centers are major consumers of energy. They are responsible for approximately 2 percent of the kilowatt-hours consumed in the United States and they count on uninterrupted power to support their operations. Consumers and businesses alike have embraced the speed and convenience of a digital world but, at the same time, they are more ecologically aware and are looking for ways to minimize their environmental footprints. In northern Illinois, ComEd is responding to these contrasting trends with an energy-efficiency program that supports the region’s growing data center market, while helping these businesses lower their energy use and save money. ComEd offers data center customers the reliability they need as well as the technical and financial support to run an energy-efficient operation. Our reliability performance is already in the top third nationally and — because you can’t power a 21st century economy with a 20th century infrastructure — reliability is on target to become even stronger due to a 10-year, $2.6 billion infrastructure and smart grid investment program that is under way. The Chicago area is one of the top data center markets in the country. The region offers a robust competitive electricity market with more than 50 suppliers, low-carbon generation sources from the highest concentration of nuclear power plants in the country, and growing renewable resources, including wind and solar power. ComEd’s new data center incentive offering builds on that strong foundation. We work with designers, owners and tenants to strengthen operations and maximize energy efficiency. Whether businesses are building, renovating or expanding facilities, we work with them to achieve a permanent reduction in electri8 E N E RGYB I Z November/December 2012
cal usage. By providing per-kilowatt-hour financial incentives and technical assistance, ComEd helps these businesses lower energy use and save money on electricity bills. We help calculate energy savings and incentivize energy efficiency measures at a rate of 7 cents per kilowatt-hour saved, up to 100 percent of the incremental cost and 50 percent of the total cost of the project for both new and existing facilities. In terms of energy efficiency, we have dedicated account managers who are specialists within the data center industry. They currently serve as energy liaisons to more than 60 data centers in northern Illinois. These experts work with both new and existing businesses to reduce utility bills by helping to offset the cost of building or modernizing equipment and facilities. Last year, energy-efficiency projects were completed at several customer sites. Latisys, a leading provider of IT infrastructure services from colocation to cloud, implemented advanced cooling systems in its Chicago data center. Working with ComEd, it was able to better manage air flow and provide more concentrated and precise cooling for its customers, while realizing significant savings. ComEd’s data center offering is one of many incentives available to business customers within the Smart Ideas for Your Business portfolio, which encourages customers to save money and reduce energy consumption by helping them offset the cost of energy-efficiency measures. Since its inception four years ago, the program has produced more than 1.2 billion in kilowatt-hour savings and has saved customers more than $94 million on their electric bills. This is a time of great opportunity for the energy industry. At ComEd, we are working hard to transform the utility business model. Our goal is to deliver the combination of technologies, information and customer service options that provide the greatest value to customers and the economy of our region. Val Jensen is ComEd senior vice president of customer operations.
New Dimensions of Risk OPPORTUNITIES NOW, THREATS LATER // BY STEVE DREYER AMERICA’S REGULATED UTILITY COMPANIES have strong credit ratings for good reason. They are local monopolies providing an essential service without practical substitutes, are assured recovery of approved costs and have a decades-long history of funding access. Utility executives’ risk-management acumen has rarely been a key driver in our ratings, but times may be changing. Prolonged periods of high costs to comply with current and planned environmental regulations could prove too much for customers to bear all at once, breaking down the pass-through business model. In the meantime though, many utilities are realizing more profits than pain in preparing for the coming mandates. Thanks to unusually favorable economic, financial, market, legal, and regulatory circumstances, many utilities are now exploiting what may be a once-in-a-lifetime opportunity to position themselves to meet new regulations in a way that in times past would be severely disruptive, if even possible. What are the sources of this good fortune? First, a sluggish economy eased demands on creaky infrastructure widely deemed incapable of keeping pace with normal levels of economic growth. The day of reckoning that seemed imminent after the 2003 Northeast Blackout has still not arrived. Second, utilities are enjoying an extended period of historically low borrowing DAYTON COAL rates. Investors view their credit as Dayton Power & Light is safe — far better than even the banks seeking bids for coal to supply two Ohio River that are the principal providers of corgenerating plants. porate funding. Third, for electric utiliIt is seeking up to ties that generate electricity, costs for 1 million tons next year and 1.5 million coal and natural gas fuels have fallen tons for 2014. and have remained low. Fourth, in a nod to economic stress, the Obama administration delayed the Environmental Protection Agency’s new ozone emission standards and pushed back a final rule on cooling water intake. Fifth, an
appeals court recently vacated EPA’s Cross-State Air Pollution Rules, although stricter Mercury and Air Toxics Standards are still scheduled to take effect in 2015. So what will utility managements do with this gift of time? One credit-healthy strategy is to close older coal units, scrub others, and build new natural gas-fired plants, as Xcel Energy recently did. Even utilities with an abundance of coal-fired generation can diversify. American Electric Power is running its gas-fired plants more often while it closes more than 5,000 megawatts of coal generation. Some companies are operating gas-fired combinedcycle units rather than coal-fired units as baseload facilities, an unthinkable concept just a few years ago. Southern Company has increased gas-fired generation to 46 percent from 28 percent in one year while cutting coal generation to 35 percent from 53 percent of total output. Other utilities are seizing on favorable credit markets to increase the size and tenor of their credit facilities. Entergy recently renewed its $3.5 billion revolving credit facility for five years. Many utilities have refunded or pre-funded debt maturities, locking in favorable rates for 10 or 30 years. Which is the best strategy for credit? It depends on a utility owner’s risk appetite and its location, which drives fuel mix options and the regulatory framework. The biggest strategic error we see is not taking advantage of the unique opportunity that the economy, the markets, and low natural gas prices present. Our observations of strategic decisions along with information gained from regular interviews of utility executives form our view of each company’s risk-management capabilities and strategic competence. Those companies that regularly assess the effects of critical strategic risks, determine limits for acceptable risk levels and take an effective riskbased approach to strategic decisions will be best able to absorb the effects of rising environmental costs. Other companies are in jeopardy of credit downgrades or worse. Steve Dreyer is lead analytical manager at Standard & Poor’s. energybiz.com E N E RGYB I Z 9
» BUSINESS EDGE
Atlantic Cable Project Delays OFFSHORE WIND STILL PROMISING // BY THOMAS F. ARMISTEAD THE NORTHEAST CORRIDOR has a high issued a declaration of no competitive interest for density of power demand, a congested electric the use of certain areas of the Outer Continental transmission grid and a deep resistance to construction Shelf. The action meant that AWC would avoid the of obtrusive industrial infrastructure. Robert L. Mitchell delays associated with an auction for the leases to sees opportunity in the situation. As CEO of Atlantic the cable’s proposed route. It “opens a door for us to Wind Connection, he is developget started with the environmening an undersea transmission tal impact statement,” Mitchell cable to run offshore from said. Engineering work will northern New Jersey to southern proceed concurrently, capped by Virginia, with five or more links to financial close. The construction the onshore grid. It will serve as start has slipped two years since a backbone for a chain of wind AWC announced the project in farms to be developed indepenOctober 2010. dently but tied into his line. That slippage occurred largely The Atlantic Wind Connection because the Federal Energy will be a 320-kilovolt directRegulatory Commission took current cable integrating up to longer to issue Order 1000 7,000 megawatts of offshore and gave the regional transmiswind generation into the Midsion organizations more time Atlantic power market. Transthan anticipated to make their Elect Development, the pioneercompliance filing to Order 1000, ing independent transmission Mitchell said. FERC’s Order company founded in 1999 by 1000 requires regional transmisThe 350-mile Atlantic Wind Connection cable Mitchell, is leading the project, sion organizations to provide will allow PJM to bypass congestion and can serve as a backbone for offshore wind farms. with investment from Google, a methodology for admitting // Map courtesy of Atlantic Wind Connection Bregal Energy, Marubeni and transmission proposals to link Belgian transmission company Elia Group. It will run renewable energy into their grid. Being admitted into about 350 miles when completed in 2021 or 2022 PJM’s regional transmission expansion plan is AWC’s at a total cost of $5 billion. Construction of 170-miletop priority, Mitchell said. AWC will be one of the first long, $1.7-billion Phase 1 will begin in 2015, with the tests for PJM’s process once it is established and aprest of the project built out in phases. proved by FERC. The project reached what Mitchell called “a major The AWC cable is being developed independently milestone” in May when the Department of the Interior of any specific offshore wind projects, although in full consideration of the potential wind farms since it will be much less profitable if they choose not to tie into it. “When we first announced, a number of the wind Gatherings//Business Edge developers thought that they were going to be able to get their projects in service prior to the time that Maputo, Dec. 3-6 Oil and Gas we would be able to get into service,” he said. But Mozambique South East Africa “the regulatory process for the wind farms has moved Nice, France March Smart Grids slowly. Now, most wind farm developers see that we 20-22 Smart Cities Forum are essentially on the same time line, so many of the For more information about these and other events, please visit wind farm developers have come over to understand www.energycentral.com/events. the benefits of the backbone to them.” AWC and the 10 E N E RGYB I Z November/December 2012
developers — “fewer than 10,” Mitchell said — are discussing interconnection issues in spite of the uncertainty about congressional approval for extending the investment tax credit. A Senate committee has reported out a one-year extension, but the House has not acted on the issue. Still, Mitchell is confident offshore wind will be accepted. Opinion polls commissioned by AWC in New Jersey, Delaware and Maryland found the range of support for offshore wind was 77 to 80 percent. “That is a phenomenally high percentage of the public expressing support for anything,” he said. After poll subjects were told that the higher cost of the offshore wind could increase a ratepayer’s monthly bill $3 to $5 per month, “even at $5 a month, the support for offshore wind was 63 percent,” Mitchell said. Substantial benefits will accrue from the cable, according to AWC’s marketing materials. Wind farms tying in will avoid between $1.2 billion and $3 billion in costs by using AWC’s high-capacity cable instead of each running its own lower-capacity line to the onshore grid. The backbone will allow the operator to direct power to congested areas, lowering power costs there
while increasing revenue for the generating entity. It will also act as a bypass to onshore grids during emergencies such as major storms, heat waves and blackouts. David Lindsay, the Electric Power Research Institute’s program manager for underground transmission, while specifically remaining neutral about the project, agreed that, from a technical perspective, these are reasonable expectations for the cable. The characteristics of the Mid-Atlantic coast are especially favorable to offshore wind development, said Mitchell. “The continental shelf off the New Jersey-Delaware-Maryland-Virginia coast slopes very gently many miles out before it sharply drops off. It goes out 30, 40, 50 miles in some areas before you get beyond 90 to 100 feet in depth. There really isn’t any other place like that on the East or West Coast.” The water depth increases much faster in the Northeast and on the West Coast, he said, so wind farms could not be far offshore. But floating platforms for wind turbines are being developed, so they also could use a backbone. “I don’t think floating turbines are all that far off,” Mitchell said. “I think it could be 2020 or shortly thereafter.”
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» BUSINESS EDGE Keep the Lights On ENERGY POLICY NEEDED // BY JOSEPH L. WELCH
THE EPIC POWER OUTAGE in Cuba recently added to a summer of similar blackouts across the globe. Electricity outages in Egypt, Pakistan and Australia disrupted huge economies and everyday life in the past few months, and the largest electric blackout in history continues to wreak havoc on livelihoods and productivity in India. Blackouts serve as a reminder that a stable electricity grid is not a luxury item. We tend to take much of our infrastructure for granted because it’s usually in full working order. But on the jarring occasions when it is not, we should take more than just a few moments to think about this vital piece of infrastructure. When the United States was first electrified, it was done city by city, with neighboring areas eventually being interconnected by a patchwork of lines. This resulted in a parochial system with individual utilities and states focused solely on their respective needs, rather than on the needs of the interconnected economy we have today. In large part, the energy industry remains that way today. Over the past decade, we have seen an increased and shifting demand for power and competition among generation providers with different energy sources. Some of these resources cannot be easily or economically transported to the location where they will be used. Reliability is compromised when the grid is asked to do things it wasn’t designed to do and it is also more costly. We need a strategy to support the changing uses of the system and plan it on a more regional basis to most efficiently serve the nation’s 21st century energy needs. To move forward, we need a long-term national energy policy that supports the simultaneous advancement of economic growth, energy security, and environmental stewardship. Such a policy will be nimble enough to incorporate all forms of energy produced in the most 12 E N E RGYB I Z November/December 2012
efficient way possible that can be maintained for generations to come. It cannot be accomplished without an energy superhighway in the form of a national, interconnected, high-voltage transmission network. In some regions of the United States, progress is slowly being made to drive change in the approach to the power grid by looking more comprehensively at the use and benefits of the system. In these areas, those planning grid investment are looking across wider footprints to identify how to more strategically build out the grid. They have also identified ways to pay for updates by more closely associating the costs with benefits that households and businesses will receive. Consider for a moment what would change if a single airline were in charge of the air traffic control system at an airport. Would it change the flight patterns or take-off and landing priorities? The power grid, like the national highway system, is most efficient and effective when it is available to everyone on a level playing field. For this reason, the benefits of independent electric transmission companies, detached from the competing market forces of traditional energy companies that own power generation, transmission and distribution assets, have been recognized at the federal level. The independent model provides for a singular focus on the development, operation and maintenance of transmission to improve PANDA PLANT service to consumers and lower the cost Panda Power Funds is of delivered energy. building a 758-megawatt Realizing the changing role transmisnatural-gas fired, combined-cycle power sion plays today in our electrical system, plant in Temple, Texas. the United States can help businesses Panda Power Funds is a Dallas private equity by ensuring reliable access to the power firm. Supporters say they want and deserve and by providing the project will help address the power competitive wholesale markets to make needs of the state. certain they get it at the lowest price possible. Let’s continue this discussion and give the modernization of the power grid the national priority it should have to keep the United States competitive in a global economy. Joseph L. Welch is chairman, president and CEO of ITC Holdings.
EXECUTIVE BRIEFING
Decision 2012: Election Returns & Energy’s Future
W
here will energy policy go for the next four years? EnergyBiz, the trusted resource for utility executives will address this question head on. One week post- election, EnergyBiz¸will bring together top Washington officials and industry leaders for discussion and analysis. This is your opportunity to participate in the conversation. The EnergyBiz Executive Briefing represents a unique opportunity to insert yourself and your company into a group of leaders, thinkers and decision-makers in what will be a fast-moving, hugely significant question. This nation will be either doubling-down on Obama energy policies or shifting radically in a new direction during a new Romney administration. This will be a chance to shape the debate over that future and connect with scores of industry leaders. The EnergyBiz post-election briefing will consist of a one-and-a-half hour briefing with executives from utilities and leaders in Washington and across the country. The briefing will take place on Friday, November 16, from 9 – 11:30am EST, plus it will be broadcast live over the internet. Additionally, a post-briefing article focusing on the conversation will appear in EnergyBiz, in print and online.
Future of WThe National Energy Policy here will energy policy go for the next four years? EnergyBiz, the
By sponsoring the Briefing, your company and your brand can be embedded trusted resource for utility executives will address this question in the fabric ofhead theon. event subsequent editorial coverage, giving you an Oneand weekthe postelection, EnergyBiz¸will bring together audience comprised of qualified executives. top Washington officials and industry leaders for discussion
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and analysis. This is your opportunity to participate in the conversation. The
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14 E N E RGYB I Z November/December 2012
Pension Liabilities
Industry Slow to Confront Problem By Russ Choma
AT THE BEGINNING OF AUGUST,
Energy Future Holdings, the Texas
company that owns Oncor, Luminant and TXU, began an aggressive effort to overhaul its balance sheet — specifically, reducing what top executives saw as a growing burden from the company’s pension plan. The company announced plans to top up its underfunded pension plan, then shut it down by
Illustration by Patrick Sullivan
offering employees the opportunity to take their benefits in a lump sum or as an annuity. Remnants of the plan — mainly for union employees and employees of the Oncor subsidiary — will remain, but the risk from future pension liabilities will effectively be “boxed in,” according to Robert Moussaid, EFH’s director of risk management, pensions and trust investment. energybiz.com E N E RGYB I Z 15
PENSION LI A BILITIES LOOM
Although deregulation and energy markets have rewritten much of the way the power industry operates in recent years, in many ways it remains something of a legacy industry — a high number of older companies, with balance sheets carrying pension plans installed decades ago, and many with aging workforces who, more often than not, are unionized. Pensions, and how to keep them funded, isn’t a question unique to the power industry, but it’s one that may challenge power companies in ways that are unique. An analysis of the pension assets of 62 power holding companies by SNL Financial earlier this year showed that the industry’s plans are on average 79 percent funded — a decline of 2 percent from 2010. While those numbers aren’t terrible — a study by actuarial firm Milliman of 100 companies found an average funding of 79.8 percent — there has also been an increasingly downward trend in the utility industry numbers. According to SNL Financial data, the industry’s pension funds took a major hit in 2008, and although a number of power companies have managed to bounce back, the overall returns on assets are lower industrywide, and far fewer companies are overfunded than in 2007. Only NextEra Energy and Dominion Resources had pensions that were more than 100 percent funded last year, according to SNL data.
One potential red flag is that out of the 10 companies with the highest pension obligations in the industry, nine were underfunded. Despite having the fifth-highest rate of return on assets in 2011, PG&E leads the list with $14 billion in pension obligations in 2011, which were roughly $3 billion underfunded. Another red flag is that while several of the companies with the most underfunded plans were relatively small, several others on the most underfunded list were underfunded by a large amount that grew significantly from 2010. Westar Energy was the second most underfunded, at just 54.1 percent, roughly $479 million underfunded; Hawaiian Electric Industries was 63 percent funded, or roughly $482 million short. Before being topped up, EFH’s pension plan was 76 percent funded. The company had the liquidity to top it off, but keeping pace in coming years would be difficult, Moussaid said. “We’ve had good returns on our assets side, but with the discount rate going down, it wipes out any positive returns,” he said. “Essentially you’re swimming really hard to stay in place.”
... with the discount rate going down, it wipes out any positive returns.
BIGGEST Pension Obligations 2011 PBO 2011 PBO COMPENSATION 2011 PBO 2011 PENSION 2011 FUNDED DISCOUNT RATE INCREASE COMPANY (TICKER) ($000) ASSETS ($000) STATUS ($000) USED (%) USED (%)
PG&E (PCG)
14,000,000
10,993,000
–3,007,000
4.66
5.00
Exelon (EXC)
13,538,000
11,302,000
–2,236,000
4.74
3.75
Consolidated Edison (ED)
11,825,000
7,800,000
–4,025,000
4.70
NA
PPL (PPL)
11,019,000
9,822,000
–1,197,000
NA
NA
Southern (SO)
8,079,000
6,800,000
–1,279,000
4.98
3.84
FirstEnergy (FE)
7,977,000
5,867,000
–2,110,000
5.00
5.20
AES (AES)
6,833,000
5,162,000
–1,671,000
NA
NA
Entergy (ETR)
5,187,635
3,399,916
–1,787,719
NA
4.23
American Electric Power (AEP)
4,991,000
4,303,000
–688,000
4.55
4.85
Dominion Resources (D)
4,981,000
5,145,000
164,000
5.50
4.21
Pension assets are taken at fair value // PBO=pension benefit obligation // As of Aug. 20, 2012 // Source: SNL Energy 16 E N E RGYB I Z November/December 2012
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PENSION LI A BILITIES LOOM
MOST Funded and Most Underfunded COMPANY (TICKER)
PENSION PLAN PERCENT FUNDED 2011
PENSION PLAN PERCENT FUNDED 2010
2011 PENSION PLAN FUNDED STATUS ($000)
2010 PENSION PLAN FUNDED STATUS ($000)
MOST FUNDED NextEra Energy (NEE)
147.06
162.14
999,000
1,239,000
Delta Natural Gas (DGAS)
117.53
92.62
3,141
–1,218
Piedmont Natural Gas (PNY)
109.67
108.22
22,879
17,342
Dominion Resources (D)
103.29
113.72
164,000
616,000
Duke Energy (DUK)
97.15
98.68
–139,000
–64,000
NV Energy (NVE)
96.37
90.56
–30,565
–76,094
Wisconsin Energy(WEC)
94.88
86.65
–68,100
–163,300
SCANA (SCG)
90.95
100.67
–75,100
5,400
PPL (PPL)
89.14
78.02
–1,197,000
–1,505,000
Cleco (CNL)
86.30
73.41
–49,591
–87,829
Westar Energy (WR)
54.14
57.83
–475,900
–370,601
Northwest Natural Gas (NWN)
55.22
64.54
–175,157
–120,324
Unitil (UTL)
58.12
60.52
–43,019
–35,293
Corning Natural Gas (CNIG)
59.64
60.40
–6,400
–6,019
South Jersey Industries (SJI)
59.86
72.00
–78,272
–46,900
Great Plains Energy (GXP)
60.28
61.18
–389,500
–353,800
Questar (STR)
60.29
73.09
–256,900
–132,500
MGE Energy (MGEE)
61.10
68.42
–110,357
–73,546
UGI (UGI)
62.65
61.02
–172,900
–183,900
National Fuel Gas (NFG)
63.35
64.64
–348,058
–326,944
MOST UNDERFUNDED
As of Aug. 20, 2012 // Source: SNL Energy
The declining discount rate is an issue that is hitting pensions across the board, but EFH’s books are also uniquely burdened by more than $37 billion in long-term debt, mostly left over from a 2007 leveraged buyout by private-equity firms. However, according to Moussaid, it’s the current state of the energy market that spurred the move. The drop in natural gas prices left the company skating on razor-thin margins. “Yes, we are in a difficult situation, but shale gas has fundamentally changed the utility business,” Moussaid said, describing the process for deciding to tackle the pension 18 E N E RGYB I Z November/December 2012
issue. “I really believe the driving factors are the economy and most importantly the price of gas.” “It’s the future,” he said, referring to the changes EFH is making to the pension plan, adding that he urges friends at other power companies to begin taking the issue on now. EFH is at the forefront of the pension issue, at least in the power business, said Royce Kosoff, a management consultant with Towers Watson who specializes in utility industry pensions. In fact, he said, compared with other legacy industries, the power business has been relatively slow
to deal with pensions. EFH is not the only company in the utility business looking to reshape its long-term pension plans, and the moves aren’t uncommon in other sectors, but it’s not the norm for the industry, Kosoff said. “I’d say EFH is one of the front-runners,” he said. “The utility sector hasn’t been out in front of this one.” The energy industry does have some major reasons to think about pensions and the need to start addressing them, according to Kossoff. “It’s not quite an issue with life-or-death consequences for the company the way it is in some of these other legacy-type industries, but it’s a big deal,” he said. There are overarching economic issues affecting all industries, like the low discount rate and global economic fluctuations, but the industry is very sensitive to commodity pricing, he said, and the makeup of the industry’s workforce raises issues.
... the driving factors are the economy and most importantly the price of gas.
“This industry is one of the most union-represented industries,” Kosoff said. “If you think about how companies go ahead and change benefits — by having a highly represented workforce it’s going to be more difficult, even if you want to make changes.” What the industry, or at least a large part of it, has going for it that other industries don’t necessarily have is that there is still a high degree of regulation, Kosoff said. That means pension obligations are built into the rate structures approved by the various public utility commissions, and when a company needs to meet its obligations, the PUC can grant those rate changes. “Inside the rate base, there is a provision for the pension cost,” Kosoff said. “By that mechanism there’s basically a steady stream of reimbursement. Utilities are unique in that regard.” But, he warned, that can change. “We’re starting to see some cracks here and there, more questions from the PUCs and more pressure,” Kosoff said. “You are starting to see a little more scrutiny.”
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energybiz.com E N E RGYB I Z 19
The Regulators Tackle the Issues W HER E THE RUBBER MEETS THE ROAD BY MARTIN ROSENBERG
tackle the future of energy efficiency, generation, transmission and much more. In a period of sustained economic hardship, they determine how our power system will be paid for. To better understand the issues they confront at the close of 2012, EnergyBiz recently interviewed a group of regulators from around the country. Their comments, edited for style and length, follow. STATE REGULATORS
Are you sensing an increase in the number of rate cases filed with your commission? ENERGYBIZ
The frequency is picking up. That’s a function of the amount of investment that is being made. KENNEY
We’ve noticed a significant increase in filings of all kinds. It will be even busier the next couple of years. HONORABLE
JONES Some people talk about the capital expenditure boom declining but it’s not declining in our state. We see a need for renewable portfolio standards requirements and environmental upgrades. Gas pipeline safety is going to be an issue. The companies are coming in about every year. I’ve never seen so many rate cases. ROBERTI We are coming out of a period where we had a number of mergers and acquisitions and a number of rate freezes. For about a 10-year period, we had relatively stable 20 E N E RGYB I Z November/December 2012
rates on the distribution side. We can expect a very busy fall and winter period There is going to be a lot of activity in the coming years. We’ve been through the destruction of a very sound vertically integrated utility in Montana, the acquisition of it by an out-of-state utility and the bankruptcy of that utility. For a 10-year period, tree trimming and distribution investment were deferred. Now it’s playing catch-up. We are seeing a lot of need for environmental upgrades. KAVULLA
Are ratepayers growing inured to rising rates? ENERGYBIZ
FOX
The public never expects a rate increase.
It’s not so much that they are unprepared for it. Couple a rate increase from your electric utility with a rate increase from your gas and water company and then you couple that with the global financial crisis that began in 2008. It’s the convergence of all of those that I think has ginned up public participation in our local public hearings, discontent and outright anger. KENNEY
Ever since I began as interim chair of the commission in 2008, my message has been that rates are going up. We should be honest with the public about that. We need to invest in infrastructure in order to ensure reliability. HONORABLE
PARTICIPANTS Commissioner Jeanne M. Fox New Jersey Board of Public Utilities ENERGYBIZ What is the impact of the new era of cheap natural gas? FOX A lot of people have natural gas heat in New Jersey and their rates have gone down dramatically in the last year or two. It could be a $500 difference from last year to this year. That’s huge, especially in this economy.
Are you concerned that stricter federal emissions standards will cut needed generation muscle? ENERGYBIZ
KENNEY It is cause for a concern. In Missouri, we opened a docket that asked our electric utilities to tell us how they intended to comply with the various regulations. We want to be proactive. Low gas prices are driving retirements as much as Environmental Protection Agency regulations. It is something that we are concerned about in Missouri and it is also something that you need to be concerned about regionally. We’ve been paying very close attention and working very closely with the Midwest ISO
Chairman Colette D. Honorable Arkansas Public Service Commission Commissioner Philip B. Jones Washington Utilities & Transportation Commission Chairman Travis Kavulla Montana Public Service Commission Commissioner Robert S. Kenney Missouri Public Service Commission Chairman Douglas R.M. Nazarian Maryland Public Service Commission Commissioner Paul J. Roberti Rhode Island Public Utilities Commission Commissioner Cheryl Roberto Ohio Public Utilities Commission
Photos by Gerry Lewin
as they gather the same type of information on a regional basis to be prepared and gather the information in advance. NAZARIAN We don’t have any real concerns about the impact of the EPA regs in our state. State law required our coal plants to get scrubbed seven years ago so they are already in compliance. But since we’re a small state within a big regional transmission organization, we’re a net energy importer anyway. We import electricity from Pennsylvania, West Virginia and Ohio — places that have not been as aggressive scrubbing their plants. JONES We engage heavily in the integrated resource planning process. One of the values that I look for in a resource portfolio is diversity. All that we’ve been building over the past 10 years is natural gas and wind. Is that a good thing longterm? Probably not. What we’re grappling with right now in resource adequacy is intermittency. The Bonneville Power Administration has integrated 4,800 megawatts of wind in the Northwest in the last energybiz.com E N E RGYB I Z 21
T H E R E G U L AT O R S
10 years, and BPA’s load is 10,000 megawatts. It means more cost for ratepayers because of the intermittency and the variability of the generation. KAVULLA If you are talking about a ratio of 4,000 megawatts of wind to 10,000 of load, that’s difficult to integrate. If you increase the size of wind to 6,000 megawatts but then integrate or balance it over 20,000 megawatts of load, suddenly it becomes a lot easier. That’s not a situation people really had to worry about in the status quo ante but it is something that people in the West are looking at more closely.
FOX
Our diversity is our strength. We rely on coal for about 45 percent of our energy in Arkansas, 30 percent is nuclear and about 20 percent is gas. HONORABLE
In Ohio, we’re in a situation where our diversity is entirely drawn by market. We’re headed ultimately where our auctions determine what the balance is going to be. We had have two plants close down in an area that caused a constraint in northern Ohio two to three years ahead of any EPA requirement imposed upon those plants and it was totally market-driven. As soon as those plants were offline then must-run contract come on the RTO so they stay online while our customers in northeast Ohio are tasked with paying for new transmission to keep these plants operating. ROBERTO
HONORABLE
Our reliance in natural gas has grown tremendously. It raises huge issues in terms of reliability. At one of our largest coal plants, the capacity factor went from 85 percent down to 35 percent in the last year. It raises a host of issues. ROBERTI
How much will the outcome of this year’s presidential election shape EPA policies? ENERGYBIZ
If you look at the pattern of these rules, EPA didn’t race to put them out. In each case they were drawn out after litigation by environmental groups that said, “EPA, you’re not living up to the obligations that have been thrust upon you by the Clean Air Act and by the Clean Water Act.” It is going to require congressional action to revoke portions of significant environmental protections that have been in place for a long time. ROBERTO
JONES
I worked for the EPA under President Clinton for seven years as a regional administrator. I took this job 10 years ago because of climate change. Those laws, since Richard Nixon started EPA, were always bipartisan. Those laws are not perfect but they are health-based. FOX
What we are talking about here is ensuring that the people who live in America have clean air and clean water. There is no politics in that. Furthermore, the utilities HONORABLE
KAVULLA 22 E N E RGYB I Z November/December 2012
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energybiz.com E N E RGYB I Z 23
T H E R E G U L AT O R S
that I’ve visited with in Arkansas with regard to EPA regulation are not saying we don’t need these laws. They are saying we need more time to implement them. KAVULLA These EPA rules reflect federal laws but there is a lot of wiggle room in some of them. The coal combustion residual rule is going to be determined by the next administration.
We’re economic regulators fundamentally. We set just and reasonable rates. We’re not environmental regulators. So I would agree with the other panelists that there is a certain amount of stability in the regulations. But with the sequence of them, how you do them, there’s a lot of uncertainty. JONES
KENNEY
ENERGYBIZ How do you view the future of transmission planning in the country? KENNEY Our role as state regulators is to ensure that costs are being appropriately allocated.
NAZARIAN
NAZARIAN There is a trend toward including important policy considerations other than purely reliability and transmission planning. There is going to be tremendous uncertainty over the next few years about how those broad principles translate into reality in the different regions. At some point down the road we will be much better for having a more robust set of considerations going into transmission planning.
If you push a particular state too hard they are going to rebel. But I also think the Federal Energy Regulatory Commission Order 1000 is, on balance, a good order and it encourages regional cooperation on new public policy requirements. But there is going to be a lot of legal uncertainty. Each region is going to propose different types of compliance filings. In addition, the Department of Energy is asking us to implement a vision of the grid by 2050 with a lot of intelligence built in. There’s no consistency and this creates problems for us as regulators. Ultimately, where the rubber meets the road is with us because we have to put all of this into rates. JONES
ROBERTI
Perhaps we will get to a tipping point where the backlash will be very strong. ROBERTI
The focus should be on where should the transmission be built. HONORABLE
We’ve gone away from the old model of centralized integrated resource planning. Whatever its virtues and whatever its problems, at least you could look holistically at a system you were trying to regulate and figure out how to solve problems. Now we maneuver within these swirling sets of regulatory spheres. NAZARIAN
ROBERTO 24 E N E RGYB I Z November/December 2012
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26 E N E RGYB I Z November/December 2012
Pioneering
Government Research BR IDGING INNOVATION GAPS BY RICHARD SCHLESINGER
FOR NEARLY FOUR YEARS, the government has attempted
to steer energy innovation as part of its overarching effort to end a nasty economic downturn. At the heart of that effort stands the Advanced Research Projects Agency-Energy, ARPA-E, modeled after DARPA, where the “D” stands for Defense. Like DARPA, the highly successful Defense Department agency responsible for spurring such innovations as the Internet and the stealth technology found on many advanced aircraft, ARPA-E is a Department of Energy agency devoted to bridging the gaps between various stages of scientific research and large-scale, socially transformative commercialization. ARPA-E was created in 2007, but it wasn’t funded until President Barack Obama included it in his 2009 Recovery Act stimulus bill, with a budget of $415 million. In just three years, ARPA-E has awarded almost 200 grants, usually just $2 million or $3 million each, in 12 basic areas, including nextgeneration storage technologies, alternatives to rare earth materials for developing advanced motors and generators, and grid-scale highvoltage hardware and software. Eleven projects funded by ARPA-E for a total of $40 million have already generated private investment of $200 million, a stunning measure of success. Arun Majumdar, ARPA-E’s first director, placed a premium on recruiting the best, most innovative research scientists to staff the agency. According to Julio Friedmann, the chief energy technologist at Lawrence Livermore National Laboratory, who is part of an ARPA-E funded team working on better carbon capture technology, Majumdar
“saw his primary job as getting very, very talented people in the shop.” And, as with everything else at ARPA-E, time was of the essence. Knowing that the usual hiring process at federal agencies can be burdensomely complex and prolonged, Majumdar asked for and was granted the ability to hire and fire outside conventional government rules. As a result, ARPA-E has been characterized, right from the basic hiring stage, by speed and flexibility. Another key to ARPA-E’s success is its practice of easily and casually moving across traditional discipline boundaries. Each of its 12 research areas is headed by a scientist specializing in that field. But the various program directors, as they are called, regularly meet to discuss possible concepts that might intersect their particular disciplines. And each director reaches out to the broad academic and industrial community within his or her field to tap scientists and technicians for insight into what the power industry really needs. Out of these meetings, requests for proposals are generated. This approach identifies concepts and technologies that are too risky for business to undertake and too complex for venture capitalists to identify, much less fund. ARPA-E’s BEEST program (Batteries for Electrical Energy Storage in Transportation), for instance, is funding efforts to dramatically increase the power versus weight ratio of batteries used for electric and plug-in hybrid vehicles. According to program director Dane Boysen, the goal is not an incremental improvement on current lithium-ion technology. “We go out and look for chemistries that offer two, three, four times the theoretical potential of between 250 and 350 watt-hours per kilogram. Essentially, we’re looking for game-changing technologies that are just too risky and seemingly too far off for people in the private sector,” Boysen said. In other words, ARPA-E is attempting to bridge the gulf between the tried-and-true technology of energybiz.com E N E RGYB I Z 27
PIONEERING
today that might offer incremental improvements and the next-generation science that will provide a quantum leap in real performance. But bridging gaps is a team effort, and a defining quality of ARPA-E is its ability to assemble teams that might not otherwise exist. The agency’s Innovative Materials and Processes for Advanced Carbon Capture Technologies program has funded a project intended to bridge the gap between the zone of applied science and development. To do it, ARPA-E assembled a team consisting of the Lawrence Livermore National Laboratory, Babcock & Wilcox, and the University of Illinois. They submitted a proposal to capture carbon using much less energy than is currently needed, THE FEDERAL ENERGY REVOLUTION and they drew their New Directions in R & D model from the way The era of massive subsidies human beings use an may be waning, but the federal government is putting its amine as a catalyst mighty resources behind a new to separate carbon vision for America’s energy dioxide when they future. Learn how by joining our webcast discussion noon ET, breathe, and the Dec. 20. Register for this free process uses very webcast at www.energybiz.com/ government . little energy. The goal Be a part of the ongoing is to find a catalyst discussion at the 2013 to capture carbon EnergyBiz Leadership Forum in Washington March 18-19, with much lower www.energybizforum.com . energy penalties than current chemistry technology. The first step in the process, according to Friedmann of Lawrence Livermore, was to design these catalysts in a computer, create them and then test and demonstrate that they would perform as calculated. The second phase would be to functionalize them. “We figured out ways to do that with microencapsulation and by tethering those catalysts to surfactants. Then, we wanted to demonstrate them and scale them up, which is the issue of finding the pathway to commercialization,” Friedmann said. The three steps are typical of the innovation cycle, a typically expensive, lengthy process, often lasting 10 to 20 years. ARPA-E accelerates the process by building bridges over what otherwise would have been long and circuitous routes and moving from an interesting design to precommercial pilot testing in just three years. By putting a university, a national lab and a company together, ARPA-E creates an innovation ecosystem that can accomplish what none of them, by themselves, could do in nearly the same amount of time. To bridge these gaps, say between basic 28 E N E RGYB I Z November/December 2012
science and applied science, or between applied science and development, is to achieve a rapid transition to real, gamechanging commercialization. Friedmann is among a host of people working in the energy field who credit founding director Majumdar with designing an agency that filled a crucial gap. There was plenty of basic science being done in chemistry and physics, often on the atomic level, by universities and national labs, and there was no dearth of efforts to commercialize already demonstrated technology funded by corporations or venture capital. But the road to game-changing innovation is filled with potholes that threaten to slow progress and break an axle here and there. Majumdar saw it as ARPA-E’s mission to fill those potholes, to bridge those gaps so that the road to change could be infinitely smoother and faster. Majumdar resigned his position in June, after serving almost three years, the time frame that defines the entire agency. Just as projects have three-year deadlines, with milestones that must be met along the way, staff appointments are also for three years. He brought a level of insight and commitment that won tremendous respect from academia, industry and, not least important, Congress. Partly because of the emphasis on assembling diverse teams, ARPA-E projects have a presence in 34 states, and Majumdar spent countless hours walking the halls of the Senate and the House, talking to staffers and members, finding common ground, listening to concerns and representing what ARPA-E was doing in clear, focused language. Majumdar’s acting successor, Eric Toone, has said that his main priority is to continue to recruit top scientists, and he’s already proposed a number of new research programs. Again, the proposals are game-changers: a search for lighter and stronger materials to improve vehicle efficiency; denser biofuel crops; and ultra-low-cost hydrogen, obtained either by splitting water more efficiently or by stripping hydrogen from other sources. Whether he can win widespread support among industry, academia and Congress that Majumdar enjoyed remains to be seen. But the legacy of ARPA-E is already assured. At the agency’s 2012 summit, FedEx Chairman and CEO Fred Smith said, “Pound for pound, dollar for dollar, it’s hard to find a more effective thing the government has done than ARPA-E.”
Pound for pound, dollar for dollar, it’s hard to find a more effective thing the government has done than ARPA-E.
New Frontiers
for a Transforming Grid ENH ANCING R ELI ABILIT Y BY RON MELTON
OUR
POWER
SYSTEM
IS
CHANGING.
Historically, we’ve operated the supply side of the power system deterministically. We estimated the load and then dialed in the required amount of generation. The U.S. Department of Energy said that 32 percent of added generation in 2011 came from wind energy. The supply side now includes large quantities of renewable resources that are
intermittent in nature. They are somewhat but not completely predictable. The supply side has become stochastic. The load side has changed, too. It is still stochastic, but it is also becoming intelligent. The number of communicating and sometimes intelligent devices capable of changing their energy consumption patterns is growing. New loads in the form of electric vehicles have energybiz.com E N E RGYB I Z 29
PIONEERING
Transformation is clearly upon us, calling for profoundly different approaches.
consumption patterns that must be managed to avoid peak load growth. While still stochastic, the load side is now capable of responding to information and adjusting consumption behavior in useful ways. Finally, the grid itself is changing with the introduction of distributed energy resources. These resources require bidirectional power flows and in the long run will be intelligent and communicating. Transformation is clearly upon us, calling for profoundly different approaches. One such approach, referred to as transactive control, will provide the opportunity to leverage smart devices to operate the grid with greater precision and efficiency while optimizing generation and end use to unprecedented levels. Through its role leading the largest regional smart grid demonstration in the nation today, the Battelle Pacific Northwest Division and its partners are developing and deploying a transactive control and coordination technology as a key component of the Pacific Northwest Smart Grid Demonstration Project funded by the American Recovery and Reinvestment Act. The team is building on previous, pioneering work by the Department of Energy’s Pacific Northwest National Laboratory, which first tested the transactive control concept in the GridWise Olympic Peninsula Demonstration — the “Oly-Pen” project. In Oly-Pen, PNNL for the first time successfully demonstrated the use of real-time pricing to retail customers as a tool for managing grid constraints. Working with the Bonneville Power Administration, the follow-on demonstration project was conceived to scale up the technology and demonstrate regional interoperability, 30 E N E RGYB I Z November/December 2012
with the notion of addressing several of the changes outlined above. This project has a total budget of $178 million with $89 million of federal funds and a match of $89 million from the project participants, including BPA and participants from 11 utilities located in the states of Washington, Oregon, Idaho, Montana and Wyoming. The technology development effort includes five providers, including IBM Research, IBMNetezza, Alstom Grid, 3TIER and QualityLogic. The transactive control and coordination technology being developed and deployed on the demonstration project directly responds to today’s new grid boundary conditions. Transactive control is a distributed system using a transactive incentive signal and a transactive feedback signal that provides global information to local decision making at any point in the power system. The system essentially opens up a two-way line of communication between generation and load that previously didn’t exist. This communication follows the flow of electricity, enabling local decision-making at any point where the flow of electricity may be modified. Through this approach, grid conditions throughout the system may be taken into account to coordinate the behavior of generation resources, loads and distributed energy resources. If we could visualize the conversation that load and generation were having using this system, we would see the supply side originating an incentive signal, communicating the expected future cost of delivering power to specific locations and taking into account system conditions along the path from supply to load. Once received, the demand side reacts to the price incentive and replies by sending a feedback signal, communicating the energy consumption plans in the future. In a simplified way, a wind turbine could say to the system, “At 3:00 a.m., I have a lot of energy. It will be a bargain.” Your car, seeing lower prices, would reply, “I will plan to charge then, because power will be cheap.”
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Through the use of a basic five-minute forecast interval, the transactive control approach also allows us to reflect the intermittent fluctuations of wind energy due to natural variations in wind. As the example hints, transactive control can help support the integration of renewable energy and the engagement of new loads without straining the grid. Let’s look at these two characteristics in detail. Over the next couple of years, the amount of wind generation in the Pacific Northwest is projected to double. Future regional wind capacity of about 12,000 megawatts will equal the amount of hydropower generated by the federal dams along the Columbia and Snake rivers. In a way similar to the mock dialogue above, transactive control engaging the responsive assets helps to balance the intermittent nature of wind energy and allows optimal operation of generation resources such as the hydro system. Transactive control is also capable of incentivizing the consumption of renewable energy when it is most abundant. This feature will help reduce the amount of “spilled” wind power — excess windgenerated electricity that has to be curtailed. Our system also allows responsive assets, such as electric vehicles, to engage without straining the grid. As an example, we could think of a pole-top transformer serving a number of electric vehicles. If the transformer is overloaded, its service life will be reduced. To avert that, the transformer increases the forecast value of the incentive signal based on its current state, weather conditions and feedback from the vehicle chargers about future charging plans. The forecast increase in incentive signal value will cause vehicles to modify their plans, thus
Transactive control can help support the integration of renewable energy.
32 E N E RGYB I Z November/December 2012
decreasing the strain on the transformer. When the transformer changes the future value of the incentive signal based on the charging plans, the plans may change as a result. Because the system is a form of closed-loop control, convergence of the give and take between incentive signal changes and charging plans may be ensured through careful algorithm design. PNWSGD is testing the technology on a limited scale with about 12,000 smart grid-responsive assets, which include water-heater load controllers, solar panels, battery storage units, and backup generators. This fall, our transactive control system will go live and allow the installed assets to start responding to electric power system conditions. During the project’s two-year data collection and analysis period, we will be working to confirm that the transactive control technique offers the operational benefits described here and to estimate the benefits of regional scale-up. In addition, the data we gather over the next two years will help us improve our knowledge of how the nontransactive smart grid technology deployed by the 11 utilities performs, identify what types of technologies will best suit our region and evaluate how the expected benefits could be spread through deployment beyond our current footprint. Starting this winter, status updates will be available on our website, www.pnwsmartgrid.org. As the boundary conditions have changed, power system operators are challenged to ensure that we continue to receive reliable electricity regardless of whether it is green, used by new loads, or flowing from distributed energy resources at points throughout the system. Transactive control is our answer to this challenge. Adapting to the changing boundaries, we are taking a significant step that will move the nation closer to a more efficient, sustainable and resilient power system. Ron Melton is the director of the Pacific Northwest Smart Grid Demonstration project, the administrator of the GridWise Architecture Council and a senior technical leader for smart grid research and development projects at the U.S. Department of Energy Pacific Northwest Laboratory, operated by Battelle.
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» TECHNOLOGY FRONTIER
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Boardman Goes Biomass COAL PLANTS GET SECOND LIVES // BY WILLIAM OPALKA AGING, INEFFICIENT AND EXPENSIVE to upgrade, the Boardman Plant could have joined dozens of similar coal-fired generating stations consigned to the scrap heap of history as its owner prepared to permanently mothball its 600 megawatts in 2020. Instead, Portland General Electric is in the middle of a grand experiment to see if the plant in eastern Oregon can be successfully converted into the world’s largest biomass power plant. The plant dates from the 1970s and the utility already filed plans with state regulators to permanently shut it down because of the cost associated with bringing it into compliance with early 21st-century environmental mandates currently on the books and with any future carbon regulations. “The mandate allows a small opening for repowering, so we looked at biomass and natural gas, but its large Rankine cycle boiler is very inefficient for gas,” Jaisen Mody, PGE’s general manager of generation projects, said. “We started looking at biomass and 34 E N E RGYB I Z November/December 2012
looked at a technology called torrefaction, and the more we looked at it, the more it intrigued us.” But biomass power plants may fail because they don’t receive a consistent supply of fuel, which makes securing a long-term power purchase agreement difficult. There are other obstacles, mainly due to the plant’s size. “On paper, it looks like it will work, but no one has demonstrated that on a boiler like ours with 100 percent fuel switching,” Mody added. The plan is to complete engineering studies and reconstruction of the boiler, so that a test burn could be performed over a few days in 2014. Emissions data would be collected and operational issues would be assessed. The Electric Power Research Institute is the research partner with PGE in the project. If the tests prove successful and the emissions data falls within certain parameters, the permitting would be pursued and the project would be completed over several years. But as PGE emphasizes, that’s a very big “if.”
The other challenge is fuel sourcing. A baseload plant of this size will require 4 million tons of green biomass, so the plan is to run the plant at 100 percent power for six months of the year when it’s needed the most. This is where local sourcing of green biomass and the torrefaction process come in. Torrefaction is a charring process of agricultural material that essentially removes moisture — roasting it in the absence of oxygen — that creates a brick-like material that could be described as green coal. It could be thought of as a half-step below turning wood into charcoal. PGE believes it has found a grass that will be better than coal, which burns at 8,400 BTUs per pound. PGE is investigating many potential plant sources, but it believes it has found one that burns at 10,000 BTUs per pound. Wayne Lei, director of research and development, said the utility found a nearby university that had been experimenting with a plant that can replace hardwood fiber in pulp production. “It came to our attention that University of Washington was testing a plant called arundo donax, a perennial grass that grows faster, like a switchgrass, but it’s the most productive in its class,” Lei said. The plant is prolific: An acre can yield 25 to 30 tons of the grass with a low moisture content. And with arundo donax having similar requirements for water and a growing season like alfalfa and corn, crops already grown in the Columbia River Basin, the local sourcing issue may be solved. Coal-to-biomass conversions under way or that have been successfully completed are well below the scope of the Boardman Plant. “Successful biomass plants tend to be under 100 megawatts,” said Bob Cleaves, executive director of the Biomass power Association. “Developers are challenged by making sure that the coal plant can be appropriately sized as a biomass opportunity as the two tend to be different. Biomass tends to be local in its supply and frankly few places exist that could accommodate a few hundred megawatts in biomass capacity.” DTE Energy has been one of the more active companies in the conversions of old coal plants during the past eight years, with the Detroit-based holding
Successful biomass plants tend to be under 100 megawatts.
company owning, operating or currently converting plants in three states. “We looked at the growing trend of coal plant shutdowns and decided that if biomass made sense, we were zeroing in on plants that could generate 40 megawatts to 50 megawatts,” said Steve Sorrentino, vice president, power and renewables. “If you’re looking at the 15-to-25-megawatt plant, that’s a tough economy-of-scale play in capital costs as well as in fuel acquisition.” DTE Energy has completed biomass conversions in Cassville, AUSTIN ADVISED Wis., and Bakersfield, Calif. Austin Energy has It has operating biomass power issued a report stating it plants in Woodland., Calif., can replace a coal-fired generating unit with a and Mobile, Ala. natural gas-fired unit, One of the first was according to an article in the Austin Americanthe Wisconsin project of a Statesman. 1950s plant that the Dairyland The change can be accomplished with Cooperative formerly owned minimal cost to the and that operated sporadically city, the report said. in recent years. After feasibility studies and a power contract with Dairyland, which was seeking renewable electricity, permitting came in a relatively quick 15 months. Operation started in late 2010. “If you can do this in the range of $1,000 per kilowatt, that’s one of the other drivers,” Sorrentino said. “When you build a new biomass plant, the number is $4,000 to $5,000 per kilowatt.” Not all conversions come that cheaply, and perhaps many are closer to $2,000 per kilowatt, but they’re worthwhile when there is a ready customer, as in the case of the ongoing Stockton conversion. The 45-megawatt plant’s output will be sold to Pacific Gas and Electric under a 25-year power purchase agreement. “PG&E is very aggressive with renewables,” Sorrentino said. And the plant qualifies under California’s renewable portfolio standard of 33 percent by 2020. The plant is on track for a late 2013 opening and will be supplied by tree trimmings and the like, as well as wood pallets and other so-called “urban waste.” So what is the future of coal-to-biomass conversions? “It’s going to continue, but I don’t think at the same pace as before natural gas became so prevalent,” Cleaves said. “We think there will be a greater trend toward co-firing as opposed to complete conversion. In smaller projects it makes lots of sense as small coal plants struggle to meet EPA mandates.” energybiz.com E N E RGYB I Z 35
» TECHNOLOGY FRONTIER Strengthening the Transmission Highway INVIGORATING AGING INFRASTRUCTURE // BY SALVATORE SALAMONE AGING POWER GRIDS are increasingly being stressed as operators must more frequently deliver peak loads to meet the demands of record high temperatures nationwide in the United States, meet the growing power needs in developing countries, and incorporate renewable energy sources into the mix worldwide. This, in turn, is driving the development of new technologies and varied approaches to better monitor transmission line conditions and improve the performance of existing lines. For example, the Electric Power Research Institute, through its overhead transmission program, is undertaking a broad range of research aimed at enhancing transmission line reliability and performance and at extending equipment life to defer capital expenditures. An institute-developed camera lets users see transmission line corona discharges during the daytime. This helps operators detect faulty components before they cause problems. Corona discharges are a telltale sign of faulty components. Unfortunately, the discharges are difficult to see in daylight. Trying to detect such discharges at night is expensive and often impractical. The technology used in the camera blocks out sunlight while capturing images of any corona discharges and related objects such as an interphase spacer or insulator. A special imaging process technique superimposes the corona image on the object image to indicate the location of a discharge. One provider used the camera to find cracked components. If the corona discharges due to these damaged components had gone undetected, the components would eventually fail and potentially disrupt service. Detecting the discharges with the camera, the operator was able to replace the components during a scheduled maintenance outage and thus prevent a possible service outage. Another example of the work being done in the industry is the move to composite materials to replace the all-aluminum or steel-reinforced aluminum transmission line cores. “Composite conductors 36 E N E RGYB I Z November/December 2012
can mitigate congested transmission lines, and offer electrical and thermal properties to reduce line loss and sag,” said David Bryant, director of technology at CTC Global. The problem that composites faced in the past is that to support higher capacity, many were designed to handle higher temperatures. But higher temperatures equated with increased line loss. Newer attempts address this problem. For example, CTC Global uses home-grown patented technology to produce a composite conductor called the ACCC conductor. When incorporated into a wrapped transmission line, it can double a line’s capacity while reducing line loss by up to 30 to 40 percent, according to the company. The technology is used in about 215 projects worldwide. American Electric Power recently agreed to purchase 1,665 miles of ACCC conductor to be used in the South Texas 345-kilovolt Valley reconductoring project. When it comes to improving transmission line performance and reliability, another area receiving attention is an attempt to add intelligence to the grid. To that end, Georgia Tech and startup company Smart Wire Grid have developed technology to help control power flow through a meshed network. The technology focuses on one of the factors that can limit grid capacity, which is that the total power throughput of a transmission network is bounded by the first line that reaches its thermal limits, even if the rest of the lines are underutilized. Devices the company calls Smart Wire modules can be easily installed on existing transmission lines to monitor and regulate power flow as part of a distributed flexible AC transmission system. Operators could change power flow by varying line impedance to shift power from a line in a meshed grid that is close to its thermal limit onto an underutilized line that has thermal capacity and line capacity to spare. This would allow an operator to use installed lines more efficiently and could increase the total power throughput of a network. These and other technologies are designed to help invigorate the aging transmission infrastructure.
UNDERSTAND THE RENEWABLE ENERGY CERTIFICATE (REC) MARKETS Expand your knowledge of the REC markets with the latest special report from Platts. Read this report to learn: • What are RECs and why they are important to the market • How RECs fit in the broader context of renewable energy policy • How RECs are traded and the market dynamics that impact pricing • How these concepts connect with real-life case studies Visit www.platts.com/rec-report to grow your understanding of the REC market.
» TECHNOLOGY FRONTIER Wave Energy’s Big Splash OREGON’S PIONEERING EFFORT // BY BELINDA BATTEN THE UNITED STATES has a golden opportunity to become a recognized leader in wave energy technology. No one need look beyond national media for proof of progress, with stories like the first Federal Energy Regulatory Commission license issuance for a wave energy project, and the Northwest National Marine Renewable Energy Center (NNMREC) opening its open-ocean test facility in Newport, Ore. As someone who is closely connected to this effort, I hope we take advantage of this opportunity for what it could mean for our energy future and economic development prospects. In 2008, the U.S. Department of Energy funded NNMREC as one of three university centers in Marine Renewable Energy. NNMREC, a partnership between Oregon State University and the University of Washington, has as its mission to advance wave and tidal energy technology. Faculty and students are at the forefront of research, education and testing that enable marine energy technology to grow. Their research closes gaps in understanding the technology, environmental and human dimension challenges, in addition to informing regulators of the impact of these devices when deployed in our oceans. As the director of NNMREC, I see firsthand the impact of this team on the industry. For example, OSU has two premier wave tanks in which developers test their pilot-scale devices, at times cycling from one
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38 E N E RGYB I Z November/December 2012
tank to another as they advance through development spirals. As device developers gain understanding of the technical performance of the devices, they transition to ocean testing. Recently, NNMREC opened our open-ocean test facility in Newport, and the first wave energy device to be tested (WET-NZ) was installed. The WET-NZ is connected through an electrical umbilical cable to NNMREC’s Ocean Sentinel, a mobile ocean test buoy. Although the new test facility represents a big step forward for developers, devices are limited to 100 kilowatts average power produced, and this limit is problematic for more mature devices. So what do developers do? Today, testing a utility-scale device, perhaps at 1 megawatt average power, in the most energetic wave resources available can best be completed at the European Marine Energy Center (EMEC) in Orkney, UK. At EMEC, devices connect to the electrical grid and developers learn about the power being produced in various wave climates, as well as reliability and sustainability of their systems in Orkney’s highly energetic waves. This isn’t a simple option for U.S. developers, who must endure high transportation costs. And unfortunately for those who are willing to ship their devices, EMEC’s wave sites are contracted through the next five years. To address these challenges, NNMREC is starting a U.S.-based EMEC companion: the Pacific Marine Energy Center (PMEC). We are working with Oregon coastal communities on site selection and are seeking funding for facility development. Upon completion, PMEC will provide another important resource for developers to move their technology toward maturity, understanding not only the device operation but also the environmental impacts and social acceptance. So, from my vantage point, the industry’s future is bright. But threats exist. In the 1970s, the United States was a recognized leader in wind energy. Altamont Pass Wind Farm in northern California was a showcase of these experimental designs. The United States established the
Ocean Sentinel at the test site, anchored. Photo by Jeff Basinger/Oregon Sea Grant
National Renewable Energy Lab in Golden, Colo., as a wind energy test center. When tax incentives and research funding decreased dramatically in the United States in the 1980s, so did the U.S. wind energy industry. Denmark, which had also been active in this industry, took the lead. Today, our wind farms consist of devices that were developed under European investment, with turbines manufactured by companies such as Iberdrola, Vestas and Siemens. OFFSHORE Wave energy technology is much GEORGIA Georgia is falling behind where wind was 30 to 40 years ago. other Atlantic states There is no one device recognized in developing offshore wind generation, as “the winner.” The best design will according to a report ultimately be decided based on cost cited in the Savannah Morning News. of energy, a quantity defined by a The National Wildlife complicated equation dependent Federation said that upon materials and manufacturing Georgia has the potential to develop costs, mooring and deployment 60 gigawatts of costs, operation and maintenance offshore wind. costs, and energy produced. But these are just costs’ technical aspects. There are also environmental impacts and opportunity costs incurred. Still, that does not capture the net cost, as arrays of these devices might have a positive benefit by acting as spawning areas for fish or crab. Moreover, there will be some devices best suited to onshore locations
where waves break, some in shallow and others in deep water, some that require rocky ocean floors, and others deployed in sand. If we fail to pursue wave energy development opportunities, we miss the new-industry economic benefits. The testing infrastructure and developer financing are necessary for industry growth, but jobs pair with investment as well. In Orkney, EMEC has produced an additional 221 jobs in 10 years. This is before any utility-scale manufacturing or development has taken place. I’ve been asked if private investment is enough to move this industry forward. We know from our history with the wind industry that it is not. We need federal investment in research to help developers push their devices through critical technology maturation development processes. Feed-in tariffs and power purchase agreements can help the wave energy industry like they have helped wind and solar. It might seem easy to succumb to a growing opinion: Renewables are not that important while we have cheap and available natural gas. However, in order to have a seamless transition to the renewable energy portfolio that will replace fossil fuels, we need to invest today. Belinda Batten is director of the Northwest National Marine Renewable Energy Center at Oregon State University. energybiz.com E N E RGYB I Z 39
Infrastructure Regains Spotlight as Important Investment for Reliable Future
I
nside of utility boardrooms, in the corridors of industry conferences, and, yes, within the pages of most industry magazines, there is a lot of talk about the future of the grid. In some scenarios, the smart grid has been labeled the future of power delivery; in others, the future is distributed generation. One truth holds regardless of who participates in the discussion: The current power delivery infrastructure could be enhanced to be better able to support today’s demands and the layering on of new technologies and applications. This isn’t a new topic or a new problem. Like a persistent toothache, we know 40 E N E RGYB I Z November/December 2012
it’s an issue. We know we should take a deeper look, and we know that it will eventually have to be addressed. But sometimes that’s easier said than done. Taking care of it could be simple or it could be complex; but, if left untended, it certainly would become painful. Like allaying a toothache, addressing the state of today’s power deliver infrastructure is necessary. The smart grid undoubtedly delivers valuable insight into consumer behavior and empowers both the consumer and the utility with more intelligent controls. The smart grid is, however, like the icing on a cake. The bulk of
the cake still, fundamentally, exists in a foundation layer of infrastructure. It’s the same basic breadstuff that Edison and Tesla tussled over, and it will remain the essence of this industry — namely, what is required to enable the reliable delivery of electricity. The details of reliability will comprise some of the interesting aspects of the power tale in the future, but the heart and soul of bulk electric delivery will remain transmission. With ongoing economic development, expansion of urban centers and, yes, even the evolution of the smart grid,
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transmission’s valued position in this industry continues to grow. The bottom line regarding the future of electric power is this: We have to make it, and we have to move it. Making it we’ve got covered. Moving it still needs help.
Looking at Transmission’s Challenges With disparate interconnections, a history of simply patching problem areas, and a lack of historic investment, the current North American power infrastructure is in need of upgrades. On average, nearly one-third remains active past the intended window of use, and nearly another one-third is quickly approaching the end of that window. In fact, the transmission and distribution systems in 300 of the largest metro areas are more than 50 years old. According to industry analysts, the increase in smart grid spending has been paralleled by an increase in transmission spending. Transmission now receives double the financial input it did just a few years ago, and growth is expected to continue for the next several years. But, the recent increase in transmission investment is not sufficient to address the requirements of these systems. Today’s growth in transmission investment evolved from sheer necessity: It simply couldn’t be neglected any longer. In April, the American Society of Civil Engineers (ASCE) released a report noting aging infrastructure issues and a need for investment, along with a declaration that investing in the movement of power is as important, if not more important, than investing in generation and smart grid details.
The ASCE anticipates investment of $566 billion through 2020. There are additional factors in the exponential growth of transmission investment, of course. Rarely does anything grow at two or three times an investment rate simply because it needs to. Often, such an increase stems from benefits or penalties, and transmission investment has both. Governmentbacked incentives, the promise of more renewable interconnection and the push in electricity demand are the benefits laid out for transmission investment — all rather “tit for tat” cash-based concepts. Working hand-in-hand with those positives are the cautionary elements of the Energy Policy Act of 2005 requirements, FERC and NERC reliability standards and FERC Order 1000.
renewable interconnections. Utilityscale solar facilities and wind farms tend to be distant from urban centers, and thus, rely on new power line builds to bring the energy to a center of use. Despite a few blows from the recession and the year-end expiration of the wind industry’s production tax credit, the renewable industry continues to move forward, especially in regions of the United States where the deadlines for government renewable requirements loom.
Peering into Transmission’s Crystal Ball
Earlier this year, for example, California’s Public Interest Energy Research (PIER) Program released its final project report listing transmission projects needed to meet California’s 2020 renewable portfolio standard, along with costs and development ideas. Even though the state faces an economic crunch, it continues to move forward with renewable development.
One of transmission’s largest growth areas centers on a need for more
While faced with its own set of challenges, renewable power
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production is projected by some studies to experience steady growth through the next decade or two. Pike Research studies estimate wind power investment in North America to top $145 billion by 2017, and just this summer, the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) released a study noting that every state has possibilities for renewable energy. Even the U.S. Energy Secretary Steven Chu believes in the growing power of renewables, stating in a recent Nature magazine article that with the right incentives in place, renewables could reach the 80th percentile of the market by 2050. As renewable development continues — and with ample resources and money to fuel investment — what remains is the need for transmission to carry it all to market. Transmission channels may be the chief incentive for renewables’ growth in this market. There are other emerging generation trends that have the potential to impact transmission infrastructure. As coal plants are retired, gas plant production has ramped up to take over the mantle of fossil-fuel’s frontline generator. And a new gas plant will require the construction of new transmission infrastructure to transport power from its generation site as well.
Transmission Expansion by the Numbers With or without renewables at the forefront, regional transmission organizations (RTOs) have initiated the early stages of extensive transmission investment strategies. The Electric Reliability Council of Texas (ERCOT) believes investment amounts in Texas will reach nearly $9 billion in the next five years, supporting the state’s Competitive Renewable Energy Zones (CREZ) as well as emerging 42 E N E RGYB I Z November/December 2012
fossil-fuel generation sources. That future investment layers on top of the $870 million spent on transmission equipment in the state since 2010. Texas is not alone in this investment wave. In January, the Southwest Power Pool (SPP) discussed 479 potential upgrades within its area — an investment expected to surpass $7 billion. In April, the Edison Electric Institute (EEI) released a report, “Transmission Projects: At a Glance,” revealing that member utilities plan to spend $64 billion on transmission through 2022. This will be in addition to the $77 billion allotted by members to transmission between 2001 and 2010. As noted earlier, the American Society
of Civil Engineers (ASCE) predicts the investment of $566 billion in transmission in North America through 2020. ASCE also noted in the same study that this billion-dollar amount isn’t enough to meet current and future transmission needs, leaving a multibillion dollar gap. So, as the industry focuses on the development of smart grid and other emerging trends, we are missing a key component for a positive energy future. Without updated transmission infrastructure to move power, the smart grid widgets needed to read and interpret the data associated with that power will be less optimal.
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made consistent the process used to plan the transmission system. No matter the definition, the truth is this: The rules of transmission building are changing. In May, the FERC upheld its Order No. 1000 reforms to transmission planning and cost allocation, a process that began in 2010. The preamble of this May decision called requirements outside of the order “inadequate” and noted that this inadequacy was a threat to adequate cost-effective development. This final word leaves utilities and merchant developers facing a number of rules, including a planning process that predicts cost allocation and an equal or positive return on investment. Regional transmission plans must be developed and must consider public policy and coordination among regional entities. And, the cost of transmission building must be spread among beneficiaries only, not across an entire consumer base.
Transmission’s Most Important Number: 1000 As transmission investment and upgrades become increasingly important, the billions of dollars invested and the miles upgraded take a backseat to a single government number: 1000. Federal Energy Regulatory Commission (FERC) defines Order 1000 this way: Order No. 1000 is a Final Rule that reforms the Commission’s electric transmission planning and cost allocation requirements for public utility transmission providers The rule builds on the reforms of Order No. 890 and further enhanced, clarified and
For the average utility dealing with the details of FERC Order 1000 and working to determine (and move to) what’s next, the first step is compliance planning — laying out an approach to fully comply with the order. The process begins by identifying regional organizations and researching what’s been done in that region, what’s on the books (even with distant neighbors) and what public policy will require in the next five years. Then, the examination turns inward. Which departments need to be involved? What resources need to be re-allocated? What cultural issues need to be addressed to make this process as transparent as possible going forward? Most utilities already will have the employee base needed to create a
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compliance plan in-house, from those familiar with regulatory issues to those familiar with operational issues. This isn’t about re-inventing; it’s simply an evolution. And, it’s very likely that FERC Order 1000 will spur a larger, more reliable electric grid that will benefit the industry as a whole — easing both the movement of power and the making of it.
A Look Ahead It will pay to keep an eye on the future: In the long run, look for new entrants to change the traditional culture. With that in mind, it will also pay to establish strategic partnerships for infrastructure building as the future of transmission becomes more open in market scope. As utilities navigate this post-FERC Order 1000 world they must realize the evolution: Transmission is no longer a “right of first refusal” environment, and it will become more dynamic, just as generation has over the last decade or so. Being prepared means planning ahead and working together across the utility (and interactively with vendors and supporters) as we plan an electric future where transmission serves as the backbone for a more reliable grid and efficiently delivers power throughout the future of power consumption. Quanta Services (NYSE: PWR) is a leading provider of specialized contracting services, delivering solutions for the electric power, natural gas and pipeline and telecommunication industries. The company provides a comprehensive range of services, including the design, installation, maintenance and repair of virtually every type of infrastructure. With approximately 19,000 employees, major offices in 40 states, and field operations across the United States and Canada, Quanta has the manpower, resources and expertise to complete projects that are local, regional, national or even international in scope.
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» INTRODUCING
Southern Leadership A CONVERSATION WITH THOMAS A. FANNING // BY MARTIN ROSENBERG Thomas A. Fanning oversees the Southern Company utility empire, serving 4.4 million customers across a broad swatch of the Southeast. The company is on the leading edge of development of a new generation of nuclear power in America with its Vogtle 3 and 4 units that are now under construction. Fanning, 55, chairman, president and chief executive officer of the company, is not shy about making a splash at industry events, artfully and forcefully defining his vision for the future of his company and the industry. EnergyBiz recently sat down with Fanning to explore his views. His edited comments follow. Can Southern Company’s success in building the first two nuclear units in three decades in this country be replicated by others? ENERGYBIZ
It absolutely can be replicated. In fact, we may be interested in building more nuclear plants down the road. Every region has diverse generation resources. In the Southeast, the dominant solution is nuclear. This is not a business for beginners. You must have an outstanding track record in nuclear operations. You don’t measure success by whether you have challenges, but rather by how well you manage the challenges that will invariably occur. FANNING
ENERGYBIZ
What about clean coal developments?
We are the only company in the industry still doing robust proprietary research and developFANNING
44 E N E RGYB I Z November/December 2012
ment. In Kemper County, Miss., we are building coal-based technology that we developed. We take low-grade fuel, we gasify it and we put in filters and strip out 65 percent of the CO2. The CO2 is then used in enhanced oil recovery. The facility essentially has the economic profile of a nuclear plant, with a relatively high capital cost but inexpensive energy and an environmental signature equivalent to or better than that of natural gas. ENERGYBIZ
Describe your generation strategy.
We spread our bets. The way our regulatory model is positioned in the Southeast, we deliver to our customers the cheapest energy we can find at any time. We always want to deliver low prices for our customers. The relationship between coal, gas and FANNING
We deliver to our customers the cheapest energy we can find at any time.
Photo Courtesy of Southern Company
nuclear changes over time, and it is important for us to have options in our energy portfolio. Recently, in light of historically low natural gas prices, we’ve made a historic shift. Five years ago, our generation was 70 percent coal, and now it is 35 percent. Five years ago, we were 16 percent natural gas, and now it stands at 47 percent. At our subsidiary, Georgia Power, we were able to reduce the fuel charge 19 percent and reduced overall bills 6 percent. All of that benefit — every penny of it — goes to our customers. But how can a utility order new nuclear generation when natural gas costs are at historic lows? ENERGYBIZ
FANNING Gas is a dominant solution for the foreseeable future, but it doesn’t mean you should put all your eggs in that basket. We are going to have to address emissions from an environmental standpoint. We have to build the infrastructure necessary to handle the growth. That either means expanding current pipelines or building new pipelines and storage. There are some rather historic decisions being made in America about the future of natural gas exports. What will that do to price? Significant demand curve shifts are taking
place. How far will that go? Another issue is credit. I believe we are the third-largest gas consumer in the industry; meeting our customers’ energy needs will require 2.5 percent of the nation’s gas supply. When I think about entering into a long-term supply relationship with some of the gas providers, you must consider their credit quality, and much of it is below investment grade. If you are forming a long-term supply relationship, there can be a credit risk. Returning to nuclear power, how many nuclear plants do you think could be built in the next decade? ENERGYBIZ
FANNING For us, Vogtle 3 and 4 nuclear units are scheduled to enter service later this decade. When I think about new nuclear units, probably by middecade is when they would begin. After that, it would be a continued build out. I could see Southern Company increasing several thousand megawatts of nuclear generation in the next few decades. Otherwise, all you are going to do is just bet on continuing natural gas price trends.
Will there have to be massive federal loan guarantees? ENERGYBIZ
energybiz.com E N E RGYB I Z 45
» INTRODUCING No, I don’t think so. If you have sufficient financial integrity and scale, then you don’t require loan guarantees. Loan guarantees were offered up along with production tax credits as inducements to pursue new nuclear, and those benefits are passed on to our customers. Do we, as a company, need loan guarantees? No, but loan guarantees were offered as a way to keep costs low and deliver every penny of benefit to our customers. FANNING
What will be the legacy of the Fukushima accident on America’s nuclear fleet? ENERGYBIZ
Fukushima is a historic event. It is an important event and one we must learn from, but there are a host of other things that we need to do as a result. The AP1000 design set out by Westinghouse is the safest technology on the planet. When Fukushima lost its external power source, the beepers and the fuel tanks went out and they couldn’t run the pipes and the pumps to get the water where it needed to be during the emergency. AP1000 does not require any of that. The water sits above the reactor and would fall into the critical part of the plant in an emergency. Even the Nuclear Regulatory Commission, in its 90-day report, suggested that the new technology being employed at Vogtle 3 and 4 would have obviated a lot of the problems that occurred in Fukushima. FANNING
Will nuclear power generate a growing share of our electricity? ENERGYBIZ
I can’t say with certainty what other companies are doing today. But nuclear is a dominant solution in America’s energy future. We can handle the used fuel; we can do all of that. This is America — and we are innovators. FANNING
ENERGYBIZ
What kind of national energy policy
is needed? I tend to take a minimalist position on these kinds of things. I’d be willing to give up all the tax benefits in existence today for a lower corporate tax rate. Whoever is in the White House, whoever is in the administration, the Senate or House of Representatives, we want them to be successful. We want the right answers for our customers. Our customers are our North Star in that they guide every decision we make as a company. We will participate relentlessly in national energy policy discussions to help ensure their needs are met. FANNING
46 E N E RGYB I Z November/December 2012
STATEMENT OF OWNERSHIPMANAGEMENT AND CIRCULATION (Required by 39 U.S.C. 3685) 1. 2. 3. 4. 5. 6. 7.
Title of publication: ENERGYBIZ. Publication No.: 0023-934. Date of filing: September 28, 2012. Frequency of issue: Bi-Monthly. No. of issues published annually: 6. Annual subscription price: Not Applicable. Complete mailing address of known office of publication (not printer): Energy Central, 2821 S Parker Rd., Suite 1105, Aurora, CO 80014. Contact Person: Sarah W Frazier, Telephone: 303-782-5510. 8. Complete mailing address of headquarters or general business office of publisher (not printer): 2821 S Parker Rd., Suite 1105, Aurora, CO 80014. 9. Full names and complete mailing addresses of publisher, editor and managing editor: Publisher: Mark Johnson, 2821 S Parker Rd., Suite 1105, Aurora, CO 80014. Editor: Martin Rosenberg, 8121 W 99th St., Overland Park, KS 66212. Managing Editor: Not Applicable. 10. Owner (Do not leave blank. If the publication is owned by a corporation, give the name and address of the corporation immediately followed by the names and addresses of all stockholders owning or holding 1 percent or more of the total amount of stock. If not owned by a corporation give the names and addresses of the individual owners. If owned by a partnership or other unincorporated firm, give its name and address as well as those of each individual owner. If the publication is published by a nonprofit organization, give its name and address.): Steve Drazga, 2821 S Parker Rd., Suite 1105, Aurora, CO 80014, Mark Johnson, 2821 S Parker Rd., Suite 1105, Aurora, CO 80014, Martin Hohmann, Kirchhertener Strasse 22, 52445 Titz, Deutschland. 11. Known bondholders, mortgages and other security holders owning or holding 1 percent or more of total amount of bonds, mortgages or other securities: None. 12. Tax Status (For completion by nonprofit organizations authorized to mail at nonprofit rates) Check one: The purpose, function and nonprofit status of this organization and the exempt status for federal income tax purposes: Has Not Changed During Preceding 12 Months. 13. Publication Title: ENERGYBIZ. 14. Issue date for circulation data below: Sept/Oct 2012. 15. Extent and nature of circulation: A. Total no. copies (Net press run): Average no. copies each issue during preceding 12 months, 22,368. Actual no. copies of single issue published nearest to filing date, 22,937. B. Legitimate Paid and/or requested distribution (by mail and outside the mail.): 1. Outside County Paid/requested mail subscriptions stated on form 3541. (Include direct written request from recipient, telemarketing, and internet requests from recipient, paid subscriptions including nominal rate subscriptions, advertiser’s proof and exchange copies): Average no. copies each issue during preceding 12 months, 18,536. Actual no. copies of single issue published nearest to filing date, 18,871. 2. In-County Paid/requested mail subscriptions stated on form 3541. (Include direct written request from recipient, telemarketing, and internet requests from recipient, paid subscriptions including nominal rate subscriptions, advertiser’s proof and exchange copies): Average no. copies each issue during preceding 12 months, Not applicable. Actual no. copies of single issue published nearest to filing date, Not applicable. 3. Sales through dealers and carriers, street vendors, counter sales and other paid or requested distribution outside the USPS: Average no. copies each issue during preceding 12 months, 20. Actual no. copies of single issue published nearest to filing date, 22. 4. Requested Copies Distributed by Other Mail Classes Through the USPS (e.g. First Class Mail): Average no. copies each issue during preceding 12 months, Not applicable. Actual no. copies of single issue published nearest to filing date, Not applicable. C. Total paid and/or requested circulation (Sum of 15b(1), (2), (3), and (4)): Average no. copies each issue during preceding 12 months, 18,556. Actual no. copies of single issue published nearest to filing date, 18,893. D. Nonrequested distribution (by mail and outside the mail): 1. Outside County Nonrequested copies stated on Form 3541 (include sample copies, requests over 3 years old, requests induced by a premiuim, bulk sales and requests including Association requests, names obtained from Business Directories, lists and other sources: Average no. copies each issue during preceding 12 months, 2,750. Actual no. copies of single issue published nearest to filing date, 2,785. 2. In-County Nonrequested copies stated on Form 3541 (include sample copies, requests over 3 years old, requests induced by a premiuim, bulk sales and requests including Association requests, names obtained from Business Directories, lists and other sources: =Average no. copies each issue during preceding 12 months, Not Applicable. Actual no. copies of single issue published nearest to filing date, Not Applicable. 3. Nonrequested copies distributed through the USPS by other classes of mail (e.g first-class mail, non-requestor copies mailed in excess of 10% limit mailed at standard mail or package service rates): Average no. copies each issue during preceding 12 months, Not Applicable. Actual no. copies of single issue published nearest to filing date, Not Applicable. 3. Nonrequested copies distributed outside the mail (include pickup stands, trade shows, showrooms and other sources): Average no. copies each issue during preceding 12 months, 889. Actual no. copies of single issue published nearest to filing date, 977. 4. Total Nonrequested Distribution (Sum of 15d (1), (2) and (3): Average no. copies each issue during preceding 12 months, 3,638. Actual no. copies of single issue published nearest to filing date, 3,762. F. Total distribution (Sum of 15C and 15E): Average no. copies each issue during preceding 12 months, 22,194. Actual no. copies of single issue published nearest to filing date, 22,655. G. Copies not distributed: Average no. copies each issue during preceding 12 months, 174. Actual no. copies of single issue published nearest to filing date, 282. H. Total (Sum of 15f and g): Average no. copies each issue during preceding 12 months, 22,368. Actual no. copies of single issue published nearest to filing date, 22,937. I. Percent paid and/or requested circulation (15C divided by f times 100): Average no. copies each issue during preceding 12 months, 84%. Actual no. copies of single issue published nearest to filing date, 83%. 16. Publication of Statement of Ownership is required and will be printed in the Nov/Dec 2012 issue of this publication. 17. Signature and Title of Editor, Publisher or Business Manager,or Owner: Steve Drazga, CEO, Date: September 28, 2012. I certify that all information furnished on this form is true and complete. I understand that anyone who furnishes false or misleading information on this form or who omits material or information requested on the form may be subject to criminal sanctions (including fines and imprisonment) and/or civil sanctions (including civil penalties).
» METRICS
energybiz.com E N E RGYB I Z 47
» LEGAL ARENA
BOULDER DEBATE
Go Muni RIPE FOR A NEW APPROACH // BY MATT APPELBAUM
[POINT]
OVER 40 YEARS AGO, Boulder, Colo., did something crazy. We became the first to approve a tax dedicated to purchasing Open Space, which led to a firm urban growth boundary even as we watched our neighboring communities grow and sprawl, and were told it was “obvious” that Boulder’s approach spelled economic ruin. Funny thing: our 70 square miles of Open Space — and our many other innovative and risky policies over the years — are critical components of a Boulder brand that attracts entrepreneurs and lands us on every “best of” list. Today our best-educated U.S. city status, along with perhaps the greatest concentration of climate scientists in the world, not surprisingly creates great community support for tackling climate change by reducing greenhouse gas emissions — and made us the first U.S. city with a carbon tax. So when our franchise with Xcel Energy, our investor-owned utility, came up for renewal, the time was ripe for a new approach. After considerable, unproductive negotiations, the city council decided to investigate alternatives. After significant technical effort, and working with a large group of community activists — including world-class energy experts — we asked our voters to create a municipal electric power company and fund the costly legal and engineering studies necessary. They agreed last November after an intense election in which opponents spent more than $1 million on an often-misleading campaign. We’ve been very clear about the goals of a muni: reliability, competitive and more stable rates, significant GHG reductions, renewables, local customer control and economic vitality. These are captured, with specific requirements, in the muni’s voter-approved charter. We don’t know if a muni will be financially feasible, and we won’t proceed if it’s not. We’re required to condemn the distribution system and deal with potentially thorny separation issues. We’ll need outside experts to run muni operations and acquire an energy portfolio. We must navigate through the largely uncharted waters of stranded costs. 48 E N E RGYB I Z November/December 2012
But regardless of much-exaggerated claims to the contrary, the engineering problems aren’t particularly difficult. Even the costs, which we have modeled extensively, aren’t daunting. However, the legal process is rather excruciating and expensive, lacking simple common-sense rules that would require the IOU to provide information, work cooperatively to minimize separation costs for everyone, and ensure rational, near-term energy planning to eliminate stranded costs. Which brings us to the why. Why municipalize? This is not about disliking the IOU. It’s not even about its flawed and overpriced SmartGridCity project, although incompetence and insistence on a ratepayer bailout certainly annoyed many. The most compelling factor, which ties together all of these issues, is our archaic regulatory system. No doubt it made sense decades ago when the goal was to promote huge expansions of generation and distribution facilities. Perhaps the guaranteed profit — which is now more than 10 percent at a time when long-term bonds yield only 2 percent — on capital projects was necessary. Maybe the assignment of virtually all risk to customers was appropriate. Presumably, the glacially slow process, skewed entirely in favor of the IOU and prioritizing the status quo well past its sell-by date, kept the electrons happily moving. Welcome to the 21st century and the rapidly changing energy environment, where even our uberpoliticized, science-denying Congress will eventually implement a real carbon tax. Where being nimble is essential. Where clinging to old but profitable ways stifles innovation, energy independence and economic vitality. Where the 26 percent renewable portfolio standard, while an important step, is far too timid, particularly in GHG reductions and future requirements. Continued on page 50
BOULDER DEBATE
Forget about It BE REALISTIC // BY KEN WILSON
[POINT]
THE CITY OF BOULDER, cost on the Fort Collins, Colo., or COUNTER Colorado Springs, Colo., munis. COLO.’S, PLAN to municipalize Next, consider the money and time it electric distribution falls into the catwill take to fight Xcel over the next deegory of large projects that are wildly cade. In addition to the legal battle at optimistic. As a city council member I FERC, there will be legal battles in State Condemnahave found it frustrating that I could not convince a tion Court — which includes decisions on separation majority of my fellow council members that municipalcosts — and at the public utility commission. The PUC ization is a bad idea. will help decide who pays for much of this — the citiThere are more than 20 municipal utilities in zens of Boulder or Xcel’s ratepayers. The legal battle Colorado. However, they are all more than 50 years on both sides will cost well in excess of $10 million old, and none of them had to fight a and could be twice that. Should Xcel and its ratepaymultibillion-dollar company like Xcel ers foot the bill for any of that? As to the stranded to start their utility. In addition, none costs and separation costs, should the amount of them are rolling in money, and none that Boulder avoids be ultimately paid for by Xcel’s of them are performing as well as Xcel remaining customers? I remember an editorial in the on renewable energy and energy conDenver Post one year ago that prophetically asserted: servation, which are the main reasons “If Boulder wins, the rest of the state loses.” Boulder wants to municipalize. For the City of Boulder, I am also concerned about Boulder’s business case for the the opportunity cost of this endeavor. We are funding planned municipal utility does not the consultants and lawyers through a special tax that include any stranded costs that must be paid to Xcel will bring in $2 million per year for five years. Then and its ratepayers to compensate for generation facilithere are additional staff costs that are not included in ties built to support Boulder. Xcel believes stranded the $2 million. We also lose at least five years in our costs should be in excess of $300 million. The issue efforts to power the city with more renewable energy. would be settled by a protracted legal battle at the Other problems with the municipalization effort are Federal Energy Regulatory Commission, which is not less tangible. No city of our size has ever municipalized known for speedy decisions. In addition, the business during the Information Age. What would it mean for case allocates only $15 million for separation costs reliability and operations to lose the maintenance and (taking the distribution grid and severing the part that outage history of the distribution grid that is embedded serves the City of Boulder from the part serving the in Xcel’s operations systems? We would not have the rest of Boulder County). Xcel estimates this cost at same operations systems. If we did, Xcel would not $100 million or more. As a network engineer, and sell us the data, assuming we could pay for it. Finally, knowing a fair amount about how Xcel’s grid is laid what opportunities for leadership does the city lose out, I think $100 million may be low. by fighting with Xcel and its ratepayers for a decade There are other costs associated with municipalizainstead of collaborating with them on energy conservation. These include purchasing the infrastructure for tion, renewable energy and grid modernization? SmartGridCity, buying power as a small player and In this fight, the only winners are battalions of highly having operational expenses that are higher due to paid attorneys and consultants on both sides. The real loss of economies of scale. The most likely business losers are the enlightened energy goals that Boulder case has an additional $200 million to $300 million in claims to embrace. startup costs. It doesn’t make economic sense at that Ken Wilson is an engineering consultant and Boulder, Colo., city council member. amount. Think of dropping that amount of additional energybiz.com E N E RGYB I Z 49
» LEGAL ARENA
BOULDER DEBATE
Continued from page 48
And where building a huge, new coal-powered plant, retrofitting others to extend their lives, and scuttling inexpensive power-purchase agreements in favor of expensive new generation would clearly be absurd, except that it yields ever-higher short-term profits at no risk. So is exploring — and, we hope, creating — a muni too risky? Or, like our Open Space and so many other
innovative endeavors, is it far more likely that the status quo is much more risky? Should we just negotiate with the IOU and hope for the best? Should we wait endlessly until the regulatory structure creeps into the modern era? Or should we pursue our thoughtful, well-vetted approach to a less-risky and much brighter long-term energy future? Our voters, I think, chose wisely. Matt Appelbaum is mayor of Boulder, Colo.
As Xcel Sees It DON’T CHASE A BAD IDEA // BY JEROME DAVIS WHEN A CITY TALKS of taking over its electric utility, it is expected that the company providing that service will not support the move. Xcel Energy does not think Boulder, Colo.’s, effort to municipalize is a good idea — and not because we fear losing customers. Instead, we believe that we can help Boulder achieve its renewable energy and emissions reduction goals faster and cheaper than the long and expensive path of an attempted municipalization. Boulder has discussed municipalization since the late 1940s, addressing it every 20 years during franchise renewal discussions. Each time the city has approached us with its goals. In response, we have thoughtfully examined Boulder’s needs, how they relate to all Colorado customers, and have been able to successfully develop a plan that has benefitted everyone. This collaboration has made Xcel Energy a better company.
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50 E N E RGYB I Z November/December 2012
City leaders have decided to pursue municipalization once again and have laid out a five-point plan. The goals of that plan include: rate parity at the time of acquisition, although there is no long-term guarantee for customers; reliability matched to Xcel Energy’s current level of 99.98 percent; revenue sufficient to cover the city electric department/company’s operating expenses plus 25 percent of its debt payments; increased renewable energy; and a decrease in greenhouse gas emissions. Xcel Energy will meet the nation’s second-highest renewable energy standard of 30 percent by 2020. Meanwhile, Boulder has reported that it could take the city 20 years to meet its renewable energy goals if it forms a municipal utility, absent laying out a strategy or cost for acquiring those renewables. The current plan has not addressed what greenhouse gases and associated metrics would be targeted. Boulder customers may have to accept trade-offs in the process of municipalizing. This could mean more renewable energy at a higher cost and less reliability or lower cost but higher greenhouse gas emissions. The city will spend millions of dollars on lawyers, studies and consultants to get those answers before a single dollar is spent to take control of our system. Jerome Davis is regional vice president, Xcel Energy.
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» LEGAL ARENA
Neighbors Seize Power SOLARIZE PORTLAND // BY ANDRIA JACOB SOLARIZE PORTLAND begin in 2008 when Stephanie Stewart, a resident of the Mount Tabor neighborhood in southeast Portland, Ore., heard about the photovoltaic group purchasing campaigns that were then taking place in the Bay Area. An active member of her neighborhood association, Stewart saw an opportunity for that group to organize a similar campaign for neighbors to go solar together and obtain a discounted price on panels. The folks from the Mount Tabor Neighborhood Association turned to others for technical assistance and support, including staff from their district coalition office, Southeast Uplift, and Energy Trust of Oregon. A web-savvy designer, Stewart coined the term “Solarize Southeast” and created a website. Thus, the first Solarize campaign was born. Solar energy has a wide appeal to consumers, but people are often stymied by high upfront costs and complexity in the solar marketplace. The premise of Solarize is simplification of the solar purchasing process. Solarize efforts are characterized by three common elements. They are competitive contractor selection, community-led outreach with a trusted partner and a limited-time offering. Selecting contractors through a competitive process led by community volunteers eliminates the headache of contractor vetting and selection for individual homeowners. The process provides transparency and builds consumer confidence. Neighbor-to-neighbor appeals and communitysponsored educational workshops have proven to be extraordinarily successful means of engaging residents and shortening the PV sales cycle. This type of customer acquisition also saves contractors the expense of marketing, enabling them to offer even further discounts on the installation price. Portland’s electric utilities have supported the program with staff 52 E N E RGYB I Z November/December 2012
members who attend the workshops to explain interconnection and net-metering. The limited-time offering is a proven consumer sales tactic; nothing conveys a sense of urgency quite like a deadline. Within six months, Solarize Southeast signed up more than 300 residents and installed solar on 130 homes. The 130 installations added 350 kilowatts of new PV capacity to Portland and created 18 professional-wage jobs for site assessors, engineers, project managers, journeyman electricians and roofers. The Solarize concept quickly spread to other quadrants of the city. The Portland Bureau of Planning and Sustainability saw an opportunity to take the concept to scale and pitched the idea to the U.S. Department of Energy Solar Program. With support from the Energy Department, the Bureau has taken Solarize Portland to every neighborhood in the city and to communities across the state. During the past three years, Solarize has helped Portland add more than 1.7 megawatts of distributed EV CREDITS PV and establish a strong, steady solar The federal government installation economy. pegged anticipated In fact, Solarize Portland is so suctax breaks for electric vehicles to amount to cessful that Solarize campaigns have $7.5 billion over the next spread to communities in Massachuseven years, according to a report in the Detroit setts, Washington, Vermont and CaliforFree Press. nia. Communities wishing to undertake The government also said that the vehicles their own version of Solarize can now do will not in the short term so, thanks to the Energy Department’s have a major impact on climate change. publication, The Solarize Guidebook: A Community Guide to Collective Purchasing of Residential PV Systems, a how-to manual that details how community members can capture volume discounts through collective solar purchasing. The model has proven so successful that new twists on Solarize keep emerging, such as employerbased group purchasing programs. The Solarize story is far from over. Andria Jacob is a senior program manager with the Portland Bureau of Planning and Sustainability.
FCC Fees for Smart Grid A NEW HONEY POT? // BY DARRELL DELAMAIDE AS IF IMPLEMENTING smart grid technology didn’t have enough obstacles, the Federal Communications Commission recently raised another potential hurdle when it posed the question of whether it should charge a fee – say $1 a month per smart meter – for smart grid use of the broadband spectrum. The question came as part of the FCC’s effort to revamp the method of determining contributions to its Universal Service Fund (USF), set up by the Telecommunications Act of 1996 so that the agency can ensure that essential telecom services are available nationwide. Electrical utilities, not surprisingly, immediately rejected the notion. “Targeting smart grids with a new contribution obligation would run contrary to the public interest by unnecessarily increasing associated costs and delaying their deployment, which could lead some utilities to refrain from deploying them altogether,” lawyers for Edison Electric Institute, the industry lobby, wrote in a filing on the proposal. In addition to this practical objection, the Edison Electric Institute marshaled a range of legal and jurisdictional arguments against the measure. For starters, the group said, the machine-tomachine transmissions of smart meters in a smart grid do not fit the definition of telecommunications or telecommunication services. Moreover, smart grid technologies do not transmit any information to customers as “end users,” the criterion used by the Commission in its proposed rules for determining being assessable. Likewise, because utilities do not charge consumers a fee specifically for use of smart grid technologies, the transmissions don’t qualify as telecommunications services. To the extent utilities use third-party carriers for the transmissions, it is those carriers that would be the appropriate targets for a USF fee. For these reasons, the industry group argues, the FCC has no jurisdiction over such machine-tomachine transmissions. In any case, most smart grid technologies don’t involve interstate transmissions and so would come under the jurisdiction of state regulators rather than the federal agency.
On top of everything else, the EEI argues, the imposition of such a fee on utilities, which would have to be passed on to consumers in one form or another, “would create a regulatory and administrative morass,” triggering hundreds or even thousands of new ratemaking proceedings around the country. The National Rural Electric Cooperative Association also weighed in with objections similar to those from the EEI. “The administrative burden that would be placed on rural electric cooperatives ... far outweighs the minimal potential contribution benefits to the system,” NRECA says in its filing. The problem for the FCC arises from the rapid evolution in the number of players in telecommunications and the variety of services they offer. The agency’s universal service contribution system has not kept pace with these changes in “the communications ecosystem,” the FCC wrote in its notice of proposed rulemaking. This means that some providers subject to the levy are competing in the same markets as other providers that currently don’t pay, creating a competitive disadvantage. It also means the base for contributions to the USF is shrinking as consumers migrate to these other providers and services. In the notice, the agency is exploring the possibility of extending the number of services and companies subject to the contributions and the modalities for making the contributions. Currently, it is primarily the big telecom carriers that contribute and their contributions are a flat percentage of revenue. The question is which other service providers should contribute and whether contributions should be made on a per-device or per-connection basis instead of revenue. And that’s how we get around to the possibility of charging $1 a month per smart meter, following the FCC’s tentative suggestion for a monthly charge for residential and mobile wireless connections. The FCC must now digest the various comments and decide whether to issue an order. The telecom companies directly affected generally prefer an improved revenue model rather than a per-connection fee, which might make the whole smart meter issue moot. energybiz.com E N E RGYB I Z 53
» LEGAL ARENA Building New York State’s Energy Highway DEALING WITH AGING LINES // BY GIL C. QUINIONES NEW YORK STATE, the Empire State, possesses vast resources — natural, manmade and economic — that support its approximately 19.5 million residents. Among these assets is the state’s electric power system. However, while forecasts indicate that New York should have sufficient power supplies for the foreseeable future, the state is confronting a serious challenge: an aging electric infrastructure. Most of the electric transmission lines in New York were built more than 50 years ago, and many need to be replaced in the next 10 to 20 years. Moreover, 67 percent of New York’s generating facilities are at least 30 years old. Excess generating capacity, including renewable energy, is available in upstate New York, with demand concentrated downstate in New York City and on Long Island. But congestion at key points on the transmission system prevents available energy from reaching the high-demand areas. Gov. Andrew M. Cuomo recognized the need for a coordinated response to these challenges. In his 2012 State of the State address, Cuomo set forth his plan for an energy highway, a sweeping collaboration between the public and private sectors to upgrade and modernize New York State’s electric power system. The energy highway is intended to build New York’s next-generation energy infrastructure through billions of dollars in private investment. This initiative will drive economic growth and the creation of jobs while providing reliable, affordable clean power. We will focus on strengthening the highways and byways of the electric system, and also address issues surrounding generators entering and exiting the energy highway power system. These measures will complement the state’s aggressive and expanding energy efficiency programs. And they’ll ensure that New York is ready to accommodate greater-than-anticipated growth in demand, possible plant retirements and other factors. To implement the energy highway initiative, the governor established a task force comprising the 54 E N E RGYB I Z November/December 2012
leaders of the principal state agencies and authorities dealing with energy, the environment and economic development. The Energy Highway Task Force’s objectives are to reduce constraints on the flow of electricity and promote economic development, job creation and investment. It intends to expand the diversity of downstate power generation, enhance reliability of the electric system, reduce emissions and protect the environment, encourage development of renewable resources and increase the efficiency of power generation. The task force officially launched the initiative in April by holding an Energy Highway Summit in New York City, attended by more than 400 people. Federal, state and power industry officials, including Federal Energy Regulatory Commission Chairman Jon Wellinghoff, the keynote speaker, discussed the state’s energy challenges and means of meeting future demand. One week after the summit, the task force issued a request for information, seeking ideas for potential projects along with details on financing and development. The task force received submissions from 85 entities, which provided 130 suggested actions and ideas for improving New York’s energy infrastructure. The responses received from private develTRES AMIGAS HELP opers, investor-owned utilities, financial Tres Amigas says it is seeking a $2 billion firms, environmental groups and others industrial revenue bond included proposals for generation, electric from the city of Clovis, N.M., to help finance transmission and gas pipelines, as well an electric power as various ideas and policy suggestions. distribution center, according to a report in The proposals represented more than the Clovis News Journal. 25,000 megawatts of capacity from new and existing transmission and generation. The task force solicited public comment on the request for information responses. Based on its review of the responses and public comments, the task force is expected to release an energy highway action plan, with its recommendations, this fall.
» FINAL TAKE With the energy highway, New York will strengthen its commitment to lowering energy costs, growing its economy, promoting energy efficiency and reducing its carbon footprint. Beyond this, the energy highway initiative can serve as a model for other states looking to work with the private sector in rebuilding and enhancing their power systems. The country is at a crossroads in addressing its energy future. New York is not wait-
ing. We are moving forward to ensure that we will meet the energy demands of the next generation and beyond while strengthening our economy, creating jobs and protecting our environment. For more information on New York’s energy highway, visit www.nyenergyhighway.com. Gil C. Quiniones is president and chief executive officer of the New York Power Authority and is co-chairman of the New York Energy Highway Task Force.
The Road from North Dakota NAVIGATING FEDERAL, STATE TENSIONS // BY TONY CLARK SINCE BEING CONFIRMED to a seat on the Federal Energy Regulatory Commission this summer, I have been asked two questions more than any others. First, how does Washington compare with North Dakota? And second, what is your impression of how the role of a federal commissioner compares with that of a state commissioner? As to the first question, let’s just say the morning commute is trickier than it was in Bismarck. Whereas I formerly had a one-stoplight, five-minute commute, I now spend a fair amount of quality time on the roads of the greater metropolitan D.C. area. As to the second question, I have found that serving on a state regulatory commission is a wonderful background to have coming to a federal agency such as FERC. The suite of issues to be dealt with, the general administrative practices, and the stakeholders are substantially similar. But there are differences as well. The size of the agency itself is perhaps the most striking difference. Many, if not most, states have a modest-sized regulatory commission staff. In my case, I went from a staff of less than 50 in North Dakota, to approximately 1,400 in Washington. How cases are processed tends to be a bit different as well. My experience on a state commission was such that, in most cases, the commissioners
themselves had a role in proceedings from beginning to end. Commissioners directly heard testimony, developed a record through questioning witnesses and had a hand in writing orders from the drafting stage through a final vote. energybiz.com E N E RGYB I Z 55
» FINAL TAKE
On the federal level, most of the preliminary work happens at the staff level and among a corps of dedicated administrative law judges. The commissioners themselves are no less busy, but our work is focused toward the end of the process, often reviewing a record and a large body of legal work that is developed before the case reaches us for a final decision. I suspect much of this difference is attributable to the fact that the caseload for many state commissions is such that commissioners can be more involved in individual cases. In contrast, the sheer number of orders handled by FERC would preclude a five-member commission from personally guiding entire cases through from beginning to end. In many ways the nature of these somewhat different processes has reinforced for me the notion that different levels of government have different strengths, which can and should be deployed accordingly. States and state commissioners excel at the sort of fact- and locality-specific granular data gathering and record building that are the bread and butter of the regulatory world. Because of this, state commissions have traditionally been granted a tremendous amount of authority and ability to work on behalf of their citizens, and rightly so. At the same time, it is clear to me that there are certain endeavors of national importance that can be best handled by the federal government: wholesale interstate markets, industrywide standards, bulk system reliability and so forth. Although I understand there exists a natural tension between federal and state authority and this probably always will be so, I am not one to believe that any one level of government is inherently better suited to all duties than any other. 56 E N E RGYB I Z November/December 2012
Having now seen both sides of the federal-state relationship, I can tell you that there is no grand conspiracy on either side in which the respective commissioners and staffs are plotting how to take authority from each other. Rather, I have seen on both sides, groups of dedicated individuals working to implement laws and rules, sometimes imperfect ones, and serving the public interest as best they can. I am reminded that there is no perfect system, but I am more cognizant than ever that American leadership in the field of energy and its oversight has led to some of the greatest advances in health, safety and prosperity the world has ever known. Now, back to that D.C. traffic! Can someone please tell me the best route to avoid I-66 in rush hour? Tony Clark is a member of the Federal Energy Regulatory Commission.
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December 4-6, 2012 Sheraton Pentagon City Hotel Arlington, VA
Don’t miss this opportunity to hear leaders in the eastern grid weigh in on relevant key issues from grid security, HVDC projects, Eastern Interconnection transmission projects, post election implications, the future of transmission, what’s beyond FERC Order 1000, and more!
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Robert Mitchell
CEO and Founder Trans-Elect Development Company
John Lawhorn
Director of Regulatory & Economic Studies MISO
Michael Skelly President Clean Line Energy
Flora Flygt
Strategic Planning and Policy Advisor American Transmission Company
Terry S. Harvill, Ph.D. Vice President, Grid Development ITC Holdings Corp.
Frank Maisano
Founding Partner Policy Resolution Group Bracewell & Giuliani
Bob McGuire
John Flynn
Director, Transmission Projects Dominion Virginia Power
Vice President, Strategic Planning and Project Development American Transmission Company
Gloria Godson
Antonio Smyth
Vice President, Federal Regulatory Policy, Pepco Holdings, Inc.
President TranSource Energy
Patrick Miller
President & CEO, EnergySec Principal Investigaor, National Electric Sector Cybersecurity Organization
Katherine Prewitt Director, Planning Southwest Power Pool
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