By Courtney Barry

[Editor’s Note: As utilities and regulators consider how to meet evolving green-energy requirements most cost-effectively, they might begin exploring securitization financing mechanisms that utilities previously have used to recover costs from storm recovery, stranded assets and certain environmental obligations. Fortnightly covered this issue most recently in August 2008 (“Securitization, Mach II,” Paul Forrester, http://www.fortnightly.com/pdf.cfm?id=08012008_BusinessMoney.pdf). Contributor Courtney Barry provides an update from Texas.-MTB]

On September 10, the Texas Public Utility Commission approved securitization in the form of “ROC” (ratepayer obligation charge) bonds totaling nearly $540 million for Entergy Texas in damage recovery costs. Entergy says it will use the proceeds to recoup its costs resulting from hurricanes that struck its service territory in Texas and Louisiana in 2008. (The bonds include carrying costs of roughly $43.5 million, calculated at 10.86 percent per annum for 14 years.)

Just how are such bonds perceived by customers, the industry, and moreover, Wall Street? Quite favorably, as reflected by a Standard & Poor’s report this summer, noting that even during recessionary times, ROC bonds outperform ABS asset classes and are “insulated from the periodic budgetary process.” Additionally, S&P notes, the political environment “may be shifting in favor of ROC bonds as ratepayers recognize the projected lower funding costs associated with the bonds’ AAA ratings.”

But arguably ROC bonds benefit utilities most of all. “Ever hear the joke about the breakfast of ham and eggs? It’s similar,” says Joseph Fichera of Saber Partners, a Wall Street financial advisory firm. “The chicken is involved but the pig is committed. Here, the company is involved (Entergy), but the ratepayer is committed, and so is the commission.”

Fichera explains that the structure insulates Entergy from liability, because the company will get the proceeds from the bonds but it won’t get the bill. In this case, Entergy set up a special purpose transition funding entity called “BondCo” to handle the transition charges, issue the bonds, and then transfer proceeds back to Entergy.

Fichera adds that utility securitization bond characteristics sometimes are misunderstood. “Some people have labeled them as ‘asset-backed securities’ and have drawn comparisons with securitizations in the corporate market and the financial sector (i.e., credit card and mortgaged-back securities) that are inappropriate in comparison,” Fichera says. ROC bonds are “better,” he says, and are more comparable to government supported bonds. “These bonds have a particular government statutory guarantee,” he says.

However, association with other types of securitized financing instruments makes them particularly attractive to investors. ROC bonds deliver a better yield than their credit quality otherwise might support, because they’re sold in the securitization market, as opposed to the broader market for utility debt.

The Roots of ROC

ROC bonds for storm securitization costs started with Florida, then later in Texas and Louisiana. In Florida, FP&L originally asked for $1.7 billion in damage recovery requests for hurricanes in 2004 and ’05. The Florida Public Service Commission set recovery at $1.13 billion. Later, through a bond hearing, FP&L secured an additional $652 million. There was dissention because FP&L wanted to bump up the reserve much more than some interveners thought was necessary. But, says Charlie Beck, of Florida’s Office of Public Counsel, “Once they went to bonding, everyone was fairly supportive.” The commission initially reduced FP&L’s total allotment partly because it included surcharges that had been in effect for some time, and the commission wasn’t sure how to handle it in the novel ROC structure. “This being the first on the bonds, it took a long time to get it,” Beck said.

The question on the table now is: Why is this financing technique being used only to recover out-of-pocket costs for storm recovery? This was a hot topic over the summer at NARUC meetings.

“This is a very efficient, very low cost mechanism,” Fichera says. “Commissioners, ratepayer groups and others are asking, ‘Why aren’t we using this more, for traditional things like nuclear plants, capital expenditures, environmental mandates?’”

In fact some utilities are doing just that. For example, the West Virginia Public Service Commission recently approved Allegheny Energy’s request for $105 million in ratepayer obligation charge bonds to fund a scrubber project. However, few companies are likely to pursue ROC funding for anything beyond storm recovery and a narrow class of investments to meet clean air compliance obligations. This is because the ROC structure requires utilities to give up earnings with the project being financed, which creates a disincentive for companies that otherwise would prefer to build their rate base with traditional investment recovery mechanisms.

However, given growing cost pressures and government-mandated investment requirements, state commissions, ratepayer advocates and other stakeholders might start pushing utilities to use ROC funding more frequently. For example, in March 2009 the Natural Resources Defense Council suggested that the state of New York should establish a securitized-debt fund to finance conservation investments related to utilities’ efforts to achieve Regional Greenhouse Gas Initiative (RGGI) targets.

“Given potential rate shocks coming from capital expenditures to meet environmental and renewable energy mandates, this financing tool should be part of the mix with conventional financing,” Fichera says. With so many investment needs on the table,  the industry might work toward a compromise approach, allowing both ratepayers and shareholders to share in potential savings and get deals done.-CB

By Michael T. Burr

President Barack Obama on Oct. 1, 2009, asked the Environmental Protection Agency (EPA) to draft new rules for regulating greenhouse gas (GHG) emissions.

The announcement represents a challenge to Congress to push climate legislation forward quickly—in advance of the United Nations Climate Change Conference in Copenhagen, Denmark, scheduled for December 2009. The House passed the Waxman-Markey American Clean Energy and Security Act in June, which would create a carbon cap-and-trade program and would impose a federal renewable energy standard. The Senate is considering similar legislation, but whether it will reach a floor vote this year remains uncertain.

Of course, these developments are huge news for the U.S. utility industry, but they aren’t happening in a vacuum. U.S. climate policy has evolved during the past several years through a series of lawsuits and state and federal policy initiatives. Here’s how we got here:

2003-Present, RGGI Forms: Then-Gov. George Pataki of New York proposed creating the Regional Greenhouse Gas Initiative (RGGI). During the next several years, RGGI evolved into a coalition of 10 states that have committed to implementing a CO2 cap-and-trade program. RGGI started auctioning emissions credits last year.

2003-2007, Massachusetts v. EPA: The EPA denied a petition by several states asking the agency to regulate GHG emissions from new motor vehicles as a pollutant under the Clean Air Act. Petitioners appealed the EPA decision all the way to the U.S. Supreme Court, which in April 2007 ruled the states had standing as injured parties to bring the lawsuit, and clarified EPA’s authority to regulate GHGs under the Clean Air Act.

2005-Present, California Kyoto Pledge: California Governor Arnold Schwarzenegger signed an executive order in 2005 committing his state to reduce its GHG emissions to 1990 levels by 2020. “I say the debate is over,” he told delegates at the United Nations World Environment Day Conference on June 1, 2005. “We know the science, we see the threat and the time for action is now.” Of course Schwarzenegger was wrong; the debate wasn’t over. The Bush administration EPA blocked the state’s GHG rules, but this summer the Obama EPA reversed that ruling and allowed California’s standards constraining auto GHG emissions to go into effect. More California rules are expected next year, and more than a dozen other states are using California’s regulations as a template for enacting their own GHG constraints.

2003-Present, Connecticut v. AEP: In 2004, another group of state attorneys general filed suit against several electric utilities. In that case, the plaintiffs alleged the utilities’ CO2 emissions contribute significantly to global warming, a “public nuisance” under common law. And last month, on Sept. 21, 2009, the 2^nd Circuit Court of Appeals agreed the states have standing to sue under common law, and that the case should go to trial to determine whether the defendants’ emissions constitute a public nuisance.

2009, EPA Reporting Rule: One day after the 2^nd Circuit’s decision in Connecticut v. AEP, EPA Administrator Lisa Jackson signed a final rule that will require GHG emitters to start measuring and reporting their GHG emissions beginning in January 2010. Although the rule doesn’t establish limits or require reductions, it sets the stage for federal GHG regulations—whatever form they might take.-MTB

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Sept. 1, 2009

FOR IMMEDIATE RELEASE

Contact:
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Public Utilities Reports Inc.

Fortnightly 40 Survey: Utility Balance Sheets Strained by Growing Expenses, Declining Sales

 Cost pressures portend contentious rate cases.

Vienna, Va.: Share values among America’s utility, gas and power companies have outperformed the broader market since the financial crisis began one year ago. Maintaining this performance, however, might become more difficult in the months ahead, according to a report published in the September issue of Public Utilities Fortnightly magazine (www.fortnightly.com).

The fifth-annual Fortnightly 40 study, sponsored by Accenture, ranked the four-year shareholder value performance of U.S. investor-owned utilities (IOUs) and other companies active in electric power and gas industries. The C Three Group of Atlanta, which along with Public Utilities Fortnightly developed the F40 financial model, analyzed the annual reports of 85 companies to compare a series of shareholder-value metrics — such as profit margin, dividend yield, return on equity (ROE), return on assets (ROA) and sustainable growth.

Companies leading the F40 ranking this year included DPL, Energen and PPL. Ranked among the top 40 for the first time was NRG (32), and returning to the ranking after a year’s absence were Mirant (21) and AES (37) — three companies with heavy exposure in wholesale power markets. Conversely, Alliant and Northwest Natural Gas slipped to the bottom of the F40 after ranking in the high 20s last year.

The F40 metrics — combined with supplementary 2009 data — showed the industry remains financially robust despite a substantial decline in stock prices. Cap-ex spending among the Fortnightly 40 companies grew by nearly 30 percent in 2008, topping $49 billion, and the entire industry’s cap-ex increased 17 percent to nearly $94 billion. At the same time, equity returns among the top 40 companies declined only slightly, from 15.4 percent in FY2007 to 14.6 percent in 2008.

Notwithstanding these strong figures, economic forces are putting pressure on balance sheets. Kilowatt-hour deliveries have declined rapidly in many parts of the country — with residential consumption falling by as much as 8 percent in the second quarter of 2009, and industrial sales dropping at double-digit rates. These trends, combined with the costs of ongoing cap-ex programs, pushed the industry’s total net cash flow deeper into negative territory, from -$10.2 billion in FY2007 to -$19 billion in FY2008. Yet, despite this decline in free cash, utilities have continued growing their dividend payouts — albeit at a slower pace in the first half of 2009.

To protect dividends, companies are delaying spending projects and tightening operating budgets. “We’ve consolidated spending decisions among our plants,” said Paul Barbas, CEO of number-one ranked DPL Inc., parent of Dayton Power & Light in Ohio. “We have an engineering team for our entire business that stacks up investments on a fleet-wide basis.”

Additionally, some utilities have cut their payroll, and a few have been forced to slash dividends — a move applauded by rating agencies but abhorred by shareholders. The Fortnightly 40 study concludes that future financial performance — including the sector’s generous dividends — will depend as much on regulatory relationships as it does financial management.

“Utilities need regulators to make them whole for lost revenues, and also to finance the industry’s transition to a greener operating model,” said Michael T. Burr, Fortnightly’s editor-in-chief and the F40 study’s author. “The result will be rising rates — an unpopular move in any economy, and a political nightmare during a recession. Continued strong performance will depend on balancing customers’ need for clean and affordable energy supplies against utilities’ need for low-cost capital.”

The 2009 Fortnightly 40 Ranking
Copyright 2009, PUR Inc., Vienna, VA, All Rights Reserved. Permission to cite the F40 table in whole or in part is granted to publications that acknowledge the source as follows:

Public Utilities Fortnightly magazine, September 2009 (www.fortnightly.com). Sponsored by Accenture, with methodology and analysis provided by the C Three Group.

1  DPL
2  Energen
3  PPL
4  National Fuel Gas
5  Exelon
6  FirstEnergy
7  Entergy
8  New Jersey Resources
9  Southern Company
10  Questar
11* CLECO
11* Equitable Resources
13  Edison International
14* MDU Resources
14* TECO Energy
16  Dominion Resources
17  Public Service Enterprise Group
18* Allegheny Energy
18* Sempra Energy
20  AGL Resources
21  Mirant
22  Nicor
23  OGE Energy
24  UGI
25  NStar
26  South Jersey Industries
27  Delta Natural Gas
28  Centerpoint Energy
29* DTE Energy
29* PG&E
31  El Paso Electric
32* NRG
32* SCANA
34  WGL Holdings
35  MGE Energy
36  Vectren
37  AES
38  Northwest Natural Gas
39* Alliant
39* Ameren

* Indicates statistical tie among category ranks. Because the 39th position was a tie, the 2009 Fortnightly 40 contains no 40th rank.

PUBLIC UTILITIES FORTNIGHTLY (www.fortnightly.com), published by Public Utilities Reports Inc., in Vienna, Va., is the journal of record for the U.S. utility industry, providing authoritative, in-depth analysis of trends in generation, transmission and distribution of electricity and natural gas. For more than 70 years, Public Utilities Fortnightly has delivered exclusive interviews and expert analysis to help utility-industry executives and regulators decide where to invest, how the industry will be regulated and what the future holds. Subscription Rate: $169/year.

By Michael T. Burr

The London-based Institute of Mechanical Engineers (IME) published a thought-provoking report in August examining the role of geoengineering strategies for dealing with climate change. The report is interesting partly because of the technologies it examines, but mostly because of the policy argument it raises.

The report focuses primarily on three approaches, namely:

- CO2 scrubbing artificial “trees,” containing sorbents that would require subsequent burial;

- Algae-growth strips, attached to buildings and later harvested for biofuel production; and

- Reflective roofing, intended to direct solar radiation back into space and reduce AC demand.

Although these approaches seem novel and interesting, I’m not sure they really comprise geoengineering. The National Academy of Sciences defines geo-engineering as “large-scale engineering of our environment in order to combat or counteract the effects of changes in atmospheric chemistry.” Examples include seeding the stratosphere with reflective sulfur aerosols, or stimulating phytoplankton blooms by fertilizing ocean shallows with iron. By contrast, the hands-on, site-specific technologies discussed in the IME report would face a very steep growth curve before they could resemble “large-scale engineering.”

Quibbling aside, however, the IME report merits attention, if only because it makes an important point that’s been mostly ignored in the climate policy debate. In short, most discussions seem to position geoengineering as a “Plan B” approach to addressing climate change. In other words, if Plan A fails, and greenhouse gas (GHG) reduction and mitigation fall short of what’s necessary to avoid a climate catastrophe, then we’ll default to Plan B — direct intervention in the global climate, vis-à-vis geoengineering.

The IME report suggests that if we wait for GHG policies to fail before putting R&D resources into geoengineering, then it might be too late for geoengineering to work — or to be more precise, reining-in a runaway climate might require desperate geoengineering measures, incurring higher costs and yielding more damaging side-effects for the environment than we’d get with more moderate approaches. Instead, the report argues, policy makers should treat Plans A and B as complementary rather than exclusive approaches, and should consider geoengineering as part of an integrated strategy — a strategy that notably includes adapting to the inevitable climate change that already is happening and almost certainly will continue, to some degree, no matter what we do.

“Two decades of failed global mitigation efforts should be a wake-up call,” the report states. “It could be geo-engineering that provides the global community with those extra years to introduce effective mitigation and adaptation strategies, and, in the long term, remove some of the existing CO2 from the atmosphere. As such, Plan B needs to be upgraded to become a fully integrated part of a comprehensive three-point approach embracing mitigation, adaptation and geo-engineering.”

In other words, if we’re re-tooling for a more sustainable future, then we should make sure we’re using all the tools at our disposal — not just the ones that adapt our economy, but also the ones that adapt the climate itself. In the long term this might turn out to be the inevitable strategy, given the century we’ve spent gasifying the planet’s fossilized carbon. But that strategy will be cheaper and less damaging if we accept and pursue geoengineering earlier, rather than later in the process. -MTB

By John S. Ferguson

Alternative electric generation sources are all the rage as a consequence of mandates for minimum portions being from renewable sources and for limits on greenhouse gas emissions, as is demonstrated by articles in the June 2009 Public Utilities Fortnightly. “IOUs under Pressure,” shows ranges of levelized costs per kilowatt hour for eight renewable resources taken from the September 2008 Renewable Energy Data Book of the U.S. Department of Energy, and that wind, geothermal, biomass, concentrating solar, and photovoltaics have experienced significant cost decreases since 1980, and wind and geothermal aren’t expected to experience significant future decreases.

Mandating the use of alternative sources assures that they become part of the generation mix, as has already happened with wind and has always been with hydro. What happens in the future with the alternative sources other than hydro will depend in part on the impact of mandates concerning emissions of greenhouse gases (GHG) on fossil-fuel generation sources. “The Costs of Going Green” asserts that CO₂ emissions costing more than $30 per ton and natural gas prices of $7 to $8 per million Btu would shove coal down in the dispatch order and that any needed environmental control equipment would compound this situation, which likely would cause existing coal units to change their mode of operation or to be retired earlier than previously expected. Renewable resources may have a similar impact on combined-cycle generating units.

My interest in these mandates is their impact on depreciation accounting for power plants and transmission systems.

Base-Load Plant Depreciation

Past experience has long been recognized as being unlikely to provide a reasonable basis for determining depreciation rates suitable for existing power plants, and the common response has been to rely on predictions of generating-unit retirement dates. Mandates for alternative sources of generation and for GHG emission limitations will make it more difficult to predict the future generating unit usage needed to adequately depreciate power plants, and also have the potential for causing past experience to not provide a reasonable basis for depreciating transmission systems.

Coal-fired generating units historically have been installed for base load service and have shifted late in life to peak load or standby service. However, more recently such units have been refurbished instead of their mode of operation changing. The requirement of U.S. GAAP that depreciation (in this case the depreciation rate) match asset usage causes either course of action to impact power plant depreciation. Initially serving a base load function and later shifting to a peak load or standby function results in a distinctive lifecycle that dictates a pattern of depreciation rates that is higher during the early years of operation than during the later years. If refurbished for continued base load service, depreciation rates should remain about the same over the entire lifetime, even though midlife refurbishment requires substantial capital expenditures.

It hasn’t been difficult to predict generating unit lifespans and any related capital expenditures needed for calculating depreciation rates that are consistent with usage. However, mandates for renewable generation sources and greenhouse gas emission limits will complicate such efforts in the future, especially for coal units. It always has been difficult to obtain regulatory approval of power plant depreciation rates that are consistent with usage, and this difficulty had little to do with how easy or difficult it is to predict lifespans and future capital expenditures. Recognition that the future influence of the mandates precludes the lifespans experienced by coal units in the past from being useful for depreciation purposes might be obvious enough to dissuade those in the habit of proposing past lifespans in regulatory proceedings from doing so in the future or to dissuade the regulators in those proceedings from giving credence to such proposals.

Transmission Depreciation

There are two aspects to the potential for the mandates to influence the life of transmission systems. One is a consequence of transmission lines being dedicated to generation sites, and is unlikely to have much influence. The need for dedicated lines from remote wind farms is well known. However, wind farms are comprised of multiple units that are easily replaced after wearing out or becoming obsolete. Therefore, dedicated wind farm lines can be expected to be useful well beyond the lives experienced by the initial generating units, and the same situation is likely for tidal and wave resources. This situation is similar to what happened with transmission lines dedicated to remote hydro stations, where reservoir urbanization resulted in local load centers developing that continued to be served by the lines after local generation ceased.

The other aspect is a consequence of generation sites moving closer to load centers, and likely will influence transmission system life. This movement, currently in progress, is referred to as “distributed generation,” and began for reliability reasons. The speed of the movement will increase as a result of the mandates causing economic considerations to exhibit a less constraining influence in the future. My March 21, 1985 Fortnightly article, “Is Central Station Generation Becoming a White Elephant?” notes that improved technology brought central station generation into existence and likely will cause its ultimate demise. I credit Samuel Insull for developing central station generation as a result of his construction in the early 1900s of high-voltage transmission lines to connect suburban communities with power plants located at load centers in Chicago. This allowed large generating stations to be located remotely, thereby taking advantage of cost savings from economies of scale, load diversity, lower losses from higher delivery voltages, and the substitution of transportation of power for transportation of fuel. Mr. Insull’s “high” voltage was what is currently a common primary distribution line voltage.

In 1985 I expected PV modules or fuel cells to be the technology that would move the generation source back toward the load, but developments since then suggest that fuel cells are more likely to be utilized to mitigate GHG emissions from transportation sources than from electric generation sources. I asserted that regulation is an impediment to introduction of new technology, because entities operating in regulated markets can exercise some control over the timing of introducing new technology. The mandates demonstrate that regulation also can impose conditions for speeding up the introduction of new technology.

I also asserted that it was then time to begin considering the implications of new technology for the depreciation of power plants and transmission systems. The mandates since then and currently being considered have increased and will continue to increase the speed of developing and implementing new technology. Therefore, now is the time for those who have not already begun considering the implications of new technology on the depreciation of power plants and transmission systems to start doing so. It’s conceivable that technology eventually will make PV roofs and attic storage devices feasible, which might move the generation so close to the customer that distribution systems also would be affected. A significant unknown is the extent to which nuclear sources will be allowed to be part of the generation mix, because nuclear is unlikely to be anything other than a central generation resource.

These comments address depreciation accounting implications of the mandates, but there are also implications for feasibility studies of new facilities. What is even more interesting is the potential for the mandates to influence the future physical, organizational, and cost structures of providers of electric service.-JSF

Editor’s Note: Fortnightly interviewed Constellation Energy CEO Mayo Shattuck this summer. His comments were included in Fortnightly’s June Frontlines column. The complete transcript of the interview follows, as part of an ongoing series of conversations about managing during a time of fundamental change.

FORTNIGHTLY: How does the changing U.S. utility landscape affect Constellation’s strategic direction? How have changing markets and government policies factored into Constellation’s decision to sell trading businesses and generating assets?
SHATTUCK: A few macro trends are important to our strategy. The first, clearly, is that when the credit markets vaporized, certain businesses that we were in couldn’t be supported by the credit environment. It’s important for us to be an investment-grade company—particularly for a couple of the businesses we’re in, and less for another. Most utilities feel they should have an investment-grade rating because it leads to a lower cost of capital. Most state regulators would agree.

On the marketing side, marketing activity requires a daily posting of collateral. These numbers can move significantly with volatility in commodity prices. The change in the credit markets of last year and this year make it more difficult to support a commodities trading operation. To the extent you are focusing on marrying these two together, you’ll make sure you yield to an investment-grade company. But if you can’t make it in the market, you have to redirect your positions.

We took our non-core positions in commodity trading and gas trading and reduced the collateral associated with those by divesting them. That’s allowed us to get quickly to a place where we have three core businesses, and we have an investment-grade company and can march forward with a narrower scope—namely Baltimore Gas & Electric, our generation fleet, and our large-customer supply business, selling electricity and gas to large commercial and industrial customers. That’s the one that needs a significant amount of working capital, and therefore requires us to be investment grade and still have access to credit markets to support it. We’ve significantly reduced our exposure to trading operations.

The one business that doesn’t necessarily need to be investment-grade on its own is the merchant generation business. We are a merchant generator, but we’ve managed the balance sheet so we’re retaining an investment-grade rating.

The business of trading commodities and the depth of counterparties has changed. That’s another reason to pull back on exposures and markets. The liquidity and depth of these markets has changed. As a consequence, people participating in these markets have to reduce their exposure, or they could find themselves too big in some of these markets.

FORTNIGHTLY: How are you managing the regulatory changes happening in your service territory?

SHATTUCK: In Maryland, the issue that continues to be topical here is whether the deregulation of 1999 is working or not. We’ve been an advocate of competitive markets for some time, and are at the point of seeing the effect of falling prices on rates. That’s true in Maryland and Pennsylvania. Just at this moment the markets are beginning to respond to recessionary forces and also to other elements of competitive markets. We’re beginning to see falling prices, and the auctions taking place in PJM are yielding lower prices. So the debate about whether to re-regulate comes at an auspicious time, given how markets evolve under pure competitive forces. We’d like to see that continue, and see it across the United States.

Having said that, there is a certain degree of angst on the part of regulators and legislators about just how much time it takes for this whole process of deregulation to work. So there are advocates out there for certain kinds of re-regulation, developing a hybrid market. We have to engage in those discussions and consider whether there are certain elements of deregulation aren’t working well. That has been topical here in Maryland for a couple of years. We’ve been very willing to engage in that debate, even though we are advocates of competitive markets and are at the point where we should look to see what effects competition is having on rates in deregulated markets.

FORTNIGHTLY: As Constellation strengthens its alliance with EdF, how will the company be better positioned for success in the U.S. energy industry?

SHATTUCK: One of the reasons for the strategic alignment with EdF is to build up capacity for development of new nuclear. We’ve had a very effective partnership for three or three and a half years, and we keep pushing the ball down the road. They have an interest in having a greater footprint in the United States, so they have greater visibility to the markets, and understand where best to deploy their capital and their investment in UniStar with us.

We’re very pleased by this outcome, where they’ll own half of the existing nuclear fleet. It gives us a chance to have a significant partner to look for a variety of ways to ensure we can participate on the new nuclear side. All of us are respectively pretty small in the scheme of things to be building plants that can cost $10 to 13 billion. We have to think creatively about the alliances we need in order to do that—not just money, but skill and perseverance and links to other strategic partners.

We have a model that we believe allows us to participate in what we believe is an imperative to build a new nuclear capacity in the United States. We will stay in the game and lead the charge. We’ve been at it for four years. The DOE loan-guarantee program is going well, and we’re excited to be part of that process. Obviously we face challenges going forward, but we’re an example of a company that would be building a merchant plant and it will be exciting to see new nuclear happen as a merchant project.

FORTNIGHTLY: How does the trend toward green energy, conservation and distributed resources affect Constellation’s business plan?

SHATTUCK: We advocate for a realistic mix in generating capacity. This recent investment in the last 10 years in renewables has been fantastic, but we need to focus on the capacity of the grid to absorb and manage these intermittent resources. The model requires a balanced mix of all resources. Our attention to base load in the future is an equal imperative. We can’t lose sight of base load requirements.

It’s no surprise to anyone we have a balance of nuclear and fossil assets. We’ve tried to move the ball on efficiency and demand reduction and conservation. We have some innovative things happening in Maryland. We’re an advanced state, in the sense we’re already decoupled. We have incentives to help people reduce consumption—our Peak Rewards program. We’re moving down a path of the modern utility, where people are going to help the evolution of the grid by virtue of understanding their own use. We have the early starts of an AMI project, and we’re working on the early stages of things like smart grid and hybrid vehicles. All these things will make a huge difference in the long term, and every utility has to be looking at these things. I believe we are marching down a very progressive path on that front, and our state regulators are cooperative and interested in doing so.

On the competitive side of the house, where we’re selling power and services to large C&I customers, that business has grown to be quite large. We’re not only selling power and gas to these customers now, but offering other services associated with their participation in renewables. We’re installing solar panels, putting in distributed generation. That whole movement will be an important part of the future as companies like ours educate large C&I customers in how they can manage their energy use.

It’s part of our long-term business plan, balanced with strong low-cost base load power. That’s why we’re as involved as we are in the nuclear movement. But there is tremendous interest among customers in distributed generation, particularly for applications like peak-shaving, and improving their own environmental footprint. There are a lot of angles of attack that will drive distributed generation to play a more meaningful role, and hopefully that’s where technology and innovation also will play a significant role. My hope is that innovation leads to methods where we have much more capacity in much smaller sizes, hopefully in renewables technologies that will help society.

FORTNIGHTLY: From a management perspective, how are you managing the changes Constellation is going through? What are the most important issues that demand your attention, and how are you dealing with them?

SHATTUCK: The events of the last year clearly have been a distraction, but the operating units are doing just fine. There’s no reason for the operating units to be distracted. It’s the requirement of management to make sure they’re steadily focused on safety, reliability and their basic operations from a day-to-day basis. I think we’ve come through the stormy capital market period very well in that respect.

The areas of the company most affected were those being downsized as a result of the credit markets. The businesses themselves actually were doing reasonably well. It was the credit underpinning supporting them that dissolved. The difficulty is explaining to people that have performed well why they have a reduced amount of capital allocated to them, and they’ll have to go through a downsizing of employees.

As a result of the businesses we divested, most of those people ended up at Goldman Sachs, Macquarie Cook and EdF. Most of these people just transplanted themselves to their new owners, and that allowed us to devote capital to our new objectives. That was understood, and people felt good about how they were treated, but no question the specter of the credit and capital markets collapsing at the end of last year made everyone nervous. We had to change a lot of senior managers and put in place people that wanted to look out 10 to 20 years as opposed to thinking about what hedge fund they wanted to join. That all went very well. We made some management changes at the right time.

We’ve gone through the vast majority of the transition. In our last earnings call, we talked about a de-risking process, including divestiture. We’ll be proving ourselves in the next year as we downsize our participation in commodities markets.

FORTNIGHTLY: What aspects of the commodities business are you keeping?

SHATTUCK: We have a central service area to deal with the hedging requirements on the generation side and the customer supply business. We sell power around the country in places where we have no generation. That requires a sophisticated backbone of risk management. We have supporting operations for hedging of our generation fleet as well as megawatt hours that we sell to C&I customers. That’s the primary purpose of the operation now. It’s managing the remnants of what we now call the portfolio optimization book, which is really just the gradual reduction and elimination of the old commodities trading book. The market understands that.

FORTNIGHTLY: What have you learned from this transition at Constellation? What advice would you offer to a utility company CEO who is facing a similar set of challenges?

SHATTUCK: There were a lot of lessons learned in all of this. One of the main lessons is associated with the quality of our earnings mix. We tried to build a business based on this evolution of the competitive markets in the United States and internationally. At the end of the day, we weren’t successful at convincing people about the quality of earnings that fall into a bucket of trading earnings. They weren’t valued in the market place, so the additional risk associated with lower quality earnings wasn’t worth it. When the credit crisis came that problem got exacerbated, and we made the decision to move rapidly out of that.

The interesting lesson I find for myself and that may be applied to some others is that the utility industry does generate very high quality earnings. Whether from distribution, transmission or generation, they are high quality because they are repeatable, more annuity-like. To the extent you degrade your model with a lower quality earnings base, you potentially aren’t adding as much shareholder value as you might hope.

FORTNIGHTLY: The merchant power business carries some of the same kinds of risks, doesn’t it? How does that affect the quality of earnings?

SHATTUCK: On generation side it will be more cyclical, and of somewhat lesser quality, but still of high quality. It’s the trading revenues specifically that cast some doubt as to whether you’re really going to be rewarded for good performance. Trading earnings probably belong on bank balance sheets, and even they struggle a bit with how much value they get from trading revenue.

There are aspects of the marketing business, of which trading support is one, that can get a good value. A sales and marketing arm, as an example, where we’re providing risk management services to large customers, is shown to have high repeatability, high retention rates and good margins. That kind of business should be rewarded with a decent multiple.

All of our companies need access to the capital markets. We all borrow, but there are some aspects of the business that are really dependent on it. All utilities are dependent on access. The generation companies, obviously, to build these big projects must have access to capital markets. Those are the priorities when it comes to reliability of our system. We have to put capital there. In areas that we consider on the margin I think that great care has to be given to the quality of those earnings, so you’re really aiming toward achieving the highest shareholder value you can, and not putting a higher risk-reward expectation on lower-quality earnings that eventually could come back and hurt you.-Michael T. Burr

Additionally, Wall Street investment banking has been consolidated rapidly with “the Big Three” commercial banks—Barclays PLC, Bank of America and J.P. Morgan—taking advantage of bottom-feeding opportunities.

This dramatic reshaping of Wall Street has come too swiftly to fully comprehend, yet it will have an immediate and lasting impact on the utility sector.

With immediate job losses among investment bankers, a decline in their ranks will reduce competition for underwriting utility bond deals. Less competition will equate to higher fees. This might not be immediately visible in a weak economy, but it will show up as the economy eventually rebounds.

Significant investment banking consolidation and downsizing will result in a loss of institutional knowledge as older experienced investment bankers are forced to take severances.

Having a banker who knows the history of the utility, and the company’s management and its level of corporate risk-taking, can be invaluable when structuring and underwriting bonds, as well as providing M&A guidance. Utilities will need to begin building new relationships.

The recent market crisis, including the bankruptcy of Lehman, has resulted in significant market uncertainty. The proposed $700 billion Treasury Department bailout has raised additional concerns about how such a plan will be funded. Such events have placed increased pressure on interest rates, raising the cost of both short-term and long-term capital. In addition, as more of the investment banking business falls in the hands of fewer commercial banks, it remains uncertain whether utilities can count on the same level of service they enjoyed previously. The corporate cultures of investment and commercial banking can be quite different, and Wall Street’s reshaping might result in customers losing out.

Prior to the weekend shotgun wedding with Merrill Lynch, Bank of America CEO Kenneth Lewis was less than enthusiastic about how investment banking activities might fit inside his institution. Moreover, it’s unclear whether these banks will view serving the gas and power utility industry as a strategic priority. For example, although Barclays is buying Lehman’s defunct investment bank, the European bank reportedly hasn’t decided which divisions it would keep and build a franchise around.

In the weeks and months ahead, one trend to watch closely is whether the investment bankers who are able to find new homes will be randomly scattered around Wall Street, or whether the Big Three banks will make it a priority to keep these utility teams intact.

Now that the Big Three hold more of the cards, they should reach out to the utility industry and pronounce their intentions. What will be their level of commitment? Will they devote the capital needed to adequately service this industry? We might be in a recession, but the market will recover eventually, and the utility industry will continue to grow and prosper. Having a knowledgeable investment banker ready, able and willing to underwrite or structure a merger will be crucial.

So the message to Barclays, Bank of America and the other institutions that may be the future home to our power and utility industry investment bankers: Whatever you do, be good to them, as they are an endangered species, and vital to this industry’s future.

Editor’s note: Williams previously was a senior vice president of Citizens Power LLC, a Boston based energy trading company, and a vice president with Edison Mission Energy. Prior to that worked at the Federal Reserve Bank as a full examiner.

I like the fundamentals of the biomass footprint even more now this year. Wind is facing trouble with the PTC extension, turbine product availability, a nagging de minimis capacity factor, and need for transmission that isn’t being developed nationwide. Transmission constraints could strand many new renewable energy projects over the next five years, as occurred for cogeneration, small power producers and independent power projects during the prior decades.

Now is the time to diversify the renewables supply base with existing technologies that have more base-load attributes—such as geothermal, hydropower and biomass, including landfill gas and municipal solid waste. Biomass in particular offers great potential for increased expansion in the next five years.

The key to success for advanced biomass development will arise from the ability to lock up sufficient and reliable fuel supplies. Failure to do this will keep biomass from scaling up until non-cultivated, closed-loop fuels become competitive on an emissions-cost adjusted basis. The determining factors are political, structural and technical/agronomical at this stage.

The political issue comes down to GHG regulation and setting carbon costs. If the GHG regulatory calculus prices carbon under $50 a ton, it will be a long time before any alternative power sources can really compete with fossil fuels, particularly coal. Until carbon emissions credits reach $50 a ton, coal plants won’t sequester carbon, but likely will just buy credits in a compliance regime. That’s exactly what occurred after enactment of the Clean Air Act Amendments of 1990, when major scrubber investments and more capital intensive strategies were postponed for a dozen years or more.

The technical issue arises from the difficulty of securing firm fuel supplies. A closed-loop solution could project biomass ahead of wind and solar in many ways, making it the least-cost renewable supply option with better operating characteristics. But I’m hearing more discussion bemoaning the possible environmental costs of increasing reliance on cellulosic energy sources. What happens after 10 cycles of harvesting switchgrass, poplar and kudzu, without any serious fertilizer input? A natural biome replaces humus nutrients with necrotic material from the previous growing season. If we’re burning that material, the humus will disappear and eventually the soil will turn into sand.

However, by aggregating supplies under a regional “hub” approach, a closed-loop system can allow careful management of growing biomass areas. And of course biomass fuels from such sources as forest thinnings, sawdust and bark from private and government properties could be aggregated by rural communities. Rural development funds to supply clean, untreated lumber for biomass power production could revitalize local forest industries. And federal and state lands can contribute feedstocks from efforts to cull overgrowth and avoid forest fires.

Additionally, biomass power plants with waste-heat capture equipment can provide thermal energy for drying, processing or other industrial or commercial purposes. This enhances the community tax base, prompts a new feedstock industry, increases local jobs and contributes to the local economy.

From a public-policy perspective, the critical factor will be for lawmakers to include supply chain and logistics support in energy legislation, to create a closed-loop biomass fuel industry and provide proper scale to capture the potential of biomass power. Inordinate focus on creating incentives for supply, without anticipating the complete logistics of transportation, storage, handling and distribution, is a fatal flaw of many of our national energy strategies for all of our fuels and power strategies. Correcting this flaw will allow the industry to harvest the true potential of dispatchable biomass power.

Michael J. Zimmer is Of Counsel with Thompson Hine LLP in Washington, D.C.

Every article we publish in Public Utilities Fortnightly is incomplete. The virtual cutting room floor is always littered with content that didn’t fit for one reason or another.

For this year’s CEO Forum feature story, we asked several utility leaders about climate change regulation. Very little of what they said made it into the June cover story, “Conservation Compact,” so we’re presenting a more complete edit of their responses here in the Public Utilities Blog.

While it’s fair to say none of the CEOs departed far from their corporate message about the topic, their comments illustrate growing concerns among utility executives about how to regulate greenhouse gases fairly and effectively.

Chris Dutton, Green Mountain Power

Fortnightly: Given your experience in a RGGI state, what’s your perspective on federal greenhouse gas regulation? How can utilities reach a compromise on GHG regulation and allocation methodologies?

Dutton: I think the better and fairer approach is a carbon tax. Whether that’s politically feasible is another issue, but that’s a more competitive and less cumbersome approach than a cap-and-trade program, which has a whole host of complications associated with it.

New England as a region has a relatively small carbon impact, in terms of generation, because of the predominance of natural gas and nuclear power in the supply. There’s very little coal in New England, so those issues are a little different for us than they are for parts of the country that depend on coal-fired generation.

One of the things we’ve been able to do outside the power supply arena is to change the way we behave in the four corners of our business. We’ve converted all our line trucks and operating vehicles to biofuels. And we operate with an office blueprint that is radically different from what’s typical in our business. At Green Mountain Power there are no private offices. I as the CEO have a work area that’s about 9’x9’, and we have low partitions. There’s no private office. That’s meant we require a lot less office space than is traditionally the case, and you can guess the corporate culture advantages this approach brings. We try to be very transparent in our behavior within the company and in our interactions with both regulators and the general public, and a part of that transparency is the idea there are no hidden agendas. Part of that concept is no private offices.

We’ve been operating this way for about eight or nine years and we just love it. It gives the place a sense of energy and direction that didn’t otherwise exist. But also, shen you operate in a place that doesn’t need as much space, you don’t need to heat and cool it.

J. LaMont Keen, Idaho Power

Fortnightly: What’s your perspective on mandatory greenhouse gas regulation?

Keen: GHG regulation now seems certain to happen. The presidential candidates both support regulation in some form and it has been ruled that carbon is a pollutant that EPA should regulate. The discussion now centers on how and what type of regulation will occur.

Whatever the form carbon regulation takes, it’s important that regulatory efforts be applied economy-wide. We recognize the electric utility industry is probably the easiest to regulate, but if carbon regulation is to succeed no single sector should be unfairly burdened. More importantly, time frames should also be consistent with development of the carbon capture and sequestration technologies needed to comply.

If applied appropriately, either a carbon tax or a carbon cap-and-trade mechanism could work. Either way, the key is getting adequate research dollars collected and applied toward developing the necessary technologies.

In a cap-and-trade program, how allowances would be apportioned is the million dollar question, raising serious issues of effectiveness and fairness no matter how the apportionment is done. Whatever method takes place, it is appropriate that companies gain some recognition for the wisdom of earlier decisions to invest in and develop emission-free forms of generation.

Fortnightly: How will the industry reach a compromise on that? I’m hearing diametrically opposed views on this.

Keen: I don’t believe it’s appropriate for the allocation method to come out in a way that’s biased against companies with a smaller carbon footprint today. Some of the concepts I’ve heard discussed might do that.

I think it’s very speculative at this point. The devil truly is in the details, and it’s going to be a divisive issue for the industry. It’s possible for the industry to come together and strike a balance, but we have some fundamentally different starting positions for the discussion.

Bill Johnson, Progress Energy

Fortnightly: What’s your perspective on federal greenhouse gas regulation?

Johnson: Carbon regulation is a certainty. We believe that a well-designed cap and trade system will have the least negative impact on our customers and the overall economy, and will help us make real progress toward a low-carbon economy. An effective climate change policy must be achievable with timelines that are in harmony with technology. It must also be affordable, with reasonable allowances that put all states and players on a level field, and include provisions that protect consumers from rate shock and limit the damage to the economy.

Fortnightly: What would a level field look like for a ratepayer in a state that already has a relatively small carbon footprint, and has been paying high rates for a long time? Should their climate friendly infrastructure pay off in this level field?

Johnson: This whole subject is pretty complicated. When allocating allowances, those most affected by the new standards should get the most mitigation. Coal dependent customers will carry the brunt in two ways, paying for emissions and paying for new infrastructure. We need to have no-cost allowances in the early years, and more costs as technology develops.

Allocation of allowances ought to be based on emissions levels. Carbon emissions is where the allowances ought to go. I don’t think it’s a good idea to try to increase rates in some parts of the country because rates in other parts are higher. That doesn’t seem like a sound public policy basis for addressing carbon emissions.

Mark Jacobs, Reliant

Fortnightly: What’s your position on federal GHG regulation?

Jacobs: We’re committed to environmental stewardship. The best approach is a national policy rather than state by state. We believe a cap-and-trade system is the best approach, because it has worked incredibly effectively for SOX and NOX, and we also think it’s important that any legislation provide enough lead time to allow new technologies and market forces to work.

Energy efficiency is one of the easiest and most cost-effective approaches to addressing GHG emissions, and the smart energy things we’re doing will have a meaningful impact on the carbon footprint.

What happens to credits and allocations of allowances will get a lot of attention and debate, but we believe there should be a bridge provided for existing generation, and some of the proceeds raised by the auction need to go into development of new technology. We don’t think it’s appropriate to be taking proceeds and subsidizing known technologies. Someone might say they ought to get a price break for building a nuclear plant, but the prices are such today that people will build it without the incentive. We ought to take the proceeds and put them into the technology solutions to store CO2.

Dennis Wraase, PHI Holdings

Fortnightly: Given your experience in RGGI states, what’s your perspective on federal greenhouse gas regulation? How can various utilities and generating companies, with different resource strategies, reach compromise on things like allocation methods?

Wraase: As someone who operates in four states—which fortunately are somewhat together in RGGI—I think it would be far better to have a federal standard than to have 50 states doing 50 different things. Also the sooner we get to this, it will solve an awful lot of problems with power plants that need to get built and technology that needs to get developed.

A lot of the efficiency projects we do don’t include social cost. So once a dollar value is assigned to carbon, there may be more efficiency projects that become cost beneficial. That would be helpful.

As for a compromise, I’m not sure the industry will ever come around to agreeing, and neither will the states. This is a winners-and-losers proposition. That’s why I’m one of those who’d be more in favor of a tax as opposed to cap and trade. It avoids a lot of problems associated with how you allocate allowances, which is highly controversial. A tax is easily understood and can be applied economy wide.

The Presidential candidates increasingly are including energy-policy issues in their stump speeches. And the Democratic contenders propose enormous spending programs—from $50 billion (Sen. Hillary Clinton) to $150 billion (Sen. Barack Obama)—with a New-Deal style appeal for investing in the country’s energy future.

Last year, Obama said, “This is our generation’s moment to save future generations from global catastrophe. It will take a grass-roots effort to make America greener and end the tyranny of oil.”

Clinton, in a speech at the National Press Club, said “Instead of national security dictating our energy policy, our failed energy policy dictates our national security.”

Sen. John McCain likewise includes the energy theme in his campaign promises. In April 2007 he said, “We have the urgent need and the opportunity to build a safer and thriving future with more diverse, reliable, and cleaner energy. But it will take another indispensable commodity to make it happen—American leadership.” McCain is well known as the perennial co-sponsor, with Sen. Joe Lieberman, of legislation that would mandate carbon constraints.

It seems the next president, regardless of who it is, is going to attack development of clean energy vigorously. If mountains of public money are to be spent on development of new technologies, there is an equally mountainous question of how those funds should be managed to assure the money is not wasted—i.e., that the investment yields commercially viable, clean energy technologies that get widely deployed in the coming decades. Who should manage this project—the federal government or the private sector?

While the Department of Energy might seem like an obvious choice, its track record suggest otherwise. For one thing, DOE’s annual appropriations are subject to political whims, as well as political competition inside the beltway—with defense, health care, education, and other departments clamoring for their share. Further, the agency’s tendencies to pick so-called winners like FutureGen before the facts are in about commercial viability suggests it would be the wrong model for managing a New Deal-scale energy development effort.

So what about the private sector? The Electric Power Research Institute (EPRI), funded by the utility industry, has prepared a comprehensive and detailed RD&D program for developing commercial, climate-friendly power generation technology. EPRI brings a great degree of industry credibility, but its budget model severely constrains its resources, and its track record is mixed, when it comes to wide-scale deployment of technologies developed.

The Gas Research Institute might be a model worth replicating. It generated 30 percent success on commercial ventures—twice the normal industry rate of success—with a benefit/cost ratio of 7:1. GRI selected its projects under the oversight of a government watchdog—FERC—with multiple review boards—including industry, academia, public interest groups and technical experts—all contributing in a formalized project appraisal methodology that winnowed out the important, likely winners with amazing success.

Plus GRI’s funding model bears more resemblance to the broad-and-deep stream that might characterize a New Energy Deal. GRI was funded by a surcharge on interstate gas pipeline sales.

It comes down to this: whom do you trust? No one I know trusts the government to develop commercial products. And historic examples support this sense of mistrust.

After World War II, Alfred Loomis shut down the MIT Rad Lab that had developed radar during the war by January 1946, because he felt companies like RCA and Motorola would do a much better job of exploiting the commercial potential of electronics. By contrast, the National Laboratories associated with atomic energy were not closed. And while they have produced valuable research, their efforts have paled in comparison to what the RCAs and Motorolas of the world have produced.

America might need a New Deal to finance the mammoth clean energy challenge, but such an investment must be managed by the private sector—perhaps in a GRI-style structure—to ensure public spending actually results in cost-effective technologies being developed, commercialized and deployed.

(EDITOR’s NOTE: This blog entry provided a preview of John Bewick’s article, “Cultivating Clean Tech,” which appeared on the cover of Fortnightly’s May 2008 issue. Bewick, formerly secretary of environmental affairs for the Commonwealth of Massachusetts, is founder of Compliance Management Inc., an environmental consultancy based in Hingham, Mass. -MTB)