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

 

Posted: October 7th, 2009 under Big Build, Uncategorized, carbon regulation, finance, green energy, renewables.
Comments: none

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

 

Posted: October 2nd, 2009 under Current News, Uncategorized, carbon regulation, climate change, energy policy, regulation, renewables.
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Sept. 1, 2009

FOR IMMEDIATE RELEASE

Contact:
Michael Burr
burr@pur.com
320-632-5342
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.

Posted: September 2nd, 2009 under Current News, Uncategorized, bear market, credit crunch, finance crisis, investment banks, recession, utility stocks.
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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

Posted: September 1st, 2009 under Uncategorized, carbon regulation, climate change, energy policy, geoengineering.
Comments: none

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

Posted: August 19th, 2009 under Uncategorized.
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