Published on Fortnightly (http://www.fortnightly.com)

Home > Printer-friendly > Generation Roundtable: Power Flux

Generators struggle to plan for the future as they cope with an unstable present.

When the acting administrator at the Environmental Protection Agency (EPA), Marianne Horinko, signed the EPA's "routine replacement" rule on Aug. 27, 2003, she proclaimed that the new approach to Clean Air Act regulation would "provide … power plants with the regulatory certainty they need."

Then, almost immediately, any illusion of regulatory certainty went up in smoke. A platoon of lawyers from 13 states and two dozen cities marched into federal court and filed suit against the EPA, challenging the legality of its new rule.

"The situation is just as uncertain as it ever was," says Chuck Wehland, a partner with the Jones Day law firm in Chicago. "I think it's doubtful that the routine maintenance and repair rules will survive the legal challenges."

Such uncertainty typifies the state of limbo in which power generators find themselves today, with evolving environmental regulation adding to the uncertainty over a wide range of factors. Consider:

Such unsteady ground makes a poor platform for planning the country's power-supply future. Nevertheless, as the Fortnightly learned in a recent series of interviews, companies are moving forward by carefully addressing the issues within their control. In preparation for new environmental regulations, for example, power companies are assessing their assets and investing in technology development. Write-downs and charge-offs, moreover, are part of a painful but ultimately healthy balance-sheet strengthening exercise. And liquidations are yielding opportunities for companies with the appetite for acquisitions. To analyze the major trends in generation strategy planning, the Fortnightly consulted utility leaders for their perspectives on the subjects of market forecasting, asset sales, environmental legislation, and energy technology and distributed generation issues.

Forecasting in Roller-Coaster Markets

The alpha and omega of power resource planning is the ability to forecast load changes. Accordingly, raging volatilities in economic and regulatory trends, plus terrorism and war, sorely challenge strategic-planning processes. In such an environment, forecasting tools are about as effective as a Magic 8-ball. interviews Thos. E. Capps, CEO, Dominion Resources; Eric Markell, senior vice president, Puget Sound Energy; and Bill Hall, executive vice president, Duke Power, on the issues affecting market forecasting.

Fortnightly: What trends do you see in load growth? What are the big issues driving demand trends? Will the oversupply situation persist?

Capps: Demand is going to drive new generation, and what will drive demand is the economy. I don't see the market doing much more than following the economic outlook.

We are primarily focused on the Eastern Interconnect. If you look at reserve margins, everyone, with the possible exception of VACAR [the Virginia-Carolinas service area], has 15 percent or more. There won't be much new generation needed through 2006.

Hall: The high-level issues involve the state of the economy, and particularly the manufacturing base. In our service territory and across the nation, we are seeing manufacturing jobs lost and factories being closed. Those are 24/7 facilities, and when they go away that's a big chunk of electricity revenue that we lose.

Some of that base is replaced with commercial and residential load, but not much heavy industry. We are concerned about it, and in the Carolinas we are getting actively involved with economic development on the state and regional levels.

Markell: In the Northwest, there is a sea change happening with relation to the availability and cost of hydropower. The 60-year era of surplus, cheap hydropower is over. As a regional economy, we've outgrown the available resources, and environmental externalities and licensing processes have imposed heavy costs on the hydro system. For example, we are looking at relicensing three hydro plants, and the requirements will more than double their cost in some cases.

We are seeing in the Northwest and the rest of the country that natural gas has become the marginal fuel. Enormous quantities of natural gas-fired capacity have been built, especially on the West Coast, and we've created a dependence on an uncertain long-term fuel supply. This is driving people to focus on liquefied natural gas (LNG) as a means to both diversify gas supply and temper the amount of gas-price volatility in the U.S. market.

Fortnightly: What power supply options do you see as most important for the long term?

Capps: Right now about all you can build is gas-fired capacity, and it will put a lot of pressure on gas reserves. Clean coal technology is still in evolutionary stages. We read about hydrogen, and it is a good concept, but to go commercial you are talking another 30 years.

What we should be building is nuclear. As a nation, we will never be completely energy independent. But if we want to get closer to that, we need to build nuclear. That is a political problem, not an engineering problem. The political will is not there to build more nuclear.

Hall: It gets back to the diversity of your generation fleet. One-third of our fleet is nuclear. That is a good hedge against environmental issues. We think nuclear ought to be a key consideration as we look at maintaining affordable energy rates and reducing emissions. But the public is not ready to accept the next generation of nuclear evolution.

Markell: Nuclear is not part of our current thinking at Puget Sound Energy. At the end of the day Wall Street is the arbiter of who gets capital. The lack of political will is really a comment that we need the government to eliminate the business-model risks in such a way that capital can be attracted.

As we've gone through our integrated resource planning (IRP) process, the foundation for meeting the need has been our conservation program. We are investing about $25 million a year in conservation activity, and we expect to save or avoid 20 MW a year through the next decade. That's a critical part of what we are doing.

Also, we are trying to acquire wind-power resources for our portfolio. We have an RFP out, targeting 800 MW of renewable energy. Wind power could account for 300 MW or more of that. I expect we'll make decisions before the end of 2004 that would allow plants to begin before the end of 2005.

Wind power technology has become quite reliable. The size of the machines, their efficiency and cost have improved greatly over the last 15 years, and now we have a truly commercial-quality product supported by world-class vendors like General Electric. The economics of wind power, however, still depend almost entirely on federal production-tax credits for investors. It is a heavily tax-subsidized resource. Others will argue that coal, oil, and gas extraction are subsidized, and then you get into the whole national tax-policy debate. At any rate, tax credits as part of a national energy policy are critical for wind development.

There are half a dozen or so proven wind-resource areas in the Northwest that will support commercial development of large-scale wind farms, in the range of 150 MW or greater. The location of the resource, however, creates transmission issues. You may not have a robust transmission grid anywhere near where your wind farm needs to be. It's as dependent on a robust and well-built transmission system as any other resource.

There are other issues with wind power about its so-called true economics, and how to integrate it into a system. But the country is getting a lot of experience in those areas, and as time passes the country will become more comfortable that we can do it technically and economically.

Assets: Megawatts for Sale (Cheap)

The merchant power industry's crisis has plunged several companies into bankruptcy, and others are disposing of distressed assets (see below). In August, for example, Exelon Corp. said it would turn over ownership of seven merchant plants, totaling 3,400 MW of capacity, to a lender group led by BNP Paribas. Similarly, the bankrupt National Energy Group (NEG), a subsidiary of PG&E Corp., expects to transfer more than 5,600 MW worth of power plants in December to lender groups led by Societe Generale and Citibank.

Most of the outright sales that are occurring, however, aren't strictly "distressed." In October, for example, the Goldman Sachs Group announced it would buy 100 percent of Cogentrix Energy Inc.'s stock in early 2004. Most of Cogentrix's plants sell power under long-term, off-take agreements, which helped the company fetch about $2.4 billion from Goldman Sachs. The investment bank agreed to acquire Cogentrix after Aquila Inc.'s attempted acquisition of the company collapsed at the end of July. (In a sad coincidence, Cogentrix founder George T. Lewis died of an extended illness just a few days before announcement of the Goldman Sachs deal.)

In the wake of such sales, we talked with two well-placed experts on secondary market activity: Jeff Bodington, principal of Bodington & Co., a San Francisco-based financial advisory boutique; and Michael Zimmer, a partner with Baker & McKenzie in Washington, D.C.

Fortnightly: What are you seeing in secondary market activity? Are plant sales picking up?

Bodington: The number of announcements and closings is clearly accelerating. The very slow market has turned into a moderately slow market, and I will take that as good news considering all that is going on in the industry.

In the big picture, there have been approximately 40 deals so far this year. Last year there were 62 in total, so at the end of 2003 the total volume might be about the same as last year. At least 90 percent of the deals getting done involve projects that have power-sales contracts or tolling agreements. The market for merchant plants remains very difficult. We have more merchant projects changing hands this year than we did last year, but so far those tend to be transfers to banks, and equity sales to new owners for substantial sums.

Zimmer: The level of interest in selling is definitely starting to pick up, but actual deal flow is still slow. It will take several months for it to pick up into 2004. Next year, people will be reorienting the pieces of their portfolios and actually moving forward in selling out of those portfolios.

There has been a lot of exploration as to price and market clearing, and people are now starting to get a fuller appreciation of where the challenges might lie. Many of those properties coming to market were originally merchant plants, reliant on natural gas as their fuel, which creates ongoing operational challenges.

A major share of the activity involves projects or facilities sold out of bankruptcy. NRG, Exxon, National Energy Group, and ultimately Mirant will appear in the market.

Fortnightly: Who are the buyers today, and who are they likely to be next year?

Bodington: I see some new entrants and some regulated utilities buying assets. (See next page). There appears to be some movement back toward a traditional utility model, where assets are owned inside a rate base.

While a few new entrants are in the market, out of the 30 to 40 new companies looking to buy, only a couple have closed deals. A few include Competitive Power Ventures, which bought four development-stage projects; Reservoir Capital Group, which bought some Sithe projects from Exelon; and Pomifer Point LLC, which bought an interest from Calpine.

There is an influx of lookers. There is new money out there, but how many of these will actually turn into buyers remains to be seen. I expect most of them will just be lookers and will go away. Examples are George Soros, Applewood, Madison Dearborn, KKR, Promentory, and AIG.

Despite the fact that there are a few successful new entrants, I stand by my opinion that half of the new entrants will never buy anything, 25 percent will make purchases that they will later regret, and 25 percent will make good long-term buys

Fortnightly: What roles are the big banks and investment banks playing?

Bodington: Those that can bring a trading capability to the market during the next couple of years will make billions of dollars, and the way they'll do it is to take away merchant risk. They'll participate in merchant projects for low investment, but add tremendous value by taking away the merchant risk and capturing some of that value for themselves.

Who will it be? Possibly Goldman Sachs, Shell, and a few other trading companies that are still standing after the carnage of the last two years. They are high on the list of those that are likely to be successful. I know that some of those are taking careful looks at merchant power plants, but deals aren't getting done yet.

As for banks... the market for power is at or is just past its nadir. I see the owners and their lenders-the de-facto owners now-holding onto assets until market conditions improve. And because of that the bid/ask spread is still too great for deals to happen. We have been retained by one bank group to assist them in a solicitation for a tolling contract for a project, and this is something a number of lenders are looking at as a way to take away merchant risk for some period of time.

Zimmer: There are not enough buyers and plenty of sellers. The buy side has not filled out as much as people had hoped.

On the other hand, the debt overhang on the merchant industry has been greatly reduced. A year or 14 months ago it was $90 billion, and recent updates indicate that number has been cut in half. Now debt overhang may be more like $47 billion. Some of it has been extinguished through bankruptcies, some has been extended through 12 or 18 months and will come due in '04, and some companies have been successful at selling plants and moving the debt off the books.

We're not out of the woods yet, though. A 50 percent reduction in less than 18 months is pretty fair, but arguably that's the low-lying fruit, compared to the final $47 billion.

The other piece of the acquisition binge that was forecast was related to the removal of PUHCA barriers, a harbinger of incremental consolidation in the electric utility industry, with perhaps another round of strategic convergence plays and maybe cross-border work, particularly with Canada.

PUHCA repeal might make merchant sales more challenging, because if people have the opportunity to purchase fleets and utility assets, it might make merchant plants seem even less attractive.

Also, with market incentives in place for consolidation, and with relaxation of Clean Air Act standards, there may be growing interest in plant life extensions and repowering of existing facilities. There is also an argument for more fuel diversity, to get off the volatility and hardships created by reliance on natural gas. I would not be surprised to see over the next 10 years that new generation will come from the regulated side, through consolidation, plant life extensions, and repowering. From a strategic perspective, these are all opportunities to build rate base.

The merchants will be in a very challenging environment until they see an improvement in their market capitalization.

Environmental Legislation: Clear Skies, Muddy Waters

Environmental regulation frequently has effects that extend beyond the environment. What happens with New Source Review (NSR) standards, for example, could alter the future for merchant power generators, most of which are relatively new facilities burning natural gas.

Their competitive position would be much different if, as the EPA rule change stipulates, existing plants can invest up to 20 percent of their replacement cost in upgrades without triggering the requirement to install best-available control technology.

Likewise, the resource planning calculus changes dramatically if federal or state agencies begin limiting greenhouse-gas emissions from power plants. For views on these issues, we turned to Thos. E. Capps, CEO, Dominion Resources; Chuck Wehland, partner, Jones Day; Michael Zimmer, a partner with Baker & McKenzie in Washington, D.C.; Bill Hall, executive vice president, Duke Power; and Eric Markell, senior vice president, Puget Sound Energy.

Fortnightly: Please explain the EPA's rule change over New Source Review. What is its status and significance?

Wehland: EPA is trying to bring some clarity to the identification of projects that would be considered routine repair and replacement, and not subject to New Source Review. The rule change does a fine job of that. It has clear, bright-line tests that you can easily use to determine whether a source is undergoing routine repair and replacement, or some other project that would have to be evaluated under NSR rules. It says that project is not significant unless it costs more than 20 percent of the capital costs to replace the whole unit.

That is clearly a departure from the EPA's previous position, which was to judge each plant on a case-by-case basis. The change is significant. There's no way to look at the rule without reaching the conclusion that more projects would be deemed routine under the new rules. The definition of "routine" would include many repowering and life-extension projects, as long as they wouldn't increase capacity and would cost less than 20 percent of the plant's replacement value.

The problem is that the rule would not immediately be effective anywhere-only in states that take action to approve it as part of their state rules. And most important is the litigation that was filed in October. Until that is resolved, New Source Review standards remain uncertain. I think it's doubtful that the routine maintenance and repair rules will survive the legal challenges. The old rules are pretty well founded and well within the scope of what Congress intended.

Fortnightly: How does the rule change affect the new source review enforcement actions that the EPA began a few years ago?

Wehland: It will be interesting to see what happens with the enforcement litigation as it works through the courts. There are drastically differing opinions on how the former rules should be interpreted, and there will be some significant decisions that will have a drastic effect on how we view the rules.

In the Ohio Edison and Duke Energy cases, for example, the district courts have reached diametrically opposed decisions on whether you judge routine maintenance and repair with reference to the source by itself, or with reference to the industry as a whole. That is important for these life-extension projects because they happen only once for a unit. But if the reference test is the whole industry and everybody is doing it, then such a project looks more routine.

The other place where they differ in irreconcilable ways is how you should calculate whether there has been an emissions increase as a result of a project. The North Carolina decision defines an emissions increase as your hourly emissions rate. It doesn't allow the government to use changes in capacity factors in determining emissions increases. That is in direct conflict with the Ohio decision.

Getting some resolution on these issues one way or another will have significant ramifications.

Fortnightly: What about new emissions control requirements? The EPA has proposed mercury-reduction standards for the first time, and some lawmakers at the state and federal level are pushing greenhouse-gas emissions control. What do these trends mean for power planners?

Hall: These things are critical to us as we plan our future generation portfolio. We think we'll have a regulatory requirement to control mercury, and we don't have the technology on the market to do that today. Also, Bush has made a commitment to reduce carbon emissions, and we have a large coal fleet in the Carolinas. I'm not an expert, but the only viable technology seems to be carbon sequestration. Unfortunately that only works in some regions of the country where you have geologic formations that can accommodate the carbon. Nothing has surfaced that will work on all our assets across the nation, so that will be a difficult one to tackle.

However, we have confidence that the industry will innovate and get actively involved with research and development around both mercury and carbon. We ourselves are involved with a couple of DOE projects, looking at mercury-reduction technology.

Zimmer: The mercury decision ripples back on these other questions too. If you are going after mercury, you can't do it in isolation from other emissions as well. Is this laying the foundation for no mercury action?

Capps: We think the Bush administration's Clear Skies initiative will get passed somewhere around 2008, and the price per ton of the entitlements you can buy will be about $2,400 a ton. We will do some trading around those. Unless something comes out of left field, we will be OK.

Wehland: Clear Skies is a move forward, but it's not as much of a move forward as the environmental community would like because it doesn't include greenhouse gas emissions among the pollutants being controlled.

Also the environmental community is historically suspect and wary of plant-wide applicability limits. That's what Clear Skies would do, telling generators to do whatever they need to do and achieve the given limits, as opposed to the re-examination of emissions limits or controls every time a repair goes on at a facility. That is a rollback, but from a utility perspective it gives you certainty. You have new pollutants regulated, but it's a good trade-off.

At the end of the day emissions won't increase as a result of Clear Skies as opponents say it will. I don't think in substance it will change a whole lot regarding what facilities are doing, but it will simplify their permit structures and give them more flexibility. In many respects, that's a better approach because it focuses on air-quality impacts that people really feel, rather than specific projects at specific plants.

Zimmer: The offset credits of Clear Skies are a fair proposition, but they have already been part of the fabric of EPA air regulation in the past. And the need to look at emissions from integrated operations, as opposed to facility-by-facility, is a fair comment. But we still need standards in terms of the results we are looking for. It also could include a richer array of other options, including fuel blending and development of renewable facilities that would provide credits you could use to offset outputs from dirtier facilities.

Fortnightly: Greenhouse gas emissions might be regulated under other legislation. The Climate Stewardship Act (S.139) recently garnered a surprising 43 votes in the Senate, across party lines. What does this portend?

Wehland: It's hard to predict. The administration has not given any indication that it will accept a bill that has climate-change elements to it. Bush believes voluntary measures and those with some economic growth element are necessary to address climate change. I don't think S.139 does that, but if you have a compromise that lets you get most of what you want in Clear Skies but adds climate change as another pollutant, maybe at the end of the day that turns out to be an acceptable compromise.

Markell: We are seeing increasing national concern over greenhouse gases. Early this year, Gov. George Pataki in New York and some New England governors issued a compact at the state level to impose state-mandated restrictions or taxes on emissions of greenhouse gases. And in early October, Gov. Gary Locke of Washington announced support for limits like those in Oregon.

The punch line is that state policy-makers have grown tired of Washington, D.C.'s, inability to come to closure on this as a national concern, and are trying to address it on a state level. What that does is make planning and resource acquisition even more uncertain, because we don't have a national level playing field or even a regional level playing field. Some states will impose certain greenhouse-gas taxes, and others will not. That uncertainty makes planning and analysis difficult, and makes capital more wary of jumping into energy investments. It's affecting decision-making adversely in a number of ways.

Energy Technology: Covering Left Field

With changes afoot in so many areas, predicting the Next Big Thing is more difficult than usual. However, distributed generation (DG) trends are generating more attention, especially amid growing concern over grid security.

The latest markup of the Energy Policy Act includes $1.15 billion for distributed generation and micro-cogeneration technology development from 2004 through 2008. But how far this technology will go remains-you guessed it-uncertain. In some sense DG might represent a litmus test for the industry's next phase of evolution. The degree to which key stakeholders embrace DG might set the tone of the next several decades. Dominion's Capps, Baker & McKenzie's Zimmer, and Duke Power's Hall debate the future of distributed generation technologies.

Fortnightly: What role does DG play in resource planning today?

Hall: DG is a viable part of an overall infrastructure system. A lot of it is predicated on what customers want to do-if they want to go into their own energy management or look to companies like Duke Power to provide it.

Outside the emotion that gets generated when you have a major blackout, large customers still want to focus on their core business, and want us to help them manage their energy needs. DG is a piece of the overall solution to long-term needs, but I'm not sure to what level folks will embrace that technology.

Capps: Once you get DG where it's economically competitive, it should succeed on the theory that the closer the power supply is to the load, the better off you are. But DG is noisy, and has to be served by fuel, if it's propane or natural gas or diesel, and its success will depend on where it is located.

It's not the panacea. The secret of reliability is, number one, to have some strict reliability standards with teeth in them, not voluntary standards. NERC did a good job, but if you didn't agree with what they suggested, they couldn't do anything to force you to comply. I'm a real federalist on this. The FERC should have authority over [electricity] transmission, as it does over gas transmission. You've got too many cooks in the kitchen on electric transmission siting. One cook needs to look after the interests of everybody.

Fortnightly: Does DG have the opportunity to become a really significant part of the U.S. power system, or will it remain a marginal technology?

Zimmer: It is poised at the cusp of national opportunity. It should happen, but there are no guarantees.

Distributed generation has one of the best opportunities to emerge in 30 years, because of security, fuel volatility, efficiency issues, power quality, pricing, and some of the grid-based transmission problems and bottlenecks. DG is about keeping supplies secure. It is using energy and deploying it most efficiently, and it creates jobs in a new industry.

However, several things are still missing. DG doesn't seem to have strong leadership coming from within the industry, state commissions, or from Wall Street to push and explore the fullest vitality and viability of the option. DG needs a blueprint that removes the artificial barriers standing in the way of full deployment.

Fortnightly: What are these artificial barriers?

Zimmer: A simple example is the ability to deploy DG in a commercial building. It may be economically impaired and not considered because standby, backup power rates have never been updated, and the demand-ratchet clause in existing rate schedules might be triggered by the use of power in one week out of a month.

This is not the only example of artificial barriers that are preventing new technology from being deployed. Transmission and interconnection issues are another example. The Cross-Sound transmission line [connecting New Haven, Conn., with Long Island, N.Y.] couldn't be turned on because the state of Connecticut feels there are continued environmental concerns, and the attorney general questions whether it will benefit Connecticut customers. If the same processes were deployed in transportation, we never would have built the interstate highway system.

Here's the question: Is it better to continue with the status quo, and nurse it along with plant life extensions and repowering at old, dirty plants, or would we be better off directing that capital toward new technologies-coal gasification, for example, or other technologies such as energy efficiency or fuel conversion systems that solve the natural gas challenge, support fuel diversity as well as regional and technology diversity, and create more high-quality jobs? The renewable energy industry could create more jobs, if it had the technology and equipment to expand. DG is the same thing. It could become the energy industry's equivalent of the cell phone. Technology, regional, and fuels diversity would promote better risk diversity for financing purposes, learning from the experience of the gas turbine troubles of the 1990s.

Of course there are dots that need to be connected, linkages that need to be drawn that aren't clear yet. But what is clear is that there are forces at work that are dragging down full and fair deployment of DG and other new energy technology solutions. And it's also clear that we are lacking leadership on these important issues compared with other countries and systems.

Power generation and infrastructure is the most capital-intensive pursuit of any industry in our country, except maybe real estate. We need to bring the best thinking in technology, regulation, and finance together to ensure that the solutions for the future meet the new, difficult challenges. We can't do it with old statutes enacted in 1935, or with state commissions whose authority hasn't been reviewed since 1922, or without fuller cooperation and regional coordination.

The institutions and processes that brought us so far in the last 50 years need to go through rehabilitation of their own, to prepare and sustain us for the next 50 years, or we will have dysfunction and disconnect that put our economy and competitive advantages at risk.

For example, rather than trying to usher in competitive markets on a global NOPR basis, it might make more sense for the FERC to move to a regional-centric form of regulation, market monitoring and enforcement to make sure markets are workable. If the markets are truly regional, then we need to bring regulators out to the regional marketplace, like the DOE or EPA regional offices. You can't sit and manage the markets exclusively in D.C., so that is likely to need to change in the future.

Unfortunately we don't act in a visionary manner until we are in crisis. Then we take action, but it's not always as effective as we can be

We need integrated solutions to service the needs of an increasingly electrified economy, increasing imports and globalization, and the escalating need for efficiency. It's not all about gas, coal, or nuclear. It's not my state versus yours, gas versus electric, DG versus the centralized grid. We have a tendency to look at these issues in absolutist terms and solely focus on the past, and that kind of thinking is holding us back.

We need to understand these issues now on a regional, hemispheric, and global basis-driven by the customer and services and products they demand, and not the products of the '70s. We need more forward-thinking, visionary thinking and strategies to sustain the world's most reliable power system into the future.

Articles found on this page are available to subscribers only. For more information about obtaining a username and password, please call our Customer Service Department at 1-800-368-5001.

Source URL: http://www.fortnightly.com/fortnightly/2003/12/generation-roundtable-power-flux