The top traders, investors and managers tell why energy convergence is still a pipe dream.

[Graphic tables included in the print version of the Fortnightly are not included in this electronic version.]

Energy investors seemed less willing in 1999 to greet electric/gas combination mergers with the kind of blind enthusiasm they tended to show in prior years.

Instead, they now demand proof that energy convergence really does create tangible value beyond the mere sum of the parts. At least that's the impression gained from talking with John W. Barr, managing director at SG Barr Devlin, part of the French global banking institution Société Générale.

"The stock price reaction to announced utility mergers changed from an automatic rise in both prices to an automatic decline in both prices," says Barr. He adds that of the 32 deals announced in 1999, the stock value declined in over half the cases.

"The gallows humor would be that [in the beginning] the market couldn't find a deal that it didn't like [and then later on] couldn't find a deal that it did like, in 1999."

Some analysts say the fall in shares reflects only that the pool of traditional investors in the energy sector is just not large enough to support the flurry of mergers taking place, especially since that pool dwindled in 1999 due to the lure of technology stocks.

Nevertheless, Barr maintains that the value of "convergence" remains to be seen, because merging gas and electric companies do seem to outperform others. Furthermore, adds Barr, "If the overall stock market has a correction, I think you will find that investors will like utilities again."

In fact, many utility and energy company stock prices got a boost early this year when investors ran for safety to utility stocks as technology stock prices declined. The PHLX Utilities Index rose 4 percent, while share prices of merging gas and electric companies like Duke Energy, Edison International, PG&E Corp., Reliant Energy and TXU increased. That marked a reversal from 1999, the worst year for electric utility stocks since 1974, according to market analysts.

Barr believes the financial picture will improve for energy companies pursuing a gas and electric strategy, but warns that the sources of unregulated earnings that might result from a "convergence" deal comprise a fairly short list.

In addition, some analysts say last year's no-confidence vote in merged electric and gas companies could reflect the energy industry's own growing skepticism of their value.

A Btu Market? Not Quite Yet

Ninety-nine percent of the mergers between gas and power companies that took place during the last few years have not fully integrated the two commodities. The deals haven't reached their promised potentials.

That's the view of Mike Flinn, executive vice president and chief operating officer at PG&E Energy Trading.

Duke Energy's chairman, president and CEO, Richard Priory, also is skeptical.

"If you look at some of the other combinations where gas might have bought electric or, in some cases, electric might have bought gas, most of those really did not integrate the companies together. They kept an electric company and kept a gas company and put them under one corporate umbrella," Priory says.

Flinn explains that at some merged companies, "gas people are on one floor and power is on another floor. They never talk. They have these predetermined transfer prices and everybody manages their blue or green widget, but no one is looking [at the big picture]."

And Flinn makes no claim that his own company is among the 1 percent of those fully integrated.

In its convergence merger in January 1997, PG&E Corp. paid approximately $1.5 billion for Valero Natural Gas Co. Valero operated a 7,500-mile gas pipeline system and eight natural gas processing plants in Texas, as part of the parent company Valero Energy Corp. At the time, the Valero acquisition was one of three conducted by PG&E Corp. in the natural gas sector.

Flinn says that his company still remains about halfway from full integration. PG&E's integration effort was delayed because of its recent focus on perfecting the company's infrastructure, he says. Nevertheless, Flinn adds, a big distinction remains between PG&E's integration approach and others.

For example, he says, if employees on the gas and electric sides simply exchange information about how much gas was burned, or if the power plant operator tells a power trader how many megawatts to sell, that is not true integration.

"They are just managing input and output from a volume perspective and are not managing their spark-spread risk," he says.

(The spark spread marks the difference between the input price of the natural gas fuel and the output price of the electricity generated, with each expressed in an equivalent form to reflect the heat content of the gas and the heat-rate efficiency of the plant. Spark spread is commonly expressed in terms of cost per Btu, or cost per megawatt-hour. It can help operators decide whether to generate power or toll the plant and sell the fuel as a commodity.)

Flinn discusses the value of tolling strategies. He also explains how a combined gas-power company can use a hot power market to escape a profit-denting price cap on the gas commodity side, or vice versa:

"As we combine our gas and power businesses ¼ we are going to ¼ do things on the power grid side combined with pipeline assets. In the wintertime that allows us to replicate [such things as] market area peaking storage."

Flinn wants access to pipeline capacity and supply both to meet the needs of its power plants "and the lucrative opportunities around the power side of the equation in the summer time."

A key component in PG&E's convergence strategy is replicating market area peaking storage in a virtual way, he says. That means using new combined-cycle power units during the winter.

"If we load in gas supply to run [the power plant] for the entire winter, and if we have markets that peak and need gas, we can buy power off the grid. [We] shut down the power plant, keep our power cells whole and go sell the natural gas to a gas distributor," says Flinn.

"Historically, to meet that peak-day need, someone would have to go out and either pay and develop market area storage, or pay and develop production area storage combined with long-haul capacity," Flinn notes.

But in the future the gas industry won't have that built-in redundancy in pipeline capacity.

"As you don't fund this kind of built-in redundancy over time, you need to look for more efficient ways to do it," he says. In other words, people who rely on buying delivered gas from the market during winter to run their power plants probably just will not run them, he says.

"[In another strategy], if you have a rate cap on the pipe and vertically integrate it with your generation business, [you can] capture the value on the power side, where you have an uncapped value proposition. [You are] raising the rate of return capability for a pipe even though it is being recorded over on the power side," he explains.

Other strategies abound for integrating gas and power assets. That may explain why over 50 percent of investor-owned electric utilities own or have a significant ownership interest or alliance with a gas company, according to the Edison Electric Institute. In addition, EEI data reveal that 26 percent of revenues from electric IOUs in 1998 came from a combination of natural gas distribution, processing, pipeline and trading operations.

Back-Office Savings? Not the Key Factor

In a merger between natural gas and electric concerns, the most immediate and easily calculable savings come from consolidating duplicated business units, says Hugh Holman, senior equity analyst at investment bank Robertson Stephens, part of Fleet Financial Services. Investors and company managers usually expect immediate gains from cost reductions, he explains.

"It may be accounting functions, human resources functions and management functions that are duplicative. Taking an organization from $5 billion to $10 billion doesn't mean that you have to have twice as many people in that task," Holman says. For example, Duke's Priory describes going "viciously" after duplicative businesses after his company's electric and gas merger.

"We [were] going to save X million dollars in insurance and we [were] going to reduce the accounting department by X percentage," Priory recalls.

In 1997, as part of its first convergence merger, Duke Power paid $7.7 billion for the Houston-based PanEnergy gas pipeline, and created Duke Energy.

Priory admits that in regions where the company would sell gas product to electric customers, growth is more difficult to track because of organizational changes.

In fact, the No. 1 revenue earner and the main reason for these mergers is to provide gas to power conversion facilities, he says.

"The electrons - that is where the bulk of the [financial] revenue will be coming from," Priory expounds. "You can deliver an electron in Connecticut but make it from a molecule in the Gulf Coast, Western Canada or at Sable Island."

"A real converged capability is that you can pick the molecule of least cost and deliver it to that machine and convert it into the electron that may be desired in Connecticut. You do it in a way which creates the most economic value for you and your customer."

Deregulation?

Sometimes A Hindrance

At Robertson Stephens, Hugh Holman believes deregulation handicaps regulated utilities that are moving to competition. He's convinced that the retail energy marketers - the Enrons and Dynegys - will take market share from incumbents because they don't suffer from the handicap of the deregulation process.

"It seems that if you are a utility, the challenges you face are almost overwhelming, from the task of having to deal with regulators to the task of negotiating in the states in which you do business," he says.

Holman estimates that the organizational change required of incumbent utilities could take three to five years. For example, according to Holman, the CEO of AES estimates that transforming the company's recent acquisition, Cilcorp, into an AES company will take three to five years. "This is the period of time where newcomers are in a great position to capture market share from the incumbents," Holman adds.

Similarly, Duke Energy's Richard Priory believes his company would be five years behind the competition if it weren't for the PanEnergy acquisition having occurred in 1997.

Holman continues, "From my work in telecommunications and airlines, if you go back and look at the stock price performance of the companies that are in those businesses, the last place you want to be putting your money to work is with the incumbents.

"They do not generally fare well in deregulation and, by definition, a regulated monopoly is going to lose market share. It doesn't mean they are going to lose money, but they are on the defensive rather than the offensive," Holman says.

That is the lesson Enron learned when it bought utility Portland General Electric, according to Stephen Bergstrom, president and chief operating officer at Dynegy.

"The biggest difference between our merger with Illinova for $7.5 billion and Enron's purchase of Portland General Electric is that Illinova was further along in its restructuring effort," he says. "Enron had to deal with a public service commission to accomplish what we [had] already accomplished with Illinois Power."

Bergstrom adds, "[With] Illinova, they had already gotten an agreement from the commission to spin their generation off; they had already gotten their rates frozen until 2004. Any cost reductions that we get out of the transaction all falls to our bottom line."

Commission approval of Dynegy's merger with Illinova, explains Bergstrom, was nothing more than a rubber stamp. The regulators had no ability to reopen the deal.

"We did not have to go in and negotiate with the commission. That is what is holding up most of these mergers ¼ the state commissions are extracting some of the value.

Bergstrom says Dynegy was able to progress beyond what Enron was able to do, although he believes that Enron would benefit more if it were to buy PGE today.

Some details, however, remain for Dynegy to iron out with the Illinois Commerce Commission.

"We hope to work a deal out with the commission to where we can put some type of shared savings deal together with them. Right now, traditional gas utility Nicor has negotiated a performance rate structure where if they do better than some benchmark, they can keep [the profits]. We would like to do something similar," Bergstrom says.

As for the merger itself, Bergstrom notes that on the electric side, Dynegy has spun off all the generation to the unregulated side, and has set up a power purchase agreement between the utility and the generating company.

"Our strategy with the utility is to optimize the costs in the transmission, distribution business. Get it to be the absolute lowest-cost service provider in the Midwest for distribution and transmission and make sure that we are completely reliable. We plan on spending quite a bit of money this year to bolster the distribution and transmission system."

Holman considers Dynegy, Enron, AES and Calpine the growth companies of the industry.

Dynegy's acquisition of a utility won't hurt it, says Holman, because as Bergstrom explained, Illinova was further along in restructuring.

"Calpine and Dynegy outperformed the NASDAQ. AES and Enron did better than the Dow Industrials [in 1999]," Holman says. "These growth companies trade at very high multiples of earnings because investors are anticipating today greater earnings power of the company down the road. Enron we estimate 15 percent growth in earnings per share. For AES and Dynegy, we anticipate 20 percent growth in earnings per share."

Jeffrey R. Holzschuh, managing director at Morgan Stanley, says companies like Duke Energy - which targets 10 percent earnings growth per share, up from 3 percent a few years ago - cannot be categorized with utilities, nor can they be classed with Enron and Dynegy. Instead, they are somewhere in between. Many of the electric utilities turned merchant plant operators, traders and marketers, he adds, will become difficult to classify because of the changing nature of the business.

Holman believes within the next three to five years, as more states restructure, Wall Street will be better able to classify the earnings potential of evolving power companies.

Power Trading? Margins Too Thin to

Survive Without Gas

After a second summer of contract defaults and consequential financial losses to energy companies, having a trading floor is not as glamorous as it once was. Yet experts say it remains a necessary part of the electric and gas strategy. Furthermore, power marketing is a zero-margin business, and little revenue enhancement has resulted from convergence deals, claims John Barr.

"What happened is power marketing collapsed with the power marketer defaults [as a result of the Midwest price spikes]," Barr says. "You could hardly call it an industry at this point. The result of all that is too many traders, too much capacity, too much credit risk and zero margins."

Barr concludes, "The only ones that are making money are probably Enron and Dynegy."

In fact, John R. Stephenson, principal at Navigant Consulting, has looked at the margins for both electric and gas revenues. He finds that companies that don't combine their electric and gas trading operations will experience diminishing returns.

In a study of the top industry players, Stephenson found that in 1998 the range of physical gross as a percent of revenue was 0.03 percent to 2.19 percent. The average was 1.5 percent for gas and electric combined.

"Last year when we did it based on 1997 data, the average margin was 2 percent," he says. "We have gone from a margin of 2 percent to 1.5 percent. ¼ What this means is that if you sell a dollar revenue wise, you are lucky to make 1.5 cents."

To increase the margins, Stephenson says energy companies have been adding products and services such as risk management services, taking risks for customers, pricing options and offering financing.

Furthermore, Stephenson adds, there is tremendous churning of financial volumes.

"You see as much as 6:1 in natural gas, and in power, it trades as high as 9:1. [For example], if you take 1 million (MM) Btu of physical gas, energy companies are trading as much as 6 MMBtu of financial gas," he says.

Stephenson blames the high churn ratio on the volume focus many energy companies have adopted.

"They do this because the only published metric these companies have to go on are [FT Energy's] Megawatt Daily and McGraw-Hill's Power Markets Week [newsletters]," he says. But Stephenson claims there are problems with this published data because no standard for reporting data exists.

"Some people report on the physical volumes and some people report physical and financial volumes combined," he says. "We have found that they understate from 3 percent [and] overstate by 72 percent."

Every time an energy company makes such a transaction to boost volumes for window-dressing, warns Stephenson, it adds costs or takes speculative positions that could erode margins.

Long-Term Investments?

Maybe You Should Rent

"We believe there [are] going to be some cycles associated with these [electric and natural gas] commodities. Someone in this business has to effectively manage around those cycles, and that is why you will often hear us talking about buying and selling assets," says Duke Energy's Priory.

Priory says he continually must guard against owning power plants where they are not needed and shorting gas in regions where gas is not available at an attractive price. An energy company should be able to continually reposition its assets as market conditions change, he says.

"It is no longer a buy and hold deal. You used to always buy and hold for electric utilities. You would buy your plant [and] forecast the economic cycle for the next 25 years - with the full expectation that you would own that plant for the next 25 years. Then you would play out that cycle. You would win or you would lose based on how well you did against that cycle," he says.

The energy industry, however, has changed in the past four years, says Priory. Instead of the traditional buy and hold deal, he says the business revolves around buy and profit-generation cycles.

"We have to continue to reshuffle our assets and move them around and reposition them not only to maximize profit, but the value creation for our customers," says Priory.

"[For example], we sold our Midwest pipelines - the Panhandle Eastern Pipeline Co. and Trunkline Gas Co. It was our belief that the markets in the Midwest were getting tighter and tighter from the pipeline's perspective, in that there was an abundance of pipeline capacity," he notes.

"Every time we wanted to [renew] a contract with customers they were beating us over the head because they had five other offers from other suppliers. We thought [we'd] rather be a renter than an owner."

In the end, Priory's biggest customer bought the pipeline to create a vertical integration. CMS Energy paid $2.2 billion for Duke Energy's pipeline assets and the storage related to those systems and the Trunkline LNG Co. Terminal.

"We sold and re-deployed [the $2.2 billion] in other market areas where we think there is excellent growth potential," he says.

Meanwhile, in a similar strategy, PG&E Corp. is selling its pipeline assets.

"While we will be selling, it shouldn't send any message [contrary] to our belief in convergence and opportunities around natural gas and power associated with generation assets and pipeline assets," PG&E Energy Trading's Flinn says. "It really has more to do with the liquids business attached to that system."

Flinn concludes, "We looked at that along with the price paid for that, and [the pipeline] didn't look to be the right value proposition for us. Not because of the pipe, but really because of the overall business that was mainly tied to the liquids piece."

PG&E will retain PG&E Northwest, an interstate pipeline, he says. "Of the Texas assets most of that is going to be sold."

Flinn explains, "[In] the Texas intrastate area there is over-capacity to meet market needs, and yet you don't have rate-based security around that business like you would on an interstate business. That has gotten very competitive.

"I think the value proposition is a bit different around an interstate [pipeline], assuming that you paid the right amount for it. I would say [that] on these intra-state [pipelines], we are seeing right now a pretty large consolidation effort take place in Texas and we will see some of that continue in Louisiana," he says.

Flinn describes some of his considerations for determining whether to acquire pipeline assets.

"We look at is not just the ownership of a pipeline but we look at our capability to access long-term pipeline capacity. We may get that a number of ways. Instead of buying a company to do it, we may sign up for a long-term lease," he says.

"Also, another avenue that we have to assess is that we see unbundling take place at the state level, where utilities go to migrate away from the merchant function ¼ and open up their markets," he says.

Flinn says utilities will be looking to relieve themselves of their long-term commitments with pipelines.

"We will be participating in that unbundling process and looking at strategic pieces of capacity that do integrate with our generation business. So we will look at it from a contractual basis, assets that we will manage for others, our customer base, as well as the ownership angle and putting all those pieces together from a pipeline grid to integrate from a generation basis," says Flinn.

Turning the Tables:

Catering to the Converged

Kinder Morgan has taken a different route than most companies. It "sells the bullets" to the already converged companies that are fighting it out.

Jay Hopper, vice president at Kinder Morgan Power (KMP), a year-old division, sells 15- to 20-year tolling agreements to energy marketers on 550-megawatt plants Kinder Morgan has built on its pipeline.

Under a tolling agreement, a power marketer or commercial electricity customer provides the fuel, say natural gas, to produce electricity for the marketer or customer at an agreed upon spark spread, dependent on the plant's efficiency as measured by its heat rate, and receives the rights to electricity output.

"All of our plants are contracted before they are built," Hopper explains.

His company's strategy is not to be a trader but to be a developer, operator and marketer to power traders.

"[The way] we make the strategy work is first the location of the pipe. When you look at where Kinder Morgan's pipe [is laid], it has access to [the entire] gas basis, whether it is the Gulf, Anadarko, the Rockies or Canada," he says. "If somebody builds a converter on our pipe, they are located to take advantage of diversity in the gas market.

"The second part of our strategy is that we have located plant sites from an electric transmission perspective where they will enhance the system and provide ancillary services into the network," he says.

Hopper believes his success comes from having a flexible plant design that has swing operation. In that way, it can vary its output greatly on an hourly basis. KMP also has a significant order of turbines from General Electric to back up that strategy.

In addition, KMP has designed computer software that tells the trading floor, based on the outside temperature, humidity and what is going on in the world, the amount of gas necessary to produce a specific electric demand. "So they know exactly what it is costing them when they are making a trade," Hopper says.

The cost for KMP's service involves a monthly reservation fee, a fee for every megawatt-hour converted, and the customer pays for its own fuel, in addition to purchasing the right to do that for the next 20 years, Hopper says.

KMP's big obstacle, because it does not have an energy marketing or trading business, is to build plants in markets that will remain attractive to customers for use as backup.

"We can't just unilaterally go out an build plants, but that imposes on us the discipline of having to go out and get customers who say, 'this is where we will pay to toll your plant for a long period of time,'" Hopper says.

Hopper explains that his customers rank among the top 10 power marketers. They tend to trade nationwide and need physical contracts to back up some portion of their trade. To do that, they depend on flexible generation plants.

"What we sign is tolling contracts with power marketers and then they bring their gas to the plant and they tell us when they want us to convert it," he says.

Due to the long-term nature of its contracts, KMP receives a lower return than companies in merchant generation. "Because we are signing tolling agreements long term, marketers end up with the upside and downside, which can be significant. We end up with more of a regulated-kind of return."

Earnings to date have not been significant. Kinder Morgan has three power plants operating in Colorado and it contributes a certain amount of margin to the bottom line, he says.

"[Of course], the plants that are scheduled to come online won't be online until spring of 2002. So, there won't be any significant change in Kinder Morgan Power's earnings between now and then," he says.

Hopper says that the plants under development will be on the GPL pipeline, which has broad coverage of the Western, Central and Midwest U.S. regions. In addition, Hopper's clients have asked KMP to build these types of plants elsewhere.

"We have a plant that is designed to be extremely flexible. That is very important to our strategy in the Midwest because large nukes and coal plants dominate the Midwest power-grid. What that means to us is that gas-fired plants are not going to be on the margin at the peak," he says. "[Therefore], we need a plant that can get in and out of the market quickly. So we have a specific design to do that."

Hopper says that his plants are a nice fit for the energy marketer pursuing a convergence play.

"Our plant is really designed to take advantage of convergence, so that they can decide on an hourly basis whether they are selling Btus or they are selling electrons," he says. "By trying to focus in on putting these flexible plants along all of our pipe, we are in a position to sell physical backup for convergence to marketers in all of the regions in the Midwest."

Hopper speculates that the trader's strategy in buying tolling agreements is to find a long-term off-take contract or some portion of it, and play the hourly market with the rest.

But Kinder Morgan is not the only company courting business from the big energy marketers. Tenaska, AES and Panda Energy International share that niche, Hopper says.

And though his company's view of convergence is limited to providing midstream services, Hopper observes that the electric side of the trading houses are of greater magnitude than the gas and tend to drive the decision-making.

True convergence in the industry, however, remains an unfulfilled promise, he adds. "In the top 10, the trading floors are coordinated between power and gas. But most of the [others] are not converged."

Richard Stavros is senior editor at Public Utilities Fortnightly.

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