Frank Napolitano is wearing a new hat.
The Lehman Brothers investment banker, who has co-headed the firm’s global power group since 2003, is now managing director and global head of origination and sales for Lehman’s new energy-trading organization.
Napolitano’s career move is more than just another title change on Wall Street. As part of a broad trend in the financial sector, it demonstrates a remarkable commitment of resources that banks and other financial firms are putting into the energy-risk market. More than a dozen major money-center banks and investment houses have launched or expanded their U.S. energy-trading operations in the past two years (see Table 1, “Power on Wall Street,” p. 33). Additionally, more than 120 hedge funds and other investment groups have jumped into the energy-trading arena, in pursuit of stellar profits reported by some funds. The result is a market once again flush with volume, with the added benefits of more creditworthy trading counterparties, trading a richer variety of contracts.
“We are building a customer-oriented business and not a proprietary trading shop,” Napolitano says. “Corporate managers of energy companies are asking us to provide commodity solutions. Along with core corporate finance and capital markets strengths in the power and natural resources areas, we now have the capability of providing a commodity-related window for customers.”
Wall Street’s commitment of banking resources might signal a coming shift in the U.S. energy markets—a shift that could change the way utilities manage their energy-supply assets and price risks. “If the market keeps moving like it is, all but a few utilities will have the banks do their risk management and procurement,” says Peter Fusaro, chairman of Global Change Associates in New York. “Banks have the management infrastructure, the balance sheets and risk-taking capabilities to manage energy risks. That’s not the forte of a utility company, and many won’t want the overhead anymore.”
In addition to the infrastructure costs, that overhead includes compliance and investor-relations factors for investor-owned companies. Nevertheless, most utilities likely will move slowly and cautiously into the new world of energy-risk management. Until they are sure the U.S. energy-trading field is a stable place to expand their business, utility executives might be more inclined to stick with what they know—time-honored rate-recovery mechanisms, with minimalist hedging strategies.
In the months following Enron’s bankruptcy in December 2001, trading volumes and liquidity for electricity commodities evaporated. The public conflagration of Enron, as well as Dynegy, Williams, and other boom-era market makers, sent electric and gas utilities fleeing from the energy-trading business. Even such aggressive companies as Duke Energy called in their unregulated bets and retreated to a “back-to-basics” bunker.
Less apparent than the flight of the utilities, but no less important, was the withdrawal of major financial institutions from electricity and other energy markets.
For example, less than a year after UBS Warburg acquired Enron’s energy-marketing operation—including the much-celebrated EnronOnline electronic trading platform—the bank quietly shut off the lights in Houston. Hundreds of energy traders were laid off, and EnronOnline—renamed UBSWenergy—vanished completely.
UBS Warburg was neither the first nor the last banking company to pack up its electricity-trading desk after the bubble burst. Merrill Lynch, JP Morgan, Citigroup and several other banks withdrew from or scaled back their energy trading during 2002 and 2003. When the attrition finally stopped, just two major financial institutions—Morgan Stanley and Goldman Sachs—were left to divide the field between them.
By then, it wasn’t much of a field. Volumes were anemic, prices were volatile, and creditworthy counterparties were scarce. Futures markets effectively collapsed, leaving little trading activity except physically settled bilateral contracts. Public Utilities Fortnightly noted at the time, “Electricity trading may not be dead, but it is definitely in a transitory state between its high-flying past life and an unknown future” (“Down But Not Out,” Public Utilities Fortnightly, Jan. 15, 2003).
However, even at the market’s nadir, signs of recovery began to appear. Bank of America, for example, filed to become an energy trader in 2002, and Merrill Lynch opened a small gas-trading desk in 2003. The following year, a host of banks and investment groups began hiring traders and building their presence on the post-Enron landscape. Since then, banks have plunged into the fray.
“There are more financial entities in the market than there were in the past,” says John Woodley, a managing director with Morgan Stanley. “The outcome has been growth in liquidity, more products, and more competition to provide risk-management services.”
Quantifying the accompanying rise in trading volume can be difficult, because markets have been changing and growing rapidly (see Table 2, “Electricity Futures: Evolution at NYMEX,” p. 34). For example, in mid-2003 three electricity futures contracts were being traded on the New York Mercantile Exchange (NYMEX). At this writing, NYMEX offers 35 financially settled electricity futures contracts, and one options contract. Additionally, the Intercontinental Exchange (ICE), based in London, trades a variety of contracts across 18 U.S. hubs.
Volumes on these contracts vary; NYMEX recently delisted three physically settled futures contracts, and price uncertainties in late 2005 drove some participants into defensive mode, which reportedly constrained volume somewhat. But through most of 2005 and continuing into 2006, traders have seen a healthy flow of transactions, accompanied by respectable levels of liquidity and price transparency.
“The market sprang back very quickly,” Woodley says. “In terms of depth and term, it is probably as liquid as it has ever been. One merely has to look at the recent refinancings of large power plants on the back of long-term off-take contracts to see this.”
As examples, he cites the oversubscribed debt flotation for Complete Energy Holdings’ acquisition of the 1,000-MW La Paloma power plant in California; the successful syndication of $950 million in debt for the acquisition of Reliant Energy’s New York City power plants by Madison Dearborn Partners and U.S. Power Generating; and a competitive field of lenders that assembled to finance the $410 million acquisition of former AEP wholesale plants by Sempra Energy and the Carlyle/Riverstone private equity group.
The perception of diminishing off-take risks bolstered lenders’ interest in such transactions—in part due to improved liquidity. Nearly half of the La Paloma facility’s output, for example, is sold in California’s wholesale power market, not under a long-term contract. With dozens of standardized electricity-futures contracts being traded and cleared in over-the-counter (OTC) exchanges, plant owners have a better chance of finding buyers, as well as finding hedging products that will allow them to manage their commodity-price risks.
Perhaps most important, contract terms have stretched out from weeks and months into years, providing more of the kind of price certainty counterparties need to hedge their positions effectively.
“It was difficult for utilities to move into the longer-dated hedge products because of the immaturity of deregulation,” says Fran Shields, a senior executive with Accenture in Philadelphia. “We had a lot of trading in the short space, but not much emphasis on the longer market. The difference today is that banks are bringing longer-dated instruments into the cleared markets. We have a broader array of products and services now that we didn’t have before.”
Memories of Enron and the agonizing collapse of the U.S. energy-trading market remain fresh in the minds of utilities, as well as their shareholders and regulators. In this context, many load-serving utilities likely will have a lukewarm response to maturing energy markets. Of course, they welcome more robust markets that make it easier to sell excess capacity and hedge fuel-price risks in accordance with PUC recommendations. But beyond that, energy trading as a business activity raises more risks than it manages for utilities—most of which deal with price fluctuations the old-fashioned way: by passing them through to ratepayers.
“Energy trading is a prudent approach that could save utilities some costs,” Fusaro says. “But we’re not seeing a stampede, because utilities like to keep a low profile at the PUC, and every PUC in the country already has its hands full dealing with other issues.”
At the same time, however, utilities and regulators understand that failure to hedge against price spikes—particularly in natural-gas markets—can be a fatal mistake. In the most recent example, Hurricanes Katrina and Rita locked-in a significant share of U.S. natural-gas production capacity beginning in September 2005, driving gas prices to historic high levels. Some utilities conducted hearings and launched investigations into hedging techniques. In New Jersey, upon approving a Katrina-related rate-increase schedule for South Jersey Gas Co., the state Board of Public Utilities (BPU) launched a study to examine price-hedging practices among the state’s gas distributors and make recommendations. And the California Public Utilities Commission (CPUC) recently approved further expansions to utility gas-price hedging commitments, after approving hedging surcharges for California IOUs late last year.
“We’re working hard to stay ahead of the rising natural-gas price curve this winter,” stated PUC President Michael Peevey. “Today’s decision gives SoCalGas and SDG&E more power to rein in volatile natural gas prices and reduce customer bill impacts.”
Over time, price pressures will nudge utility companies toward more sophisticated risk-management strategies—albeit less so at operating companies than at the holding company level, where investors will seek growth in unregulated businesses. “The market is back, in a different way,” Shields says. “The future of energy trading is global, multi-commodity and both physical and financial.” As old wounds heal and experience builds, integrated companies will look again at energy-price arbitrage as a competitive opportunity.
“Utilities are at a strategic crossroads,” Shields says. “They are asking whether the parts may be greater than the whole, whether they should keep them conglomerated or not, and in either case, how energy trading fits into the business.”
Another key question for utilities—as well as their ratepayers and regulators—is whether the current market trends are sustainable, or whether they are just part of another boom-bust cycle. This uncertainty is exacerbated by what is perceived as the sudden interest of so many banking and investment groups, some of whom are notorious for following the latest exuberant fad on Wall Street.
“A lot of the new players have a history of getting in and out of the commodity business,” says Brett Friedman, managing director with Risk Capital Management Partners in New York. Many of these firms could pack up their trading desks again if they find margins are tighter than they expected.
“Some banks are overestimating the returns they realistically will see, because they’ve heard about others making a lot of money,” Friedman says. “But 2005 had a lot of volatility. If you couldn’t make money in 2005, I don’t know when you would.”
Moreover, the hedge funds and investor groups that are providing volume and liquidity in the markets depend on the current volatile-and-rising fuel-price conditions to generate arbitrage income. While current trends suggest energy-price pressures and volatility will persist for at least several years, hedge funds might lose interest in an increasingly competitive and efficient market. Time and experience will show which of the new market entrants have staying power.
“Getting all those traders in one room is a capital-intensive exercise,” Friedman says. “I see liquidity and volume going up, but the market isn’t that big. Not all the banks will be able to make a living at it.”
Despite a measure of skepticism about some of the market’s participants, the energy trading business in general is being rebuilt in a way that seems inherently more stable and sustainable. Instead of being dominated by “paper” trades, energy-marketing volumes today reflect a better balance of physically and financially settled transactions. The physical markets themselves are more accessible, with RTOs and ISOs maturing significantly in the past two years. And market participants are subjected to rigorous credit-control policies and standards, developed to prevent the kind of counterparty defaults that decimated confidence in the markets the last time around.
“The overall credit quality of the industry is better,” says Sid Jacobson, managing consultant with PA Consulting Group’s global energy practice in New York. “Financial institutions are bringing their balance sheets to the game, and the industry’s sophistication is increasing, with more sophisticated price structures and more intelligent contracts.”
Credit discipline is evident not just among financial firms. Market participants, including merchant-power companies and other energy suppliers, have endured significant scrutiny of their balance sheets and business plans in the last few years. Those that remain in the market are, by definition, standing on more solid financial footing.
“There has been a growing risk-management culture in the utility sector over the last few years,” says Jonathan Taylor, head of commodities sales for Barclays Capital in London. “Today people are thinking in terms of risk-management tools, not the frequent transactions coming out of a trading desk. They understand their risks better and are managing them appropriately.”
Such sophistication among market participants likely will increase along with greater depth in OTC markets and services. Cumbersome bilateral contracts increasingly are giving way to more standardized OTC contracts, reducing the transactional friction and credit barriers that have kept energy markets from maturing. Additionally, major trading exchanges—NYMEX and the ICE—are developing increasingly sophisticated electronic clearing services to facilitate OTC trading among counterparties. “Exchange clearing has created an easier entry into the market, and made it possible for financial institutions to provide services beyond just trading,” Jacobson says.
Banks are offering a growing variety of contracts, not only for energy supplies but also related products. For example, the notional value of weather-contract trades nearly doubled, from $4.6 billion to $8.4 billion, between fiscal years 2004 and 2005, according to the Weather Risk Management Association. Similarly, emissions credits have become increasingly active in the United States and on the world stage, and are expected to grow in importance as environmental compliance becomes more challenging.
“Mitigating greenhouse gases will drive technology shifts and disrupt the market,” Fusaro says. “It will affect the entire value chain, including emissions trading. The linkage between emissions and power prices is becoming tighter.”
A few utility holding companies still are strong energy-market makers themselves; specifically, the wholesale trading affiliates of Constellation, Entergy, and Sempra are perennial leaders in terms of trading volume. But for most utility companies, the prevailing “back-to-basics” business strategy deters them from contemplating more aggressive arbitrage strategies—at least for the time being.
“With respect to financial hedging going forward, management will need to determine the right risk-reward balance,” says Pete Sheffield, a Duke Energy spokesperson. “Duke’s post-merger marketing and trading focus will be similar to the current Cinergy platform—shorter in term with less collateral required.”
Duke Energy is emblematic of companies that brought an ambitious, integrated approach to energy marketing during the boom years, and have since adopted a back-to-basics business posture. Duke spun off the Duke Energy North America (DENA) trading book to Barclays Capital late last year, and in January 2006 LS Power agreed to acquire 6,200 MW of DENA’s generating capacity in the Western and Northeastern United States for about $1.5 billion.
Such transactions mark not only the final dissolution of the old energy-trading business model, but also the genesis of a new model that might change the strategic equation for U.S. utility companies. If the energy-trading markets remain robust, utility companies eventually will migrate toward more active risk-management strategies.
“The markets have come a long way in the last few years,” Jacobson says. “Utilities should focus on marrying the whole picture together and not just thinking of it as more marketers to call.”