Uncertain future looms for North America's intertwined natural gas and power markets

Dec. 2, 2002
The implosion of Houston-based Enron Corp. in the autumn of 2001 can in some ways be compared with the horrific events of Sept. 11, 2001: Both caused pervasive and irreparable damage—the latter to America's sense of security and the former to the momentum of a once-thriving energy industry.

The implosion of Houston-based Enron Corp. in the autumn of 2001 can in some ways be compared with the horrific events of Sept. 11, 2001: Both caused pervasive and irreparable damage—the latter to America's sense of security and the former to the momentum of a once-thriving energy industry.

While industry players were shaking their heads in disbelief at Enron's demise in early November 2001, the natural gas market was suffering from the first repercussions. In early November, as Enron closed its Henry Hub positions on the New York Mercantile Exchange (NYMEX), open interest levels dropped dramatically, and volatility increased, with Henry Hub futures experiencing a 33¢/MMbtu, 1-day loss on Nov. 5. During the same period, liquidity in the over-the-counter (OTC) markets for locational gas in the West began to dry up as players scurried to cover any open positions held with Enron and lost Enron Online as a trading medium and source of price discovery.

Following this initial period of market disruption came a period of balance-sheet scrutiny in the winter of 2002 when companies, at first primarily from the power sector, scrambled to shore up capital holdings. At the same time, ratings agencies assessed just how leveraged the industry had become, and the government got involved in determining which accounting firms and Wall Street banks had helped it along.

What has followed is a spate of announced asset sales, lay-offs, downsizings, and credit downgrades that is far from over. Companies have become more introspective, assessing core strengths and possible liabilities. In most cases, the first business area under attack was energy trading—in particular, trading of the speculative kind. Speculators and market-makers who once rode high as the wild cowboys of the energy frontier were now the suspected criminals of what was perceived by many as a grossly unlawful market.

As the investigations expanded, El Paso Corp., Houston, and a handful of California power generators came under fire for allegedly manipulating natural gas and power prices, respectively, by withholding capacity during the 2000-01 California energy crises. In addition, the price reporting methodology of market observers such as Platts was investigated in the wake of wash trading and subjective price reporting scandals by market participants. This alleged misbehavior resulted in an investigation by the Federal Energy Regulatory Commission and has renewed the national debate over the desirability of energy market deregulation and its ability to limit profit incentives created by loopholes and market manipulation.

This push for more-rigorous market monitoring by FERC's newly created Office of Market Oversight and Investigations (OMOI) has instilled fear in many energy companies. What began as company introspection has turned into a virtual clampdown, not only on external information exchanges, but also with regard to the very role of trading in diversified business models.

The somewhat symbiotic power and natural gas industries are facing Herculean challenges created by the developments of the past 12 months. There are many issues facing the markets over the near-to-long-term, but the following are among the most critical.

Credit crunch, irrational exuberance backlash

After Enron virtually killed the highly leveraged business model overnight and investment banks have strongly reevaluated their lending practices to the US power and natural gas industries, to say that credit has become scarce would be a gross understatement. In fact, the well is bone dry. Leveraged power companies are trimming assets and cutting out all the fat from their diversified operations in everything from trading desks to European subsidiaries.

In the free-money environment of a few years ago, power plant projects had been relatively easy to finance with 80:20 debt-to-equity ratios. This period of plentiful capital led to a generation capacity construction boom and "irrational exuberance," in which combined-cycle gas turbines were going up at rapid speed nationwide and stock prices of companies such as San Jose, Calif.-based Calpine Corp. and Arlington, Va.-based AES Corp. blossomed.

In the current climate, one of the only ways to secure project financing from the capital markets is with a long-term supply contract that guarantees a revenue stream. Until the electricity market design rules laid out in FERC's Standard Market Design (SMD) notice of proposed rulemaking (NOPR) are finalized, securing a long-term supply contract will continue to be a challenge.

Much of the power capacity built over the last few years received limited thought as to location or where a plant was in the transmission grid. As a result, many grassroots generating facilities were located close to a fuel source (e.g., gas pipeline) but far from demand in load pockets, where congestion can limit unit dispatchability. This, in turn, limits revenue streams and capital cost recovery for many who paid much too dearly for generation capacity during the industry boom.

Further aggravating the poor financial state of things is the fact that trading activities, which had apparently accounted for a large percentage of bogus power and natural gas marketing revenues, have been scaled back dramatically, as has the level or even existence of speculative trading conducted by many market players.

Gas demand

According to the US Energy Information Administration (EIA), natural gas demand from the power generation sector accounted for 32% of US gas demand in 2001. During the combined-cycle gas turbine construction boom of the late 1990s and early 2000s, projections for natural gas demand grew increasingly more bullish for the long term, as thousands of additional gas-fired megawatts nationwide were translated into incremental increases in daily gas consumption.

Since November 2001, however, many companies have shelved or canceled projects. The result of this belt-tightening has been that thousands of megawatts of previously anticipated capacity is not likely to come to fruition. In the Northeast, for example, Energy Security Analysis Inc., Boston, estimates that out of the 66,285 Mw currently in the New England Power Pool, (New York Power Pool, and independent system operator (ISO) PJM Interconnection LLC (covering the Pennsylvania-New Jersey-Maryland region) generator development queues, only 23,070 Mw of capacity is likely to get built.

In addition, cost-cutting measures may force plant owners to mothball older, more expensive units. For example, American Electric Power Co. Inc. (AEP), Columbus, Ohio, recently announced it would shut some of its Electric Reliability Council of Texas generating assets in Texas. Overall, this decrease in existing and projected capacity has taken some of the steam out of the previous long-term gas demand outlook.

Capacity crunch

Perhaps most urgent is the effect on capacity adequacy in some regional power markets. One visible example is California, where poor market design, combined with scarce resources, high gas prices, and booming demand, helped to create the state's energy crisis of 2000-01.

While the past 1 1/2 years have seen decreased demand as a result of economic slowdown, lower gas prices, improved hydroelectric resources in the Pacific Northwest (which California relies on for the bulk of its power imports into the northern half of the state), and regulatory controls, the overall reserve capacity margin remains suboptimal. According to California Energy Commission data, 4,750 Mw of planned capacity (much of it peaking) has been canceled since 2000, and more than 6,100 Mw of capacity projects has been put on hold.

Therefore, there is every reason to believe that a rebound in demand, another bad hydro year in the North, increasing Northwest aluminum smelter activity (boosting industrial demand), or gas import constraints into southern California could bring the state face-to-face with another tumultuous energy crisis.

Aside from the generating capacity crunch, credit issues also could affect anticipated expansion of natural gas pipeline capacity. In areas such as California and New York, expansions that had been driven by forecasts for increased gas demand from grassroots power generation look less attractive as electricity projects are gradually withdrawn. This is an important issue, as basis (the difference between the cash price and futures price of the commodity) in premium regional hubs can already be volatile during peak periods, and investment in pipeline transport capacity out of cheaper areas such as the Rocky Mountains could help rein in an exploding basis over time.

One area that may benefit from this adversity is merchant transmission of electricity. Merchant projects can help alleviate congestion in load pockets while allowing locked-in resources to deliver their cheaper megawatts to demand areas. Direct current (DC) projects have the advantage of electrically transferring energy and capacity from rich to poor areas. With backing from the load-serving entities (LSEs) or other energy companies through firm capacity purchases or development capital, project financing is more attainable from the investment community. DC projects such as the Atlantic Energy Partners LLC consortium's Neptune Project that will connect sources in the PJM power pool to the congested New York City load pocket, or French firm TransEnergie's Cross Sound Cable that will connect Connecticut to Long Island, are two prime examples.

It is more difficult to evaluate the economics of less-controllable alternating current (AC) transmission projects. System operators and transmission operators have to upgrade and expand their existing AC connections. Obtaining financing from the private sector will prove challenging but not impossible.

Regulatory risk

The challenge to FERC is to create the right balance of regulation that can satisfy social objectives without killing profit incentives that drive market participants to invest. Deregulated natural gas and certain US West and Northeast power markets have successfully moved from the regulated world of guaranteed rates of return and fixed costs to market-based rates and wholesale trading.

While the natural gas world has had a few more years of deregulation under its belt than the more-fledgling power markets, the recent ricochet back to strong government visibility in market operations is an overcorrection that has increased the sense of regulatory risk in the marketplace, while impeding market forces.

One early example of this was FERC's intervention in the California ISO market in June 2001 and issuance of an electricity price cap set at $91.87/Mw-hr. In addition, rules that forced out-of-state sellers and marketers to be price takers have damaged regional generation capacity investment. FERC's recently created OMOI and its dragnet of investigations have exacerbated market uncertainty and the sense of regulatory risk inherent in electricity and natural gas market investment.

While it may be safe to say that the market has developed enough to prevent comprehensive reregulation, the pace of deregulation in states that are still rate-based power markets will undoubtedly slow down. And FERC's SMD rules would put utilities and LSEs back in the driver's seat by requiring them to be responsible for contracting specified resources to secure supply for their end users. In markets with no retail competition, generators will be at the mercy of these LSEs. And retail competition appears distant indeed.

Liquidity

Amid the maelstrom of increased regulation, market oversight, tight credit, and massive stock devaluations, investment in the industry has clearly suffered over the last year or so.

Tight credit and corporate introspection have put the kibosh on projects and trading activities. As trading operations have been scaled back or disappeared altogether over the last 12 months, the critical mass that once made up the vibrant wholesale natural gas and electricity community has turned off the lights and gone home. Larger companies such as AEP, El Paso Corp., Kansas City, Mo.-based Aquila Inc., Tulsa-based Williams Cos. Inc., and Houston-based Dynegy Inc. had—in conjunction with Enron—provided liquidity and market-maker services that allowed a semblance of "forward curves" to develop in electricity and liquid locational gas trading to take place at regional pooling points such as SoCal Border or PGE CityGate.

With major players either limiting trading activities to revolve around their asset base, or exiting the trading function altogether, a void has been created that remaining market players—who may face similar credit issues and have far less trading savvy—are not ready or willing to fill.

With less liquidity, longer-term structured deals and calendar-strip trading have suffered alongside capacity development, as quotes in the market have become sporadic at best, and longer-term regulatory uncertainty has left many reluctant to value contracts beyond prompt month. One result is that market players and LSEs that continue to trade have had a harder time hedging beyond prompt months. There also is an unwillingness to enter into a long-term supply contract if there is no forward price available to use as a benchmark.

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Regional gas markets have also suffered from a drop in liquidity, starting in late 2001 when Enron exited the market and the Enron Online trading platform disappeared. Fig. 1 shows SoCal basis to Henry Hub in the fall of 2001. Note the October 2001 natural gas price suppression despite strong regional power prices, but bullish prices and a basis blowout in November despite relatively similar power prices. While the extreme volatility pictured in Fig. 1 has been dampened somewhat since late 2001, there remains a lack of robust trading levels previously seen in the region.

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The market liquidity issue continues to be one of the most visible in the industry, and the situation looks as if it could get worse before it gets better. Entry into the trading area by certain financial players such as SA Louis Dreyfus & Cie., Bank of America Corp., and Deutsche Bank Group will help ameliorate some of the market vacuum. However, their relative lack of ties to the energy industry raises the question that their injection of liquidity may not be a long-term panacea for an endemic problem.

Volatility

Liquidity (or lack thereof) generally goes hand in hand with volatility. The downfall of Enron was a result of poor fiscal management—not necessarily a weak fundamental business model.

Enron's demise acted as the catalyst within the industry, bringing to light poor accounting practices coupled with questionable fiscal management. In return, other significant fundamental market players have responded to public pressure by performing a "quick fix"—reducing exposure by exiting the trading business altogether—instead of continuing to participate in trading operations while restructuring corporate governance. However, market leaders may have prematurely thrown the baby out with the bathwater. As fundamental players exit the business, financial markets have moved away from equilibrium, allowing banks and noncommercials to wield greater price power.

As liquidity continues to dry up in the natural gas and power markets, volatility will continue to increase and bid-ask spreads will continue to widen in forward markets. Lack of liquidity in natural gas trading will increase basis volatility at less-liquid points. Enron's exit from futures trading on NYMEX took a significant toll on the exchange in late 2001, when Henry Hub spiked roughly 30¢/MMbtu at the end of October. Fig. 3 shows the percentage of open interest held by the eight largest traders on NYMEX from 2001 to the present. The dramatic 10% drop in November 2001 can be seen as quantification of the significance of Enron's overall market position.

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Enron's trading presence on NYMEX proved to be a formidable trading force that may have acted as a counterweight to noncommercial hedge fund trading. Following Enron's exit, Henry Hub prompt prices reached lows near $1.90/MMbtu in January as the funds went on a selling spree and reached historic net-short positions. In the spring of this year, despite extremely bearish fundamentals, the funds went long, triggered somewhat by sympathetic strength in the crude oil market, and prices pushed toward $4/MMbtu.

In the electricity markets, power price volatility has also increased, partly due to the wider bid-ask spreads and lack of liquidity, but also due to gas market volatility that impacts power prices in gas-fired-generation-dependent regions such as the Western Electricity Coordinating Council and the Northeast. This volatility and uncertainty act to undermine investment and can be a deterrent to increased market participation by the remaining load servers and hedgers left in the market following the virtual disappearance of trader-speculators.

Transparency

While the natural gas market does have a liquid futures exchange that provides price transparency at the hub, cash and basis trading, as well as all power market trading, is conducted solely in the OTC markets. In the absence of an exchange mechanism, the industry has relied upon brokers, trading platforms such as Bloomberg, Enron Online, and Dynegy Direct, as well as publications such as Platts's. The process of price discovery is critical for market development and liquidity.

The Enron Online trading platform quickly became a main source for price discovery in the natural gas market in 2001. However, this platform (unlike Bloomberg, which is purely an electronic medium that matches buyers and sellers) allowed Enron to be the counterparty on every transaction and have the advantage of complete price discovery on the bid and ask side of the market. Through subsequent investigations conducted by FERC, this "subjectivity" is thought to have produced invalid prices—prices that were used in OTC trading publications such as Platts's.

This sudden scrutiny of price reporting and quest for "objective prices" has led to an investigation into the price-gathering methodologies of companies such as Platts's and into the validity of the power and gas pricing information given to reporters by market players. The result has been that some companies have come forward and admitted to having quoted directly from Enron Online (a now tainted source) or to having "talked their book" to reporters. In this current "witch hunt" investigative environment, fear of repercussions has led some entities to stop reporting prices altogether to the trade press, placing a gag order on employees.

Without a wide and deep pool of market participants for OTC market reporters to work with, the industry will be shooting itself in the foot. Prices become more opaque and inaccurate, begetting less liquidity and increased volatility—a vicious downward spiral. Less transparency will increase the difficulty in valuing the forward market and obtaining project financing from Wall Street. Instead, it is in the best interests of power companies to continue to work with price reporting agencies and to promote open markets and information flow—especially since it is likely to be a long time before the power industry can develop a successful and liquid futures exchange to rival Henry Hub. And while regulatory agencies should be interested in understanding how price reporting works, they should leave these entities to their work and deal with suspect wholesale market players.

Competition from LNG

As mentioned earlier in this article, one side effect of increased natural gas price volatility and the absence of an Enron-type entity in the market is a stronger futures price curve for Henry Hub NYMEX.

If this trend continues and equilibrium prices remain above $3.00/MMbtu, US dry gas producers should be prepared to face increased competition from imports of LNG.

The road ahead

The road ahead remains bumpy for the natural gas and electricity markets. It is definitely a period of catharsis for both.

This is not dissimilar to the growing pains suffered by the crude oil market in the 1980s—a market that has no FERC equivalent, in which players police themselves and where prices are relatively transparent to all.

The kinks will be worked out eventually, and players will become leaner and more focused on core competencies that will maximize revenue flows of their existing assets. For the natural gas market, the key moving forward will be to recognize the inextricable link that has been forged with the power industry and how liquidity, volatility, credit, and transparency ills inflicting regional electricity markets will continue to have a direct impact on demand outlooks and price levels in local and national gas markets.

An alternative approach to completely discarding what is now perceived as a corporate rating "liability," the trading model can be fixed if the private and public sectors agree to cooperate in amending corporate governance issues. One method would be to encourage a well-constructed derivatives accounting business that establishes investor communications, proper pricing, and transparency of trading assets, resulting in a reduction of overall risk. This equates to lower cost of equity capital, greatly increasing a firm's value and stock price. The process would alleviate not only corporate risk exposure but would maintain the necessary fundamental presence of energy companies in the financial markets.

The author

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Kristin Domanski is manager, power and natural gas services, for Boston-based Energy Security Analysis Inc. (ESAI). She manages ESAI's Power & Natural Gas Services group, where she conducts and oversees primary research and written analysis of energy market dynamics that combines fundamentals and emerging trends with economics, flow models, bidding behavior, capacity additions, and proprietary input-fuel forecasts. She has several years experience as a market analyst in the energy and utilities industry, including work in journalism, wholesale market dynamics, and industry marketing. Prior to joining ESAI, Domanski was employed by Lucent Technologies, Murray Hill, NJ, and by Energy Argus Inc., Hoboken, NJ. She received an MA in transitional economic studies from the University of London and a BA in economics from Wellesley College.