Academic journal article The McKinsey Quarterly

Finding the Balance of Power

Academic journal article The McKinsey Quarterly

Finding the Balance of Power

Article excerpt

Deregulation has given rise to a new breed of highly profitable US power generators and electricity traders, but the industry faces a shakeout as supply catches up with demand.

Recent US power shortages have left the Bush administration scrambling to develop a national energy policy and Californians sitting through brownouts. Yet for a power industry emerging from deregulation, the fundamental shortage of electricity has contributed to an unexpected success story: a new breed of power generation and electricity wholesale-trading companies. Many of these "upstream" companies, often created when utilities floated their deregulated generation businesses, have become stock market favorites. They are riding high on soaring prices coupled with the appetite of the capital markets for high-growth companies in the old economy.

Even as NASDAQ fell by 45 percent in the 12 months leading up to May 2001, the S&P 500 electric utility index rose by 37 percent. Traditional integrated utilities--especially those with strong upstream businesses--made substantial gains, but pure-play companies that focused on the upstream business performed better still: the stock price of power generators such as NRG Energy and Calpine and of wholesale traders such as Dynegy rose by anything from 80 percent to more than 130 percent (Exhibit 1). With annual earnings projected to grow by 20 to 35 percent, the leading companies in this emerging upstream power industry enjoy price-to-earnings multiples in the 20 to 30 range.

Power companies now face the challenge of meeting the growth expectations of the capital markets, even as supply catches up with demand. For while the timing will vary from region to region, supply will indeed catch up. In fact, we believe that many regions could have excess capacity within four years.

Savoring the sweet spot

During the 1990s, new generating capacity failed to keep up with steady-to-brisk growth in demand. Traditional utilities became reluctant to build new power plants as that era of regulation, when utilities were assured of recovering their costs, drew to an end amid uncertainty about what deregulation would entail (see sidebar, "A market in transition," on the next spread).

The result, in many parts of the United States, has been a fundamental shortage of electricity, followed in turn by rising prices: summer peak consumption increased by 96 gigawatts from 1994 to 1999, while new generating capacity increased by only 15 gigawatts (Exhibit 2). Strong demand and high prices for the natural gas that fuels many power plants have contributed to extreme volatility in several markets. California is the most extreme example. From about $33 per megawatt-hour in the summer of 1999, wholesale summer prices in that state rose on average to more than $140 per megawatt-hour in the summer of 2000. In December 2000, prices, at a little over $300 per megawatt-hour, were more than nine times the 1999 level. [1]

Leading power generators and electricity traders have been quick to exploit the sweet spot. Five companies--Aquila, Mirant, NRG, Orion Power, and Reliant--successfully spun off generation and wholesale-trading businesses in late 2000 and early 2001. Several others intend to follow suit, and many more have ambitious growth plans: Mirant, NRG, and Orion, for example, have moved quickly to buy assets and to add capacity Calpine, a company focused on building new, efficient power plants, has announced a target capacity of 70 gigawatts by 2005--which would entail a compound annual growth rate of more than 60 percent over five years. Dynegy, which entered the electricity business only in the mid-1990s, envisions owning or controlling 75 gigawatts of capacity within three or four years.

If the announced projects are completed as planned and electricity demand follows recent trends, by 2005 reserve margins will reach or exceed the 15 percent needed to ensure reliable supply when demand is at its peak in 10 out of 12 regional US markets (Exhibit 3, on the next page). In other words, several markets could have excess capacity within four years. In New England and Texas, excess capacity might develop over the next two years; the Southeast and Florida could remain tight through 2005. As regional markets develop excess capacity, prices could be driven to levels that might make gas-fired combined-cycle plants unprofitable.

Of course, if companies add capacity more aggressively in the near term to pursue growth, that point could be reached earlier still. In the meantime, the Bush administration's proposals aimed at removing barriers on the supply Side--by, for example, streamlining the relicensing of hydropower projects and by working closely with the Canadian gas industry to build new gas pipelines to deliver its products--can only hasten the day when the sweet spot turns sour.


What about the view that there is no danger yet of supply catching up with demand?

Some in the industry believe, for instance, that the intensive use of computers and other kinds of electronic equipment in the new economy means that demand for electricity will rise. But this factor is countered by others, such as the introduction of more efficient air conditioners and refrigerators and the shift away from certain types of manufacturing. The evidence suggests that the electric intensity of the economy as a whole (measured by electricity consumption per unit of gross domestic product) has fallen over the past decade--even in regions, such as California, where the new economy is growing rapidly.

Others question whether the planned new generating capacity will actually be built, in view of constraints such as the physical limits on the delivery of new turbines and the high price of gas, as well as the difficulty of finding suitable sites and gaining permission from local politicians. We, however, do not believe that any of these factors will much prolong the sweet spot's duration. Turbine manufacturers will, it is true, have difficulty delivering enough turbines to meet the demand from all announced projects over the next two or three years, and the growth plans of some generators will be frustrated as a result. But as the pent-up demand from years of inadequate building is worked off, the "shortage" will end.

Moreover, site constraints must be a regional rather than national problem, since in 2001 in excess of 40 gigawatts of capacity is projected to come on line. In California, arguments rage over where generators should be allowed to build plants, even as the state's electricity shortages become increasingly uncomfortable. In Texas, by contrast, several projects are moving through the regulatory process relatively smoothly. Ultimately, such varying regional policies will create important regional differences in the price outlook of electricity.

As for the long-term supply of gas and its cost, the basic question is whether the high price of the fuel needed to run gas-fired combined-cycle plants will make power developers pull back from current plans to build new ones and instead build coal plants that take longer to get on line, thus prolonging the tightness in electricity markets. It is currently expected that gas prices will remain relatively high until the spring of 2004, but so far there is no sign that the long-term outlook has resulted in a serious retreat from the construction of new gas-fired plants. The reason is that high gas prices will probably push up electricity prices over the next three years--compensating generators for the higher price of fuel--and that long-term gas prices are expected to fall.

The road ahead

How will the business models of today's power generators fare when the supply shortage ends? In varying degrees, each of the three existing models will be vulnerable to lower electricity prices and to lower volatility in regional markets.

Regional generators

Many traditional integrated utilities, such as Public Service Electric & Gas (PSE&G), in New Jersey, and Cinergy, in Ohio, have built strong regional positions in generation by building new generation plants and combining these with their recently deregulated generation assets. But regional generators are particularly vulnerable in the changing upstream industry: they may be profitable in their own regions but--especially when market prices eventually fall and the industry's more normal cyclical pattern returns--unable to deliver the type of growth that competitors with national or global scale can achieve. What is more, the lack of regional diversification makes the profitability of regional generators highly vulnerable to price movements in one area. Some, such as PSE&G, recognizing their vulnerability, have embarked on selected international investments. It remains to be seen whether these moves will be substantial enough to provide a meaningful hedge. Regional generators are also susceptible to takeover b y national and global players that enjoy higher valuations and have big appetites for growth. And they will struggle to find top-notch managers when bigger competitors with grander aspirations and higher stock market valuations offer richer opportunities.

To put it bluntly, regional generators will not survive in their current form. They have two choices. The first is to sell their generation assets on attractive terms, but they must act quickly because the value of such assets is likely to fall as electricity supply catches up with demand. The second is to build scale and move into the national league. For many a regional generator, such an initiative would in practice mean embarking rapidly on a power generation merger or forming a joint venture with a view to floating it in the next 18 months and using the proceeds to go on building national scale. Many integrated utilities are considering this second course.

National or global powerhouses

Some companies are building, buying, and operating power plants on a national or global scale. They include spin-offs of regional utilities, such as NRG, that have gone national through expansion, as well as companies from outside the traditional utility industry, including Calpine, which specializes in building power plants using gas-fired turbine technology, and AES, which has built a global portfolio of coal- and gas-fired power plants through greenfield development and acquisitions. The national and global powerhouses operate plants efficiently, know how to enter regions when market conditions are optimal, and are skilled at financing their plants attractively. They will remain in an attractive position during the next two or three years, but their business model too will eventually come under pressure.

One reason for the pressure is the fact that as electricity supply catches up with demand, there will be a risk of excess capacity in many markets. Thereafter, the need for new electricity generation capacity will return to modest levels (about 20 gigawatts a year nationally). Under such conditions, builders of new power plants will find it particularly difficult to sustain high growth. Expansion through the acquisition of regional generation companies may be an alternative, but purchasers run the risk of overpaying in an overheated acquisition market.

Part of the success of the national and global powerhouses lies in their ability to find municipal distributors prepared to sign three- to five-year fixed-price contracts for electricity. They have also found some counterparties (notably wholesale-trading companies such as Aquila and Williams) willing to sign long-term "tolling deals," in which they free themselves from commodity market risk (as well as upside) by charging the counterparty a rentlike payment to provide the fuel and take the output. In this way, such companies have been able to secure stable future revenue and so keep their total cost of capital down by using large amounts of debt. But this model may be strained once supply goes up and electricity buyers start shopping around for more attractive, shorter-term contracts.

In this new, increasingly competitive environment, national and global powerhouses will also be punished for their limited trading skills. They can clearly build, buy, and operate power plants and negotiate profitable long-term contracts for their output. But their ability to make money by trading their output on a day-to-day basis is less clear. Furthermore, the jury is still out on whether these leaders, focused on asset ownership and operations as they are, have the flexibility and discipline to sell assets at the right time and to shift the capital to projects with better prospects.

These companies have two options. First, they can persist in their current form but with scaled-back growth aspirations. They will not be able to maintain their current growth and profits, though opportunities for acquisitions will periodically arise in their home markets, and international growth can partly compensate for slower growth at home. Their second choice involves transforming their business model into something like that of the third group of companies: the energy merchants. This approach would mean venturing into areas such as day-to-day trading and marketing, as well as optimizing growth by moving in and out of medium-term asset positions. These changes will force companies to change their organization and culture from one rooted in project development to one characterized by a broader commercial mind-set.

Global energy merchants

The third model--that of the energy merchants--has been adopted by companies that negotiate short- and long-term deals to buy and supply electricity and then use trading skills to maximize the value of those deals. The ability to originate agreements to buy and sell, to price risks appropriately, and to decide whether to keep or shed specific risks is critical for these companies.

Energy merchants, such as Dynegy and Enron, pursue national and even global opportunities. They are open to owning power plants but equally open to controlling generation output through properly structured contracts. Many national or global merchants trade not only electricity but also gas and other related commodities. Indeed, the recent volatility of US gas prices has highlighted the need for upstream players to be skilled in multicommodity risk management.

Energy merchants have the ability to enter and exit markets at the right time and concentrate on creating value through trading rather than the ownership of assets. We therefore believe that this flexible (and frequently capital-light) business model depends on high electricity prices less than do the other two models and has a better chance of maintaining growth rates and high valuations. But challenges remain.

First and foremost is the fact that electricity markets will move toward greater efficiency and liquidity, a development that will in turn place downward pressure on margins for even the most skilled competitors. In response, energy merchants will have to discover new opportunities in which their skills can create considerable value--for instance, making markets in new geographies and in other commodities, such as liquefied natural gas or even bandwidth. As energy merchants try to expand into unfamiliar regions and markets, there will be a risk that catastrophic risk-management failures may destroy large amounts of value. Hiring the right talent and perfecting risk-management processes will be central to avoiding such failures.

To sustain innovation over the longer term, energy merchants will have to take on the difficult task of building a value proposition for people--one that consistently attracts a disproportionate share of the top performers. As the experience of other industries has shown, it is difficult for any company to be ahead of the pack repeatedly in the ongoing race to spot untapped opportunities.

This article draws upon the findings of a research initiative conducted during the summer and autumn of the year 2000. Other contributors are Tim Bleakley, a principal in McKinsey's Houston office; Raul Espejel, a consultant in the New York office; and Marcelino Susas, a consultant in the Washington, DC, office.

Anjan Asthana is a principal in McKinsey's Pittsburgh office; Ken Ostrowski is a director in the Atlanta office; Venki Venkateshwara is a consultant in the Washington, DC, office.

(1.) The factors contributing to the crisis in California include lower than normal hydropower production; rising demand resulting from the growing economy; a long period of inadequate additions to capacity; particularly high prices for gas delivered to California, because of higher gas demand and pipeline constraints; a run-up in market prices for emission credits (needed to comply with environmental regulations); and regulatory flaws in the design of the wholesale market.

[Graph omitted]


The old economy strikes back

Change in stock price from May 1, 2000, to May 1, 2001, percent

Calpine                         138
NRG Energy                      136
Mirant [1]                       88
Dynegy                           80
S&B 500 electric utility index   37
NASDAQ composite                -45

(1)Mirant--formerly Southern Energy--is spin-off of Southern Company,
a large, integrated utility; change in stock price calculated from
Mirant's first day to trading, in September 2000.

Source: Bloomberg, McKinsey analysis

Note: Table made from bar graph
A sellers' market

Compound annual growth rate, percent

Capacity        4.6  1.4  0.5
Peak demand     3.6  2.5  2.8
Average demand  3.6  2.4  2.4

(1)Independent power Producers.

(2)Includes 15% reserve margin.

Source: Edison Electric Institute; Energy Information Administration (US
Department of Energy; McKinsey analysis

Note: Table made from bar graph
Forecast 2005 regional reserve margins (excluding Canada) based on
announced capacity additions [1]

Forecast compound annual growth rate of demand, 2000-05, percent

ERCOT               3.6
FRCC                3.4
SERC                2.9
MAIN                2.6
California ISO      2.5
ECAR                2.4
MAPP                2.2
SPP                 1.8
NEPOOL              1.7
WSCC (partial) [2]  1.6
MAAC                1.4
NYPP                1.1

(1)Regions shown above are California ISO (Independent System
Operator), ECAR (East Central Area Reliability Council), ERCOT
(Electric Reliability Council of Texas), FRCC (Florida Reliability
Coordinating Council), MAAC (Mid-Atlantic Area Council), MAIN (Mid-
America Interconnected Network), MAPP (Mid-Continent Area Power Pool),
NEPOOL (New England Power Pool), NYPP (New York Power Pool), SERC
(Southern Electric Reliability Council), SPP (Southern Power Pool),
and WSCC (Western Systems Coordinating Council).

(2)Excludes California.

Source: Resource Data International; North American Electric Reliability
Council (NERC); McKinsey analysis

Note: Table made from bar graph

A market in transition

The deregulated electricity generation and wholesale-trading (upstream) industry in the United States rose from the ashes of a system of cost-based regulation dating back several decades. In those days, an electric utility would be awarded a service territory, and customers in it had to buy their electricity from that source. These utilities were usually vertically integrated across generation, transmission, and distribution. They planned and built all the generation facilities as well as the high-voltage transmission lines that carry electricity in bulk and the distribution feeder lines into homes and businesses. The cost of serving customers could be fully recovered from the regulated rates (including a "just and reasonable" rate of return on the capital invested) that utilities charged.

Then came an end to regulation--a change brought about by three factors. First, utilities found that as they brought expensive plants on line in the 1980s, regulators frequently insisted that stockholders bear part of the cost. Second, as a result of a federal law enacted in 1978, entrepreneurial independent power producers emerged. They proved successful in offering industrial customers attractive prices, thus demonstrating the advantages of a market-oriented approach. Third, a growing political consensus held that generation could become a competitive industry, with no need for cost-based regulation, if free wholesale-market institutions were created to help buyers deal with sellers and to arrange delivery of the electricity. These buyers (typically wholesale traders and utilities buying on behalf of households and businesses) and sellers (generators and wholesale traders) were to carry out their transactions using regulated transmission and distribution systems.

Through the late 1980s and early 1990s, federal regulators increasingly adopted policies that freed generation from cost-based regulation. In 1992, federal legislation gave regulators new authority to order franchised utilities to give other suppliers access to their transmission lines. Participants in today's wholesale markets--companies that sell their output into spot markets or under contract, as well as companies that buy and sell electricity in the wholesale market and enter into pure financial transactions such as futures and options contracts--are free of cost-based regulation as long as the market is fully competitive.

Because franchised utility providers operate under state law, state-by-state action has been required to give all customers a choice of electricity providers. California and Massachusetts acted soon after federal legislation began opening up wholesale markets, in the early 1990s, and many other states followed. By 2005, 60 to 70 percent of US customers should be able to select their electricity "retailers."

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