It seemed like a good idea at the time. In 2000, eager to capitalize on Enron’s recent success in electric-power trading, executives at Allegheny Energy Inc. launched their own trading business.
Before that, the Greenburg, Pennsylvania-based company operated in a regulated market; it sold its electricity only to clients in a territory granted by the Federal Power Act of 1935. By taking up power trading, it planned to move a hefty part of its business beyond the customers in its territory and into the open, competitive market.
In doing so, Allegheny put traditional industry economics on hold. Rather than emphasizing the long-term reliability of its plants, Allegheny began to focus on the “spark spread,” a relatively new measure that power traders use to price their transactions. The spark spread is the difference between the price of electricity and the price of the fuel (usually natural gas) used to produce it. The wider the spread, the greater the profit; indeed, fuel costs account for 60 percent to 80 percent of the cost of generating electricity.
But the heavy stress that Allegheny placed on building a successful trading operation didn’t serve it well. By 2001, news of trading scandals filled industry publications, and deregulation — the prime mover of the newly competitive market — stalled. Then Enron collapsed, as did investor confidence in energy-trading companies.
By the end of 2002, Allegheny Energy had already begun to dismantle its trading business, but too late. The company’s trading portfolio lost $218 million of its after-tax value, spawning large layoffs and related expenses. Investors, inevitably, balked. Allegheny’s stock plummeted by nearly 80 percent in one year, dropping from $35 in January 2002 to a lowly $7.56 on December 31. Net losses for the year totaled $633 million, and the fact that the company could not cover its debt service had lenders buzzing about bankruptcy.
By the summer of 2003, a new CEO and CFO were hired to pull the company out of its tailspin. After making sure bankruptcy was no longer a concern, chief executive officer Paul Evanson and finance chief Jeffrey Serkes refocused management’s attention away from spark spread and toward “plant availability,” a more traditional industry metric.
Plant availability is a ratio of reliability, measured year by year, of the hours a plant is in service divided by the total number of hours. The more often a plant is online, the more megawatts (and the more revenue) it can generate.
Plants are taken out of service for one of two reasons. A planned maintenance outage — the darling of plant-equipment manufacturers, lenders, and credit-rating agencies — is equivalent to putting a car into the shop for an oil change. A forced outage, on the other hand, results from an unexpected event and more resembles towing the car to the service station after an accident.
Historically, Allegheny Energy plants run at 81 percent availability, while the top quartile of plants in the United States run at a 91 percent. Boosting availability is important for Allegheny, says Serkes, the CFO: at current prices for electricity, every percentage point of improved availability means $10 million more in pre-tax income for the company.
To keep management focused on the goal, Allegheny, which took in $2.8 billion in sales in 2004, ties bonus pay to availability improvement. Every employee who receives incentive pay, whether they work for the power-generation business or not, receives bonuses based on plant availability. Other performance-based compensation metrics are net income and the company’s safety record.
The change in focus seems to have worked. On January 17, 2006, Allegheny Energy’s share price closed at $34.60. Further, the company posted $36 million in net income for the third quarter of 2005; during the same period in 2004, it revealed a $377 million third-quarter loss. Allegheny Energy cut its debt by $1.9 billion as of October 15, 2005, paying down borrowing three months earlier than expected.
Those positive results don’t necessarily mean that all power companies should start linking pay to availability rates. The effectiveness of metrics in the industry differs according to the type of plant and the business model, contends Larry Straight, president of Sterling Energy International, a Capistrano Beach, California-based contract plant operator.
For coal-fired plant operators like Allegheny Energy, availability is essential. Plants that run on coal commonly top five stories in height and often take more than three hours to reach full generating capacity; they’re less expensive to operate when the plants run constantly.
Smaller, natural-gas-fired facilities, however, are built to be shut down or restarted in a relative hurry — less than an hour, in most cases. That enables them to respond more quickly to pricing signals and take advantage of peak demand opportunities and favorable market prices. It follows that the owners of natural-gas facilities are likely to be more interested in selling into competitive, spot markets.
For those plants, constant availability isn’t the selling point. The owners of gas-fired facilities tend to be more concerned with per-unit productivity, as measured by the “capacity factor.” Measured over the course of a year, a plant’s capacity factor is the ratio of the amount of electricity it produced to the amount of electricity it could produce if it operated at maximum output. (Gas-fired plants rarely run at maximum output since owners don’t always sell all of the plant’s potential power.) Think of the capacity factor as a measure of inventory: A high factor means that inventory is selling out, while a low one means that you’re stuck with goods on the shelf.
Jerry Crouse, CFO of privately held Tenaska Energy Inc, a power producer based in Omaha, Nebraska, says that the capacity factor is a “more interesting” metric than availability. Tenaska, which runs gas-fired plants, sells all of its 7,600 megawatts of electricity under long-term (15 years to 20 years) contracts in the wholesale market.
Thus, unlike gas-fired facilities that peddle their inventory to the spot market, Tenaska’s business doesn’t turn on its plants’ capacity factors. Even so, says Crouse, “the metric helps tell me if our customers are doing well.” When capacity factors are high, he explains, Tenaska clients are using most of the power they bought.
Further, a high capacity factor helps the company raise capital through issuing public bonds, adds Crouse. Bond-rating agencies often run availability-rate and capacity-factor sensitivity models on plants to determine how the company financials will hold up under different scenarios.
Lately, Wall Street has shown an interest in availability, capacity factors, and other engineering-related measurements, according to Jason Makansi, head of research for Pearl Street Capital, a hedge fund that invests in power companies. Over the last two years, he’s noticed an increase in the use of such metrics in analysts’ presentations.
Hot, Hot, Hot
Another calculation that’s finding its way to Wall Street to help explain power-generation business fundamentals, says Makanski, is the “heat rate.” A plant’s heat rate, the ratio of fuel input to electricity output, is a measure of its efficiency.
Of course, standard financial metrics — like assets, liabilities, and shareholder’s equity — are still part of every power-company CFO’s tool kit. However, the industry’s own measurements lend them a unique twist.
In that light, Robert Flexon, chief financial officer of NRG Energy Inc., a power producer based in Princeton, New Jersey, is a fan of capacity factors and forced-outage rates because they tell him how the underlying business is doing. “If the plants are not running because of a high outage rate or poor capacity factors, that affects the balance sheet,” remarks Flexon.” That means that investments in capital assets wouldn’t be paying off.
Power generators are also likely to keep a close watch on free cash flow this year, says Mark Agnew, a financial analyst with Washington, D.C.-based trade group the Edison Electric Institute. After four straight years of free-cash-flow improvement, Agnew notes that 2005 will likely end the streak.
To be sure, an EEI report analyzing the third-quarter cash-flow statements of U.S. investor-owned electric-power companies notes that free cash flow was a positive $552 million through Q3. But a 16 percent rise in capital expenditures (spurred mainly by the addition of pollution-abatement equipment like sulfur-dioxide scrubbers and upgrades to transmission systems) plus higher dividend payouts will curb full-year free-cash flow totals. As a result, Agnew doesn’t expect the cumulative total to match 2004′s free-cash-flow tally of $4 billion.
Many companies will also be coming off rate freezes and will have to renegotiate regulated rates with state commissions. If they lose the right to recover new expenses from customers, that could put a drain on cash flow.
But unless cash flow isn’t reduced by accrued maintenance costs, it’s not the best measure of a power-generation company’s financial health, contends Sterling Energy’s Straight. Indeed, power plants require regular maintenance outages that can cost anywhere from $10 million to $25 million for each plant in a company’s portfolio. Expenses must be accrued each year for the outages, which usually occur in three-year cycles, he says.
That effectively puts a lien on short-term cash flow until the maintenance expense is booked. While power-industry CFOs and lenders are well aware of the reoccurring future charge against cash flow, it’s something that an outsider might not catch, adds Straight.
Long-term cash flow, however, “is still king” because large amounts lure commercial lenders, says Paul Harmon, vice president of energy assets at consulting firm R.W. Beck. Borrowing is especially important to power-generation companies because the capital-intensive nature of the business means “the industry needs outside equity to make it work,” stresses Harmon.