|
|
ANALYSIS samples also include.... After PUCHA: Good California Vibes Merger Horizons & Utility Futures
California Energy Circuit, August 26, 2005
Calpine's Unwanted Attention
California Energy Circuit, November 11, 2005 There Is No Such Thing as a Free Lunch
California Energy Circuit, July 8, 2005
Friday, December 8, 1978 How new law will affect natural gas, if… By Jim Brumm
Special to The Christian Science Monitor WASHINGTON -- "If Wishes were horses. the beggars would ride," my grandmother used to say when I ran together a string of wishful thoughts headed by that little word that can have such a big meaning - if.
This week, the line could well read: If wishes were computers, the gas price would be right. For everyone has his own estimate of what the Natural Gas Policy Act of 1978 will cost consumers, and when the impact will be felt.
But few - if any - of those estimates are listing all the "ifs" (that is, assumptions) needed to reach the number they toss out to the waiting world. And most of these apply to someone the news services like to call “the average homeowner,” without pointing out that such a person does not exist.
As a rather simple example, one could say that a local distribution utility will have to raise the price it charges residential customers 4.3 percent as a result of the inflationary adjustment Congress included in the law that went into effect last Friday.
If all the gas the utility sells was under federal control before April 1977.
If equal amounts of each of the 15 categories of prices that now apply to this gas - on which Congress mandated a 12.6 percent inflationary price increase - are being delivered to the utility by its pipeline suppliers.
If the traditional ratio of transportation (two-thirds) and wellhead (one-third) costs apply to the gas this company is delivering.
Percentage can change
But the percentage quickly changes. . .
If the utility is buying part of its gas from sources not controlled by federal regulators such as producers in its own state or via what is called emergency procedures that let the utility or the pipeline serving it bargain directly with producers.
If the controlled gas it is buying started flowing from the well after April 1977.
If it is selling imported gas - which could be coming into the United States by pipeline from Canada or as shiploads of LNG (liquefied natural gas) from Algeria.
If the utility is one of the few that produce SNG (synthetic natural gas).
And none of those assumptions tells the customers of this nonexistent utility when the price bubble will show up in the bills it mails out. The bubble was created when Congress said producers could raise prices Dec. 1 to reflect the full impact of inflation since April 1977.
Adjustments limited
But the Federal Energy Regulatory Commission told interstate pipelines that they could reflect changes in the cost of purchased gas only twice a year. And the local utility does not pass the cost on until the pipeline serving it gets the needed regulatory permission.
The biggest number of these adjustments for changes in purchased gas costs will come in January, when 14 of the 32 pipelines involved are scheduled to seek approval of price changes. Other applications will come as late as June. .
Most estimators have not tried to predict the size of that initial price bubble. Rather, they have tried to look at the price impact for all of 1979. By the end of next year, there will have been 12 more monthly price adjustments to reflect inflation, and gas will have started flowing under another set of "ifs" - the recently established prices for various forms of newly found gas.
These annual impact projections cover a wide range -- 4 percent to 50 percent.
On the high end, with projections of a 30 to 50 percent gain in the price residential consumers will have to pay, is Energy Action. This self-labeled consumer group puts no dollar figure on its estimate.
In the middle is the American Gas Association, a trade group representing local gas utilities. It expects the average homeowner's gas bill to increase about $25 next year. That represents an increase of 9.6 percent from the $260 that it expects the average bill to total in 1978.
The low end comes from the application of an estimate developed by the Federal Energy Regulatory Commission staff to a very limited, though possible, circumstance - a utility served completely by interstate pipelines. What the commission's staff did was project that domestic gas producers will get an additional $1.7 billion from interstate pipelines in 1979 because of the new law. That represents an 11 percent increase in the pipelines' purchased gas costs.
JUICE: Merger Horizons & Utility Futures
California Energy Circuit, August 26, 2005
Some good vibes are being generated by Southern California's troubled power market, and they are resonating with investors across the nation. They have been pushing the price of Sempra Energy and Edison International shares higher while other utility stocks receded from early-August highs.
Most utility stock measurements reached their best levels in five years during the first week of the month as investors sniffed the smorgasbord of tax breaks, subsidies, and regulatory changes Congress assembled into an energy bill before its summer break.
A featured entrée was repeal of PUHCA—the Public Utility Holding Company Act of 1935—which some expect to be the centerpiece of a merger feast.
Exelon chief executive officer John Rowe told Circuit that he expects "four or five other large [utility mergers] fairly quickly." Discussing the post-PUHCA possibilities after Public Service Enterprise Group shareholders approved Exelon's merger offer, he said there'll be "more and more" of the transactions in the future.
He didn't discuss how quick "quickly" was, but the new energy law says it is at least six months away. That's when PUHCA actually expires under the new law. Congress gave FERC four months to come up with regulations to implement the new law, which gives the commission enhanced merger oversight.
"This is not exactly repeal of Glass-Steagall," said Merrill Lynch utility analyst Steve Fleishman. He was referring to the change in Depression-era banking laws that spurred consolidation in the financial industry a few years ago. "Remaining FERC and state regulatory obstacles still make utility M&A a difficult process," the analyst explained. For those wondering how difficult mergers and acquisitions will be in California, state regulators aren't ready to say. As California Public Utilities Commission counsel Harvey Morris put it, "we aren't able to share our views yet," as the 1,700-page energy law is still being studied.
As the potential delays offset the initial euphoria, there was a pause in the biggest utility stock price rally since World War II. During the resulting August lull, the S&P Utilities Index slipped 3.5 percent after doubling its October 2002 low.
One of the bigger August losers was California's third publicly traded utility-Pacific Gas & Electric, which has seen its stock price slip 5 percent. Ironically, it is also the California utility that has had the most to say about PUHCA's repeal.
Asked during the second-quarter earnings conference call whether this would result in a change in strategy, PG&E Corp. chief executive officer Peter Darbee responded, "I don?t think so." Citing the company's "first and foremost" focus on "delivering better, faster, and more cost-effective service," he said, "Longer term, we want to be a leader in the industry, and that would suggest we would be a consolidator rather than somebody that's acquired."
Meanwhile, Sempra and Edison shares traded at 52-week highs this week. One of the better explanations for this came from Barry James at James Equity, who said that despite their gains, the stocks still look cheap compared to the market. He cited "healthy earnings growth" and big dividends, which mean the stocks "should hold up relatively well even if . . . the overall market sells off."
During Edison's second-quarter conference call, there was one question about the implications of a post-PUHCA industry for the company. Chief executive officer John Bryson responded that there are "none that we see at this time."
It was mid-month before Sempra chief executive officer Stephen Baum spoke up, expressing the belief that utilities "will consolidate at a more rapid rate as a result of the repeal of PUHCA."
"That's a needed thing," he continued. "There are so very many utilities that have grown up in a kind of Balkanized landscape in the United States, some of which are really too small to be efficient." Baum said the consolidation "will help greater efficiency in the lowering of prices."
Beyond utilities acquiring utilities, American Electric Power chief executive officer Mike Morris believes PUHCA's repeal "will add to the asset acquisition game" by lowering "the barriers to nonutilities or international companies." In addition to the widely discussed regulatory changes, Merrill Lynch's Fleishman noted in written comments, the new law "is chock-filled with tax incentives to support new utility infrastructure investment."
Some estimate such needs at $12.7 billion over the next quarter-century.
FERC chair Joseph Kelliher agreed that "the electricity business needs a tremendous amount of cash and investment." He added that he expects to see more coming from the financial industry because PUHCA "was a barrier" to the financial sector. He also sees entry into the power business "by companies that are in the energy business but not the electricity business."
AEP's Morris believes the tax changes enhance the "dramatic opportunities" for investment being created "as the U.S. economy becomes more and more dependent on more and more reliable electric energy."
He sees this reflected in the profit growth potential for coal and nuclear power plants, explaining that the need for additional generation has been satisfied over the past decade by building natural gas-fueled power plants and pressing aging plants into extended service. While these plants got the industry through the heat waves sweeping across the nation this summer "in real good shape," delivering record supplies of electricity, the rising cost of gas made this an expensive effort, Morris pointed out.
As a result of the new law, he expects that "capital will flow into [the power] business as it needs to."
--Jim Brumm Calpine's Unwanted Attention
California Energy Circuit, November 11, 2005
The stock of Calpine Corp. has attracted a lot of interest recently - short interest, that is. The result has been a tale of lost faith told by the erosion of the independent power producer's share price on the New York Stock Exchange over the past three months. Short interest is the result of short sales. It is a bet that a stock's price will decline made by borrowing stock and selling it in the expectation that the borrowed shares can be replaced with stock purchased at a lower prices. The number of shares borrowed at any given moment to make these bets is a stock's short interest. It is reported once a month by the exchange where the stock is listed for trading.
Calpine is listed on the New York Stock Exchange, which reported in mid-September that short interest in the stock topped 226 million shares. That is about 47 percent of the power plant operator's outstanding shares and the most of any stock listed on the NYSE. By mid-October, the short interest had declined to 213 million shares - still more than 44 percent of those outstanding and still the largest total of all the stocks trading on the exchange.
Just the reporting of such totals adds to the pessimism that led to the bet in the first place. The associated cynicism can become self-fulfilling - aided by encouragement from "shorts," the label put on traders who placed the bets.
The encouragement often comes in the form of rumors, such as those that pushed Calpine shares down a third before trading was halted for a company statement on April 22.
In a news release responding to trading pressure that resulted from false market rumors, the company said: "While it is not Calpine's policy to respond to market rumors, we feel compelled to comment today to assure the marketplace that these rumors are false. Calpine remains in compliance with its corporate and project indentures. Further, the company assures the market that it has no plans to file for bankruptcy."
There was nothing in the statement about the rumors, although there was a hint in the word bankruptcy.
Before trading was halted on the third Friday in April, Calpine's common stock traded at $1.70/share - its lowest price in two and a half years. And the company's reaction was far from satisfying.
"Obviously the suggestion that all is well is not enough. They will have to be more forthcoming with new information," Maxcor Financial analyst Daniele Seitz told Reuters.
As it turned out, the stock price continued to decline, reaching a low of $1.32/share in early May before the company reported a first-quarter loss in line with expectations.
This was followed by another phenomenon of large short-interest positions -- a short panic. This features heavy buying of the stock once the price starts to rise as those who have profited by the decline attempt to maximize their gains by purchasing replacement shares at the lowest price possible.
In one late-May session, nearly 70 million Calpine shares changed hands as the price surged to about $2.50/share from $2/share on one such panic. The stock then continued to climb, reaching nearly $4 in early August before more rumors of financial problems started to wear on the company?s credibility.
Again, as TheStreet.com put it, Calpine didn't make life easy for investors.
Instead of initiating reports of bondholder challenges to its use of cash from asset sales, the company waited until the news was spread by others and then verified the reports. By Wednesday, this had driven the stock price as low as $1.83/share before some shorts figured they had profited enough and closed their trades with purchases of more than five million shares in 45 minutes.
Once again, the end is in sight for Calpine's bad-news mongers.
Today, the company is appearing before a Delaware court, asking it to release funds blocked by bond trustees.
Last week the company's general counsel, Lisa Bodensteiner, told analysts, "We expect the trial to last one day and that the decision from the court will be made promptly thereafter."
She also said a hearing has been scheduled for December 19 and 20 to finalize an order issued in August on funds blocked by other trustees.
Jim Brumm
There Is No Such Thing as a Free Lunch
California Energy Circuit, July 8, 2005
The axiom "there is no such thing as a free lunch" has been around for some 160 years, popularized most recently by Nobel Prize winning economist Milton Friedman as the title of a 1975 book.
But as hot weather spreads across the nation this summer, its truth seems to have been forgotten by those expecting reliable power delivery during periods of high demand.
The free-market forces unleashed by deregulation did attract power plant investments, resulting in significant overcapacity in generation across most of the nation.
At the same time, the Federal Energy Regulatory Commission's 2004 State of the Market Report points out that urban areas where high costs limit construction of new power plants or transmission lines suffer from inadequate capacity.
The report from FERC's Office of Market Oversight and Investigations calls these needy areas "constrained regions" and says that there are six of them in the U.S., including Southern California and the San Francisco Bay area.
Just because capacity—to produce or deliver power—is not growing in these constrained areas does not mean that demand is also stagnant. Rather, there's been a growth in power demand that has not respected the various barriers to electricity delivery, leaving utilities with little choice other than to decide who will have to do without.
As California has demonstrated over the past five years, the resulting curtailments are not popular.
The question has become "How unpopular?" What are people willing to pay to have electricity every time they flip the switch?
Federal regulators have tried to answer this question by mandating increases in the prices paid for electricity during periods of high demand. Economists theorize that this will reduce demand by pricing some users out of the market and increase supplies by attracting investments in generation, admitting that most of the hope is based on funding new power plants to meet these peak demands.
For California, FERC's prescription came in an order quadrupling the state's price limits—called market caps—from $250 to $1,000 per MWh in steps to take effect over an extended time period.
Many months earlier, however, the same commission decided that high prices alone were not enough and adopted an incentive called locational installed capacity, or LICAP. This promises payments to anyone willing to build a power plant and have it ready for operation during periods of peak demand. These payments would be in addition to payments for a plant's electricity output and would be greater the closer the plant was to an area of high demand.
The payments would be recovered as part of the cost of all power distributed in the area protected from power interruptions by the standby capacity.
Just as Nobel Prize winner Friedman adopted an old phrase in naming his 1975 tome, the idea of paying for standby capacity is not new to the utility world.
In the days before deregulation, utilities were allowed to earn a return on the capital used for any equipment approved by regulators—whether the equipment was used one hour a year or 90 percent of the time.
But deregulation did away with guaranteed returns, increasing the cost of borrowing the capital needed for such investments for both utilities and private developers by as much as 50 percent, according to Joseph Somsel, a former Pacific Gas & Electric official. A nuclear engineer, he is currently involved in construction of a nuclear power plant in Asia.
The new way of financing standby capacity became a political controversy in mid-June when a FERC law judge approved the LICAP plan put forward by the New England Independent System Operator, the area's power distributor.
The same day, the New England grid operator released estimates that the decision would increase its six-state region's cost of electricity by some $10 billion to $13 billion over the next five years.
Before dismissing New England as a far-away place featuring strange accents and succulent crustaceans, consider that the Northeast corner of the U.S.—like the Southwest corner—includes two of FERC's six designated constrained regions: Boston and southwest Connecticut.
While declining to discuss FERC's locational capacity market theories, California Independent System Operator spokesperson Gregg Fishman said, "We agree with the concept of capacity markets," pointing out that the agency is "in the early stages of looking at a capacity market here in California" (Circuit, Oct. 8, 2004).
Another coast-to-coast similarity is the political reaction. While Californians are floating a ballot initiative to reregulate electric industries, Connecticut?s legislature opened the same door by allowing utilities—which had to sell their power plants a few years ago—to build and own up to 250 MW of peaking capacity.
The bill sent to Governor M. Jodi Rell last week would provide conservation and power plant construction incentives aimed at bolstering the state?s inadequate power reserves and offset an estimated $300 million to $600 million a year in higher power costs seen as the state?s share of New England's LICAP pricing.
While $600 million doesn't sound like much to Californians, it is another $120/year for an average residence in southwestern Connecticut just to ensure that there will be power to cook the year's 365th lunch—a stark reminder once again that the last megawatt needed to supply electricity on demand leaves no such thing as a free lunch, even if it is microwaved crustaceans.
Jim Brumm |
|
|