Business & Money

The collapse of wholesale markets has utilities once again making the purchasing decisions, and taking all the risks.
Fortnightly Magazine - June 1 2003

The collapse of wholesale markets has utilities once again making the purchasing decisions, and taking all the risks.

If a common theme is emerging from the various policy directions across the country, it seems to be that responsibility for supply resources is moving away from open markets and back into the hands of load-serving utilities.

This is partly a survival response from an industry that has been in crisis. In the absence of a liquid wholesale power market, state regulators and utilities are reverting to resource planning systems that hearken back to the early 1990s. This dated practice-known as integrated resource planning (IRP) and competitive bidding processes-is being welcomed by regulators and even beleaguered merchant players desperate for reliable revenue streams.

"IRP is tried and true. It's something that regulators are familiar with," says George Gross, a professor at the University of Illinois at Urbana-Champaign, and formerly a manager of electric resource planning at Pacific Gas and Electric Co. "For lack of anything better, IRP is a possibility at this point. But I am not convinced this will be effective policy."

The industry has changed, Gross says, and even integrated utilities are loath to return to the old environment. At the same time, however, a return to IRP in some form might help the industry get off the dime and move into its next stage of evolution, some analysts say.

IRP: Merchants Return To Their IPP Roots

Merchant power producers are struggling to find a new business model that works in the current market, while not setting them up for failure in the future. In some ways, the emerging model looks a lot like the IPPs of old. Namely, their power plants increasingly will depend on long-term power purchase agreements (PPA) for stable cash flow.

Some things are notably different, however. First, the definition of "long-term" has changed. While the IPPs of old frequently operated under 15- to 30-year PPAs, today's long-term contracts specify five- to 10-year terms. Additionally, while classical IPPs had virtually all of their output committed under contract, the new merchant IPPs must continue to market much of their capacity via spot-market sales and short-term contracts.

In many parts of the country, an apparent oversupply situation has limited utilities' new capacity requirements in recent years, and long-term contracts have been virtually absent from the market. Now, however, signs of life are beginning to return to the market.

"We're seeing an uptick in RFPs and bidding processes," says Steven Schleimer, Calpine's director of market and regulatory affairs for the western region. The illiquid power market, ironically, is partly responsible for this increase in demand for long-term power supplies. "Utilities and merchants are both looking to manage their risks with longer-term deals," Schleimer says.

Regulators, likewise, are eager to prevent the price spikes and supply dislocations that have jolted consumers in recent years. "The regulatory agencies seem to want to take a more active role in overseeing utilities' portfolios," Schleimer says.

Power Returns to the PUCs

IRP and competitive bidding programs represent a logical way for public utility commissions to take this more active role. In California, for example, the California Public Utilities Commission (CPUC) has been developing a new IRP framework for the state's investor-owned utilities.

"We have a history, prior to restructuring, of relying on non-utility power plants to meet California's resource needs," says Barbara Hale, the CPUC's director of strategic planning. "That approach will persist as we reinvigorate the resource-planning process. I don't think anyone expects the IOUs to stop contracting for power."

A primary goal of California's new IRP process will be to expand diversity in utilities' resource portfolios-specifically to increase by 1 percent per year the amount of renewable energy used and to prioritize demand-side management. Indeed, renewables and conservation have kept IRP processes alive across the country even as power markets have been restructured. But in California and other states, IRP seems to be evolving into a somewhat different animal than it was in the past.

"We've come to consider ours a hybrid market," Hale says. "We have a reliance on wholesale markets, a reliance on IOUs, and the opportunity for customers who have established a direct-access energy service provider to continue that relationship." California, like the rest of the country, is striving to maintain a delicate balance between old-world regulation and new-world competition.

How To Keep It Liquid?

Creating a hybrid market that works today while not impeding progress toward greater liquidity requires careful thought. At first glance, the state-mandated IRP approach seems to defy the goals of open, liquid power markets.

"There's a tension there," says Dick Watson, director of the power division at the Northwest Power Planning Council (NWPPC) in Portland, Ore. The NWPPC requires its member utilities to pursue IRP processes that date back to 1991. Idaho Power has already issued an RFP for new power supplies, and Pacificorp is reportedly planning a solicitation as well.

"The degree to which you recognize the market in your planning process is the crux of the issue," Watson says. "It is a tug-of-war."

Trends toward competitive bidding and IRP seem to be pulling the industry back toward its less-regulated state. This represents an unmistakable regression for an industry that only a few years ago was marching toward a generally laissez-faire market structure.

"Once you get back into that mode, there won't be a merchant industry anymore," says Roger Feldman, a partner with Bingham McCutcheon in Washington, D.C. "There will be a build-to-suit or tolling industry. That's all right, except that it doesn't necessarily add up to a coherent resource plan, which takes you all the way back to the '70s and '80s."

Regulators' new assertiveness doesn't bode well for open markets, unless regulators pursue a new, market-oriented IRP model rather than the prescriptive programs that IRP traditionally represented. "I'm not in favor of IRP in terms of what it used to be, because it was a substitute for the market," says Larry Eisenstat, a partner with Dickstein Shapiro Morin & Oshinsky in Washington, D.C. "On the other hand, if we're going to have an ISO or regulatory authority identify a problem and then put the solution to that problem out to bid, that's the kind of IRP that I can deal with."

Eisenstat explains that a regulatory approach that makes sense in today's market will provide a process for resource planning, but won't actually perform that planning. "It doesn't make the decision, but it ensures that the utility's decision-making process will result in what's best for ratepayers," he says.

Of course, defining what's best for ratepayers is a proposition fraught with disagreements over rates and ratemaking policies, plus price stability, reliability, environmental impacts, transmission siting, and creditworthiness issues. All of these questions are intertwined with issues regarding technology, regulation, and market design.

Resource Adequacy: It Depends On Where You Sit

The Northwest region, with its predominance of hydroelectric power and electric residential winter heating, faces a significantly different resource-adequacy situation than does the Southeast. A generic standard market design will not satisfy either constituency, and as a result, both oppose FERC's proposed SMD rules. Additionally, these issues incite disagreements on all sides. How RTOs should address resource adequacy is a prime example.

One attorney puts it in perspective. "We're collectively managing three sets of laws: the laws of physics, economics, and politics," says Michael Zimmer, international partner with Baker McKenzie in Washington, D.C. "You can't look at one in the absence of the others. We've lost sight of that as we've gone down the course of restructuring."

Integrated Resource Planning: A Step Back in History

State regulators developed integrated resource planning (IRP) in the 1980s as a way to bring renewable energy and demand-side management into the utility resource mix. Generally speaking, these were prescriptive programs that established specific goals for utilities to meet in procuring these alternative resources.

When utilities began contracting for long-term power supplies from independent power producers, regulators began expanding IRP programs to include competitively sourced power capacity from qualifying facilities (QF)-first renewable energy plants, and eventually cogeneration facilities using a variety of fuels.

The procurement methodology of IRP was, in most cases, competitive bidding. These programs effectively launched merchant plants into the big time, laying the foundation on which a highly attractive power plant development business was built.

IRP and competitive bidding faded into the background as the PURPA-driven independent power producer business was transformed into a large and dynamic merchant power industry. In the past five years, approximately 95 percent of the new power plants brought into service have been built outside the utility rate-base, representing more than 300 GW of capacity. Most of these facilities are merchant plants with minimal or non-existent long-term power sales arrangements. -M.T.B.

Business News Bytes

Energy Traders TXU, Sempra, Constellation Energy 1Q Earnings Impacted by Accounting Change

A slew of energy companies saw their first-quarter earnings results negatively impacted by the Financial Accounting Standards Board's Emerging Issues Task Force 2-03 decision to eliminate mark-to-market accounting for certain commodity-trading assets and changes the timing of earnings recognition for revenue. In essence, say analysts, the new rules will price energy contracts at cost rather than fair value, and forces energy traders to report earnings as they are received rather than at what they expect to receive throughout the life of the contract. Sempra Energy, for instance, posted first quarter net income on May 1 of $88 million, or 42 cents per share, down from $146 million, or 71 cents a share, a year earlier. The results reflect a non-cash reduction in earnings of $38 million, or 18 cents per share, from EITF Issue 2-03. Excluding the effects of the accounting charge, Sempra would have earned $126 million, or 60 cents per share, falling short of Thomson First Calls analysts' average consensus estimate of 68 cents per share. Sempra missed the analysts' estimates because of a reduction in net income from the company's trading entity. EITF Issue 2-03 also tremendously impacted TXU Corp.'s earnings. On May 1, TXU posted earnings of $40 million, or 14 cents per share, compared to $250 million, or 94 cents per share in the same quarter of 2002. The accounting change resulted in an after-tax charge of $63 million. Excluding items, income for the latest quarter was $101 million, or 30 cents per share, beating analysts' average consensus estimate of 21 cents per share. Moreover, Constellation Energy Group Inc.'s first quarter earnings were down because of the new accounting standard, which resulted in a net charge to Constellation of $198.4 million, or $1.20 per share. The company reported a first-quarter net loss $131.4 million, or 80 cents per share, compared to a net profit of $228.6 million, or $1.40 per share, a year earlier.

Detroit Edison Co. Reports 1Q Income of $155 Million, Adjusts Future Earnings

DTE Energy Co. said May 2 that net income for the first quarter was $155 million, or 92 cents per diluted share. This compared to the Thomson First Call analyst consensus of $1.30 and earnings of $200 million, or $1.24 per diluted share, for the same quarter last year. Operating earnings for the quarter, excluding discontinued operations, the effect of accounting changes and other non-recurring items, were $178 million, or $1.06 per diluted share. Earnings from operations for the year-ago quarter were $181 million, or $1.12 per diluted share.

Among some of the company's business segments, DTE Energy Resources earned 62 cents per share for the quarter, down from 69 cents in the year-ago period. The units regulated operations, which include subsidiary Detroit Edison Co.'s power generation business, suffered from higher costs for plant maintenance and replacement power, as well as higher pension and health-care costs. The unregulated segment, which includes marketing and trading and coal services, benefited from higher synthetic fuel production volumes and increased margins.

Additionally, the company adjusted its 2003 operating earnings guidance to a range of $3.75 to $3.95 per share. Previous guidance of $3.90 to $4.10 per share included the company's transmission business, which was sold in late February.

AES Swings To First-Quarter Profit

AES Corp. posted net income for the first quarter 2003 of $93 million, or 17 cents per share, compared to a net loss of $313 million, or 58 cents per share, in the same period of 2002, exceeding Wall Street estimates of 6 cents per share. The company attributed the improvement to higher power prices and asset sales.

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