Competition abounds at wholesale, but retail is another story.
Will geography, politics and regional economics stand in the way of real choice for electric consumers at the retail level? Consider this tale of two power players.
One competitor, the Indiana Municipal Power Agency, is proud of itself. In its annual report, IMPA says that open access and competition in the wholesale market allowed it to trim wholesale rates for power it delivered to member distribution companies in 1996. "The results were remarkable," the report reads. "Rates to members decreased by more than 5 percent for the second consecutive year."
But take a look at Duquesne Light Co., an investor-owned utility. Like the IMPA, Duquesne has made progress at wholesale, where its rates appear competitive. Yet its retail rates rank among the highest in the nation. Apparently, Duquesne's retail customers pay a heavy subsidy to its wholesale buyers. Will consumer choice put an end to such anomalies?
Overall, any correlation between wholesale and retail power markets appears tenuous at best. The ratio between wholesale and retail prices varies widely from utility to utility, even though both are supposedly based on cost. The rates are set by different regulators, state and federal, and so have never been reconciled.
So what did the National Energy Policy Act of 1992 do for wholesale competition? Not much, at least not yet. In fact, deregulation of wholesale power has not made a huge difference. Moreover, where it has wrought change, the market faces a reckoning with environmental concerns, capacity problems and legal issues. On the other hand, prices are down, competition is up, and the power brokerage business is booming. The glass, while filling slowly, is at least filling.
At retail, however, all the analysis one reads about opportunities for cost savings from electric competition must be taken for what it's worth. Wholesale competition is working, and probably has been for a long while, but retail competition is still a muddled pipe dream, at best, with many difficulties ahead.
You Can Get It Wholesale
The wholesale power market is large and complex. Roughly 2,000 cooperative and 1,000 municipal (em mostly small and rural (em systems exist in the U.S. More than 200 investor-owned systems serve 70 percent of demand, especially in large urban areas. In the contiguous U.S. (and Canada), these thousands of separate systems are divided among 10 regions that manage reliability and supply, each with its own way of running things. One region may have a single control center, another more than 30. Together, these regions fall under the administrative umbrella of the North American Electric Reliability Council, or NERC.
All these systems buy wholesale power; many generate and sell it as well. The number of possible buyer-seller combinations, not to mention possible transmission paths between them, is staggering. Thrown into the mix are hundreds of power brokerage firms and a growing derivatives market, plus a handful of federal generating and marketing agencies.
That's the wholesale market. But the wonderful strangeness of electricity makes the grid a commodity market like no other. Consider the term "loop flow." It was coined by the Western Systems Coordinating Council, which bills itself as the world's largest machine. WSCC has a hole in the middle of its grid where few people live. When electricity is shipped from the coal fields of Montana to Seattle, sometimes 40 percent of it goes south through the "loop" via California. Every sale travels by all available routes from point of origin to destination. The market is founded on this fictional "contract path," but the fiction has yet to be resolved, which underlies a lot of the difficulty in bringing customer choice to retail markets.
Another problem, ironically, concerns NERC itself, the guarantor of reliability. In fact, the various NERC regions, though designed to ensure reliability of wholesale power supply and the transmission grid, actually create one of the greatest obstacles to long-distance wholesale trade. Transmission capacity between adjoining regions typically runs much less than 5 percent of generating capacity within either region. For example, ECAR claims about 100 gigawatts of generating capacity, much of it using low-cost coal, but has only about 4 gigawatts of transmission capacity into the East. So in many cases, the NERC regional structure tends to isolate high-cost suppliers from their potential low-cost competitors.
Nevertheless, wholesale trade is not new. It was a major contributor to system operations in the utility industry before deregulation. Resale jumped dramatically, from about 17 percent to 25 percent of all power sales between 1988 and 1992, before wholesale deregulation.
Competition for this trade also pre-dated the new law. Cooperatives routinely bought from multiple suppliers. In the 1980s, municipal utilities in most states formed joint-action agencies, like IMPA, to buy wholesale power competitively. Federal power marketing agencies were active in both cooperative and municipal markets, where they are bound by legal preference. Large IOUs have opted to buy power rather than increase generating capacity; IOU's purchased power costs now equal fuel costs. The control centers also have worked hard to find cheap power. However, only a small fraction of these IOU purchases come from PURPA facilities, 20 percent on average and half of that in WSCC and ERCOT. And this figure should not imply that PURPA sales are competitive; often they are not.
With this robust wholesale trade, concerns turn to the retail front, where slow progress appears to be a problem.
There are several good reasons why, after 5 years, the 1992 act has not created the impact some had predicted. First, competitive wholesale trade was well developed before the law was passed. Interchange capacities between the 10 NERC regions are too small to support much growth beyond this pre-existing level. In fact, the transmission network was not designed to support a robust spot market. Finally, long-term wholesale contracts and a risk-averse customer-base tend to inhibit competition.
History and Geography: Barriers to Trade
Two reasons contribute to the high cost of wholesale electricity, neither of which likely will disappear very quickly when competition moves to retail markets. One is geography (em the distance from the coal fields. The other is historical, accidental or political (em the late-model nuclear power plant.
Generally, utilities near coal fields pay 60 cents to $1.20 per million Btu for fuel. Distant utilities pay nearly $1.50 to $2.00 for the same resource, and pass that increased cost onto customers (unless they happen to have a lot of hydropower). It's that simple. NERC regions are more or less concentric with respect to the coal fields. Thus transmission constraints between regions severely restrict the ability of low-cost coal plants to compete with their expensive, distant counterparts. As a result, the industry ships coal instead of its refined product, electricity. Other industries aren't limited to shipping only the raw materials.
But power lines remain difficult to build. This obstacle is not entirely NERC's fault, however, even though the most-needed lines would cross NERC boundaries. According to some experts, the single biggest step the industry can take toward promoting electric power competition, wholesale or retail, is to grant federal eminent domain for transmission lines, as was done for gas pipelines. Interestingly, the gas people may disagree.
This summer, at the Gas Summit (em the 2-day technical conference at the Federal Regulatory Commission on the future of gas pipeline regulation (em several executives from pipelines proposed a new idea. They said they would voluntarily give up their legal right to eminent domain, if the FERC would compensate by eliminating various levels of regulation, such as its certification of gas pipelines, or perhaps its rate-of-return regulation of pipelines. Nevertheless, the gas industry would probably concur with electric utilities that long-haul transmission facilities are difficult to plan and construct in either business.
Beyond geography, history lies behind the second major industry problem, which stems from high-cost, late-model nuclear plants.
Nuclear plants brought on line in the 1980s cost about four-times more than coal-fired plants per unit of capacity. These nukes were built primarily in the Northeast and North Central, and so cut across NERC regions. ECAR has coal-based American Electric Power and Allegheny Power System Inc. versus nuclear-burdened Duquesne Light Co., Ohio Edison Co./EnergyCorp. and Centerior. MAIN has the mother of all nuclear utilities (em Commonwealth Edison (em just north of the Illinois basin coal fields. But in many of these cases there are few wholesale customers. The concentration of wholesale customers and that of nuclear plants do not overlap.
Reluctant Buyers: Barriers to Change
With a few notable exceptions, like Virginia's Blue Ridge group, most wholesale buyers still appear wary of wary of competition. Two out of three of Maryland's municipal systems in 1995 (three years after wholesale power deregulation) took the bold step of insisting on having only three-year contracts with Allegheny Power, not the usual five- to eight-year terms. Now they have hired a consultant to put together a request for proposals for competitive power.
But munis in the distribution business may have a good reason to keep their local supplier, especially if it is a big IOU. In times of distress, the local IOU can supply trucks and crews. Nobody calls the muni's chief engineer at 2 am to complain about the price of power being a half-cent per kilowatt-hour too high. They call if there is no power. Of course, one could unbundle emergency service, but so far this is a fiscal conundrum that few have cared to attack.
Then there is buyer lock-in. Many potential wholesale customers have financial interests in local power plants, and nobody wants to strand their own investment. Many of those late-model nukes are partly owned by municipalities. Likewise, most distribution co-ops have an interest in a generation & transmission co-op with a heavy debt load.
Worse yet, the system was not designed for competition. Engineers like to say that if a system was not designed to do what you want it to do, then it won't do it. Generally speaking, lines go from specific plants to specific load centers. If the industry wants a true grid, then it will have to build one.
Environmental Threats: Catalyst for Protests
Increased use of low-cost, highly competitive coal-fired generation, especially in ECAR, SERC and MAIN, is on a collision course with national environmental concerns, whether well-founded or not. A fundamental change in the regional dynamics of the electric power market could occur quickly if these plants are subjected to massive new controls, even to the point of negating many of the benefits of competition.
There has been an amazing lack of discussion of environmental issues. FERC's 1995 Environmental Impact Statement for open access projected an increase in coal-fired generation and therefore emissions. This has touched off a growing wave of objection by environmentalists and the entire East Coast. The FERC's statement has caused a lot of confusion, however, as it projected virtually no increase in emissions from open-access, per se. This predicted increase of thousands of tons of NOx per year occurs with or without the regs, simply due to the Energy Policy Act. It does not include any new transmission capacity from the coal fields to high-cost states.
These projections, plus the concept of transport of ozone and its precursors, have become a catalyst for the environmental community, led by the U.S. Environmental Protection Agency. EPA has launched several rulemakings aimed squarely at coal-fired power and promulgating tougher national ambient air quality standards. At the height of this summer's ozone season, the Washington Post made a pointed reference to "the belching smokestacks of Ohio" as a major source of the East Coast air quality problems. Then there is global warming, an extremely speculative issue, but one EPA is working hard to link to its air-quality initiatives.
Capacity Margins: Misunderstood by Everyone
How can a must-run plant qualify as stranded investment?
Studies by analysts such as Moody's Investors Service, Resource Data International, and Citizens for a Sound Economy claim there is an abundance of low-cost excess generating capacity that should ramp up in a competitive market.
Industry analysts like Cambridge Energy Research Associates claim there is a growing shortage of generating capacity, verging on crisis. Can both groups be right? Yes, because they are talking about two different kinds of capacity (em specifically, capacity to meet normal demand and capacity to meet peak demand. The distinction, and hence the confusion, derives from the unique nature of electricity as a commodity that in large part cannot be stored.
Electricity demand dips and peaks seasonally. This fluctuation explains why even base-load plants only operate about 65 percent of the time. This excess capacity could be used to steal sales or satisfy increased demand, except during peak-demand seasons. If low-cost plants should pick up this use, then the high-cost plants that lose business are supposedly stranded.
But consider annual peak demand. Capacity margins have fallen to less than 10 percent in some NERC regions, especially MAAC, MAIN, ECAR and SERC; this means 90 percent use of existing plants. Margins continue to slide, new construction has slowed and peak demand grows robustly. Summer peak demand grew 30,000 megawatts nationwide in 1995, while only about 6,000 MW of capacity was added. Demand-side management programs report an annual reduction in peak demand of 10,000 megawatts or so each year, but that does not mean peak demand is going down. These are reductions from what would otherwise have occurred, or so it is claimed.
This growth has caused almost every generating unit to run for at least several unpredictable weeks a year. Otherwise, the nation would run short of power and black out because electricity, unlike other commodities, can't be sold on a first-come basis. But in a competitive scenario, the price for power from those plants that only run a few weeks has to cover their full annual cost. So they are not stranded. Just about every plant we have is a 'must run plant' in this sense.
The price to cover annual peak using these high-cost plants could grow astronomical. In some cases, it is already 10-times the off-peak price, but could go much higher as supplies tighten. This growth could lead to cost-saving measures such as turning off air conditioning or shutting factories. It could also lead to building of efficient peaking plants, as our present mix is too heavy with base-load equipment. But adding enough peakers to displace all high-cost plants could take a long time, especially given the growing clean air constraints.
It is not clear when or how fast high-cost plants are likely to be stranded or which ones will lose a significant portion of their revenue stream. One can't say that every high-cost plant is a loser, because right now all are needed, despite cost.
Note, too, that we are talking about heavily regulated competition and the regulators, for political reasons, have always cross-subsidized maximum peak. Consumers will not tolerate too much volatility in their bills; certainly not unpredictable price jumps of 100 percent, probably not even 10 percent. Price increases allowed for peak power may not be enough to stimulate the cost-avoidance measures that would strand expensive plants.
So again the question is how can there be stranded capacity when there is no excess peak capacity? The confusion is evident. Given a storable commodity, 65 percent use of production means excess capacity. Not for electricity. Off peak must always be a buyer's market, on peak a seller's, unless peak capacity is overbuilt in true business-cycle fashion.
Marketers and Brokers: Key to Choice?
Can power brokerage (em now a multi-billion-dollar-a-year industry (em bridge the gap from wholesale competition to true consumer choice?
Today more than 300 power marketing firms are operating, the largest of which sell more power than some of the largest utilities. For example, in 1996 the leader Enron sold about 60 billion kWh, a figure greater than the wholesale trade of some entire NERC regions. Of course, some sales are between marketers, and others are hedges and futures contracts used to establish a firm market, not for physical delivery. But many of these deals are for delivery. On the face of it, marketers are doing the jobs that the independent system operators and power exchange spot markets were created for, but seem unable to perform.
The growth in brokerage activity is explosive. According to the Edison Electric Institute's Power Marketers Yearbook: "Power marketers in 1996 sold approximately 230 billion kWh (em more than eight and a half times the 26 billion kWh sold by marketers in 1995 (which was nearly four times 1994 sales). This total represents between $3.3 to $7.1 billion in 1996 sales, compared to roughly $450 to $670 million in 1995. Subtracting the cost of power purchased, marketers are estimated to have netted approximately $240 to $770 million."
In 1994, power marketer sales composed about 1 percent of wholesale sales. In 1995, that number leaped to 6 percent and to more than 20 percent in 1996. In some cases, the power is sold six or eight times before it is delivered. In fact, the power marketing industry in many respects looks like a derivatives market, not a supply market.
Nevertheless, this secondary derivatives market may be just what is needed to make competition flourish at retail.
William Daniel Fessler, former president of the California Public Utilities Commission and an architect of that state's restructuring plan, said, "The idea of customer choice is a convenient fiction, the so-called contract path." Fessler, who taught contract law for many years, said: "So long as the customer takes delivery of electric energy off of a high-voltage transmission grid, the energy is fungible and utterly commingled. Bilateral contracts are, in the final analysis, financial transactions aimed at risk apportionment." In other words, derivatives.
Whatever power brokerage is, it is taking off, and taking the electric industry with it.
David E. Wojick P.E. is an independent consultant on the dynamics of the electric power industry. His clients have included the AES Corp., Duquesne Light Co., Allegheny Power System Inc. and the Chief of Naval Research.
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