Energy Hedging, Part II

Prior to recent industry restructuring, the electric power sector consisted predominantly of utility companies holding monopolies to generate, transmit, and distribute electricity within a specific geographic area.  Each utility took care of building enough power plants to supply its own customers, including enough excess capacity to ensure reliability.  Utilities would also buy and sell power amongst themselves on a limited basis to balance the supply and demand in their own systems.   State Public Utility Commissions (PUCs) approved the rate that each utility charged to its customers (households, stores, factories) based on the amount the utility spent to build and operate its own plants and power lines.

The impetus to change this system came from arguments about market efficiency.  With each individual utility responsible for carrying enough excess capacity to ensure reliability, the total amount of reserves across regions as a whole was more than necessary – and each utility’s customers were paying for all of that excess capacity to sit idle, like expensive blackout insurance.  Because utilities could recover the cost of their investments in pre-set, regulated retail prices, they had little incentive to tightly manage capital and operating costs or to put a lot of effort into technological innovation. Looking around at the rest of the developed world, this was one market where the United States was a laggard:  the UK, Australia, Argentina, Chile and New Zealand all moved away from a monopoly system long before the U.S. did. Ironically, despite having a structure that fostered inefficiency, the U.S. electric power industry provided power at prices lower than in most of the rest of the world.  However, the 1990s was a time when the notion of competitive markets was very much in vogue, so the “deregulation” argument was an easy one.

Regulatory restructuring of the electric power sector involved four different initiatives, which were implemented at the federal level, and to varying degrees at the state level.  First, Congress passed the 1992 Energy Policy Act, which forced utilities across the country to buy power at fair rates from anyone who wanted to generate electricity in their service territories.  This caused a boom in construction of “independent” power plants, built and operated by newly-formed private companies, or independent affiliates of utilities.  Utilities for the most part stopped building much new capacity themselves, finding that it was cheaper to let these aggressive new players make the investment decisions.  The role of electric power traders also came into being, with new utility subsidiaries and independent companies like Enron jumping into the business of buying and selling power across the country.

Then, during the mid- to late-1990s, individual state legislatures and PUCs addressed the goal of lower retail prices by enacting some or all of three regulatory changes: 

•  Asset divestiture. Ahandful of states passed legislation forcing utilities to divest their generation assets (i.e. their power plants), breaking up their vertical monopolies.  Theory suggests that independent owners of the assets would operate them at a lower cost, resulting in lower prices; splitting the assets into multiple hands would also increase competition and further drive down prices.  When assets were sold at auction, the highest bidder was often another utility or its independent affiliate.

•  Retail access. Many states legislated an end to utilities’ geographic service territories by granting a universal right to sell retail electricity service.  In those states, households and businesses can now choose their electricity provider just like they choose their long distance provider.  In theory, the pressure to offer customers a low electricity price to retain their business creates the incentive for utilities to generate or procure power at the lowest possible cost.  In many cases, however, retail prices were low enough to begin with, such that undercutting them has been difficult.  In states with retail competition, very few households, and only some electricity-intensive businesses, have exercised their right to choose an alternate power provider.

Between December 2000 and March 2001, California wholesale gas and electricity prices spiked at up to 10 times their normal levels, and capacity shortages resulted in rolling blackouts.   In parts of California where the local utility was allowed to pass procurement costs through to customers, consumer electricity bills tripled.  In contrast, utilities that were forced to buy power from the volatile wholesale market, but sell it at pre-set regulated rates, suffered billions in losses.  Pacific Gas & Electric, the country’s then-largest utility, actually went bankrupt despite a large-scale bailout attempt by the state government.  For several years after this crisis, the power sector was overwhelmingly focused on understanding its causes and trying to draw conclusions for the future of regulation.

The infamous California energy crisis of 2000/2001 is commonly attributed to three concurrent causes:  (1) a “perfect storm” of market fundamentals, (2) poor regulatory design, and (3) illicit market manipulation: 

1. A perfect storm. Hydroelectric plants in the Pacific Northwest normally provide one fifth of California’s power; but in 2000, spring draughts substantially reduced hydro capability, compressing the supply curve.  At the same time, natural gas bought cheaply in the summer and stored underground normally provides much of California’s wintertime gas needs; however, because gas plants had to operate more in the summer to make up for lost hydropower, gas was expensive in the summer of 2000 and storage facilities could not be filled, further tightening supply.  In addition, because power plants were running overtime to compensate for lost hydropower, they also went down for maintenance more often during the fall of 2000 and winter of 2001.  Winter storms washed kelp into the intake system of one of California’s main nuclear plants, forcing this backbone of the grid to operate at greatly reduced capacity at the same time as those winter storms caused electricity and gas demand to soar.  On top of everything, capacity reserves in the state were low because nobody had built new power plants in years, due to uncertainty over whether and how restructuring would take place, as well as strong not-in-my-backyard (“NIMBY”) opposition from residents.  This unfortunate coincidence of events reduced supply and increased demand for gas and electricity, creating a textbook example of a constrained market with extremely high price spikes.

2. Market structure problems.  Problems with California’s newly restructured power market exacerbated the impact of high prices on the industry and consumers.  California mandated asset divestiture without vesting contracts for plant output, meaning that when supplies became constrained, the state had no authority to demand that power plants sell electricity to in-state buyers.  While forced divestiture aimed to reduce generator market power, the state didn’t go far enough with such safeguards.  Some generators controlled up to 8% of the state’s capacity, which turned out to be enough to exercise market power – i.e., in a constrained market, they could offer their output at extremely high prices and still make a sale.  Observers noticed this type of market power gaming before the crisis peaked, but the Federal Energy Regulatory Commission (FERC, who has jurisdiction over monopoly behavior) refused to act. Most dramatically, the California legislature had mandated that utilities buy all of their power in a central spot market, while providing it to customers at fixed, regulated rates.  When this rule was written, a scenario of wholesale prices exceeding regulated retail rates was considered inconceivable; however, as wholesale prices spiked in the winter of 2001, utilities found themselves buying high and selling low, massively subsidizing every kWh of electricity supplied to customers until they had no funds left to do so, and the government stepped in to procure power for the state’s residents. 

3. Manipulation. Aconstrained market and poorly designed regulations resulted in a situation ripe for both clever arbitrage and outright manipulation.  In the first case, electricity generators and traders in California responded to the incentives that the legislature created for them with the new regulatory structure.  For example, glaring loopholes in the restructured market rules allowed players to export and re-import power into the state to avoid price caps, thus driving prices higher.  Similarly, players could profit by arbitraging pricing on both sides of a transmission bottleneck, making the bottleneck worse rather than alleviating it. However, in electricity markets there is a rather fine line between clever arbitrage and illegal actions – exercising market power is illegal, but whether a company possesses market power or not changes hour to hour as market supply and demand fluctuate.  Clear illegal actions during the heat of the energy crisis included withholding generation capacity to drive up prices:  declaring false outages, failing to bid output into the PX, bidding output into the PX at unjustifiably high prices.  Generators also illegally gamed the system by submitting false load schedules, double- selling the same electricity, selling nonexistent electricity, deviating from dispatch instructions, and colluding with other generation companies to play these profiteering games. 

Years of public investigation into the causes of the energy crisis focused overwhelmingly on market manipulation games.  Ultimately, the state of California and its residents received several billion dollars in fines from the biggest culprits: the Williams Companies, El Paso Corporation, Dynegy, Reliant Resources, Enron, Duke Energy, Mirant Corporation.  Scrutiny of Enron’s immense profits in California during the winter of 2001 helped draw attention to its web of partnership hoaxes, resulting in the company’s astonishing crash into bankruptcy in the fall of 2001.  In 2002, Congress passed the Sarbanes-Oxley Act in response to the Enron debacle, mandating accounting oversight boards for public companies, requiring companies to furnish enhanced financial disclosures with personal accountability, and providing stiffer sentencing guidelines for white-collar crime.

The rest of the country watched the California energy crisis in horror, with most observers finding a lesson about why electricity market restructuring should be halted or re-examined.  In the fall of 2002, FERC issued a proposal for a carefully-formulated standard market design that could be implemented across the entire country at once, rather than let each individual state wrestle as California did with internal political lobbies to create a flawed regulatory regime.  However, FERC’s proposal was ripped apart from all sides by constituencies that had different ideas of what a fair market would look like. Since 2001, almost all states have simply frozen their restructuring activities in place.  As a result, states now sit at very different points along the continuum between local regulated monopolies and competitive markets for generation and distribution.  With those markets for the most part functioning well despite their heterogeneity, the electric power industry expects to simply remain regulated as it is for the foreseeable future.