California electricity crisis caused due to electricity derivatives trading ?

The California electricity crisis (also known as the Western Energy Crisis) of 2000 and 2001 resulted from the gaming of a partially deregulated California energy system by energy companies such as Enron and Reliant Energy. The energy crisis was characterized by a combination of extremely high prices and rolling blackouts. Price instability and spikes lasted from May 2000 to September 2001. Rolling blackouts began in June 2000 and recurred several times in the following 12 months.

Controversy

While initially the cause of the crisis was defined as being caused either by poorly structured deregulation or by market manipulation, after extensive investigation The Federal Energy Regulatory Commission (FERC) concluded in 2003:[2]

"...supply-demand imbalance, flawed market design and inconsistent rules made possible significant market manipulation as delineated in final investigation report. Without underlying market dysfunction, attempts to manipulate the market would not be successful."

"...many trading strategies employed by Enron and other companies violated the anti-gaming provisions..."

"Electricity prices in California’s spot markets were affected by economic withholding and inflated price bidding, in violation of tariff anti-gaming provisions."

In summary, poorly structured deregulation which relied on active policing by the FERC led to situations where energy companies could manipulate the California energy market with near impunity and reap substantial profits at the expense of California energy consumers and the State.

Most proponents of deregulation suggest that the major flaw of the deregulation scheme was that it was an incomplete deregulation -- that is, "middleman" utility distributors continued to be regulated and forced to charge fixed prices, and continued to have limited choice in terms of electricity providers. Other, less catastrophic energy deregulation schemes have generally deregulated utilities but kept the providers regulated, or deregulated both.

California's utilities came to depend in part on the import of excess hydroelectricity from the Pacific Northwest states of Oregon and Washington. California's groundbreaking clean air standards favored in-state electricity generation which burned natural gas because of its lower emissions, as opposed to coal whose emissions are more toxic and release more pollutants. In the summer of 2000 a drought in the North West states reduced the amount of hydroelectric power that was available to California, though at no point during the crisis was California's sum of [actual electric-generating capacity]+[out of state supply] less than demand. Rather, California's energy reserves were low enough that during peak hours the private industry which owned power-generating plants could effectively hold the State hostage by shutting down their plants for "maintenance" in order to manipulate supply and demand. These critical shutdowns often occurred for no other reason than to force California's electricity grid managers into a position where they would be forced to purchase electricity from other suppliers who could charge astronomical rates. Even though these rates were semi-regulated, the companies (which included Enron and Reliant Energy) controlled the supply of natural gas as well. Under regulation the price of natural gas dictated the price of electricity, so manipulation by the industry of natural gas prices resulted in higher electricity rates that could be charged under the semi-regulations.

In addition, the energy companies took advantage of California's electrical infrastructure weakness. The main line which allowed electricity to travel from the north to the south, Path 15, had not been improved for many years and became a major bottleneck (congestion) point which limited the amount of power that could be sent south to 3,900 MW. Without the manipulation by energy companies, this bottleneck was not problematic, but the effects of the bottleneck compounded the price manipulation by hamstringing energy grid managers in their ability to transport electricity from one area to another. With a smaller pool of generators available to draw from in each area, managers were forced to work in two markets to buy energy, both of which were being manipulated by the energy companies.

It is estimated[3] that a 5% lowering of demand would result in a 50% price reduction during the peak hours of the California electricity crisis in 2000/2001. With better demand response the market also becomes more resilient to intentional withdrawal of offers from the supply side.

Regulation and deregulation
The deregulation of the California energy market was supported by a unanimous vote from both parties in the California legislature and signed into law by then-Governor Pete Wilson in 1996. Then-state senator Steve Peace was the chair of the energy committee and the author of the bill that caused deregulation, and is often credited as "the father of deregulation". Wilson admitted publicly that defects in the deregulation system would need fixing by "the next governor".

Part of California's deregulation process, which was promoted as a means of increasing competition, involved the partial divestiture in March 1998 of electricity generation stations by the incumbent utilities, who were still responsible for electricity distribution and were competing with independents in the retail market. A total of 40% of installed capacity - 20,164 megawatts - was sold to what were called "independent power producers." These included Mirant, Reliant, Williams, Dynegy, and AES.

Then, in 2000, wholesale prices were deregulated, but retail prices were regulated for the incumbents as part of a deal with the regulator, allowing the incumbent utilities to recover the cost of assets that would be stranded as a result of greater competition, based on the expectation that "frozen" would remain higher than wholesale prices. This assumption remained true from April 1998 through May 2000.

When electricity wholesale prices exceeded retail prices, end user demand was unaffected, but the incumbent utility companies still had to purchase power, albeit at a loss. This allowed independent producers to manipulate prices in the electricity market by withholding electricity generation, arbitraging the price between internal generation and imported (interstate) power, and causing artificial transmission constraints. This was a procedure referred to as "gaming the market." In economic terms, the incumbents who were still subject to retail price caps were faced with inelastic demand (see also: Demand response). They were unable to pass the higher prices on to consumers without approval from the public utilities commission. The affected incumbents were Southern California Edison (SCE) and Pacific Gas & Electric (PG&E). Pro-privatization advocates insist the cause of the problem was that the regulator still held too much control over the market, and true market processes were stymied — whereas opponents of deregulation simply assert that the fully regulated system had worked perfectly well for 40 years, and that deregulation created an opportunity for unscrupulous speculators to wreck a viable system.

Prior to deregulation, the electricity market in California was largely in private hands, though subject to intense regulation. The main players were PG&E, SCE, and San Diego Gas and Electric (SDG&E). Those utility companies were forced to sell their generators to non-regulated private companies such as Enron and Reliant. Ownership of certain power stations was transferred in order to increase competition in the wholesale market. In return for divesting some of their power stations the major utilities negotiated a deal to protect them from their assets being stranded. Part of this deal involved price caps for retail customers.

While the selling of power plants to private companies was labeled "deregulation", in fact Steve Peace and the California legislature expected that there would be regulation from the FERC which would prevent manipulation. The FERC's job, in theory, is to regulate and enforce Federal law which would prevent market manipulation and price manipulation of energy markets. When called upon to regulate the out-of-state privateers which were clearly manipulating the California energy market, the FERC, whose chairman was appointed by President Bush, hardly reacted at all and in fact did not take serious action against Enron, Reliant, or any other privateers. FERC's resources are in fact quite spare in comparison to their entrusted task of policing the energy market.

Market manipulation

As the FERC report concluded, market manipulation was only possible as a result of the complex market design produced by the process of partial deregulation. Manipulation strategies were known to energy traders under names such as "Fat Boy", "Death Star", "Forney Perpetual Loop", "Ricochet", "Ping Pong", "Black Widow", "Big Foot", "Red Congo", "Cong Catcher" and "Get Shorty".[4] Some of these have been extensively investigated and described in reports.

Megawatt laundering is the term, analogous to money laundering, coined to describe the process of obscuring the true origins of specific quantities of electricity being sold on the energy market. The California energy market allowed for energy companies to charge higher prices for electricity produced out-of-state. It was therefore advantageous to make it appear that electricity was being generated somewhere other than California.

Overscheduling is a term used in describing the manipulation of capacity available for the transportation of electricity along power lines. Power lines have a defined maximum load. Lines must be booked (or scheduled) in advance for transporting bought-and-sold quantities of electricity. "Overscheduling" means a deliberate reservation of more line usage than is actually required and can create the appearance that the power lines are congested. Overscheduling was one of the building blocks of a number of scams. For example, the Death Star group of scams played on the market rules which required the state to pay "congestion fees" to alleviate congestion on major power lines. "Congestion fees" were a variety of financial incentives aimed at ensuring power providers solved the congestion problem. But in the Death Star scenario, the congestion was entirely illusory and the congestion fees would therefore simply increase profits.

In a letter sent from David Fabian to Senator Boxer in 2002, it was alleged that:

"There is a single connection between northern and southern California's power grids. I heard that Enron traders purposely overbooked that line, then caused others to need it. Next, by California's free-market rules, Enron was allowed to price-gouge at will."
As a result of the actions of electricity wholesalers, Southern California Edison (SCE) and Pacific Gas & Electric (PG&E) were buying from a spot market at very high prices but were unable to raise retail rates. PG&E and SoCalEd had racked up $20 Billion in debt by Spring of 2001 (PG&E declared bankruptcy in April of that year), and their credit ratings were reduced to junk status. The financial crisis meant that PG&E and SoCalEd were unable to purchase power on behalf of their customers. The state stepped in on January 17, 2001, having the California Department of Water Resources buy power. By February 1, 2001 this stop-gap measure had been extended and would also include SDG&E. It would not be until January 1, 2003 that the utilities would resume procuring power for their customers.

Between 2000 and 2001, the combined California utilities laid off 1,300 workers, from 56,000 to 54,700, in an effort to remain solvent. San Diego had worked through the stranded asset provision and was in a position to increase prices to reflect the spot market. Small businesses were badly affected.

The involvement of Enron
One of the energy wholesalers that became notorious for "gaming the market" and reaping huge speculative profits was Enron Corporation. Enron CEO Ken Lay mocked the efforts by the California State government to thwart the practices of the energy wholesalers, saying, "In the final analysis, it doesn't matter what you crazy people in California do, because I got smart guys who can always figure out how to make money."

Enron eventually went bankrupt, and signed a $1.52 billion settlement with a group of California agencies and private utilities on July 16, 2005. However, due to its other bankruptcy obligations, only $202 million of this was expected to be paid. Ken Lay was convicted of multiple criminal charges unrelated to the California energy crisis on May 25, 2006, but he died due to a massive heart attack on July 5 of that year before he could be sentenced.

Enron traded in energy derivatives specifically exempted from regulation by the Commodity Futures Trading Commission. At a Senate hearing in January 2002, Vincent Viola, chairman of the New York Mercantile Exchange -- the largest forum for energy contract trading and clearing -- urged that Enron-like companies, which don't operate in trading "pits" and don't have the same government regulations, be given the same requirements for "compliance, disclosure, and oversight." He asked the committee to enforce "greater transparency" for the records of companies like Enron. In any case, the U.S. Supreme Court had ruled "that FERC has had the authority to negate bilateral contracts if it finds that the prices, terms or conditions of those contracts are unjust or unreasonable." Nevada was the first state to attempt recovery of such contract losses.
Consequences of wholesale price rises on the retail market

Are We ready for electricity futures ?

Electricity ,Futures Trading! – Its Shocking…..

Electricity lends itself to futures trading. It meets the three broad criteria needed for successful futures markets:

1. prices are volatile;
2. there is a large, diverse universe of buyers and sellers;
3. and the physical product is fungible.
   
   The Exchange clearinghouse provides a system of guarantees that mitigates counterparty credit risk.

Indian Scenario

In India with the imminent opening of the power sector including re doing of archaically laws and powers employed with the constitutional authorities such as the regulatory authorities(Varies ERC's) The competitive market in India would develop through structural changes in the power industry that have evolved in recent years, resulting in opportunities, price volatility, and market risk.

Barriers to the development of the Indian electricity derivatives market

The physical supply system is still encumbered by the british legacy of vertical integration.
Electricity markets are subject to Central and State regulations that are still evolving.
As a commodity, electricity has many unique aspects, including instantaneous delivery, non-storability, an interactive delivery system, and extreme price volatility.
The complexity of electricity spot markets is not conducive to common futures transactions.
There are also substantial problems with price transparency, modeling of derivative instruments, effective arbitrage, credit risk, and default risk.

How should the contract be ?

Greater market participation is a key issue for the emerging rather "under supplied" Indian power market.
In an effort to address this, the Indian exchanges in consultation with regulators has to create a contract that reduces the barriers to market entry by removing the requirement for underlying physical OTC contracts and signatory status.

The Unique Nature of Electricity as a Commodity

Storage and Real-Time Balance
The two most significant characteristics of electricity are that it cannot be easily stored and it flows at the speed of light. As a result, electricity must be produced at virtually the same instant that it is consumed, and electricity transactions must be balanced in real time on an instantaneous spot market. Electricity's real-time market contrasts sharply with the markets for other energy commodities, such as natural gas, oil, and coal, in which the underlying commodity can be stocked and dispensed over time to deal with peaks and troughs in supply and demand.

Real-time balancing requirements also complicate the market settlement process. Some electricity market transactions occur before the system constraints are fully known or the price is calculated. In extreme cases, the settlement price may be readjusted up to several months later

Electricity is typically "stored" in the form of spare generating capacity and fuel inventories at power stations. For existing plants, the "storage costs" are usually less than or equivalent to the costs of storing other energy fuels; however, the addition of new storage capacity ( i.e., power stations) can be very capital intensive. The high cost of new capacity also means that there are disincentives to building spare power capacity. Instead, existing plants must be available to respond to the strong local, weather-related, and seasonal patterns of electricity demand. Over the course of a year or even a day, electricity demand cycles through peaks and valleys corresponding to changes in heating or air conditioning loads. Two distinct diurnal electricity markets also exist, corresponding to the on-peak and off-peak load periods. Each of these markets has its own volatility characteristics and associated price risks.

Regulatory Challenges Ahead for Electricity Derivatives – Watch out No more Enron "Death Stars" The Jurisdictional Interplay Between the FMC and CERC

Financial Risk to Ratepayers. The financial risks resulting from the use of derivatives are illustrated by the number of companies that have suffered significant losses in derivative markets. Large losses can be the result of well-intentioned hedging activities or of wanton speculation. In either case, regulators must be concerned with the impact that such losses could have on ratepayers who, absent protections, might be placed at financial risk for large losses

Market Power.

The preceding paragraphs has illustrated the complexity and non-homogeneity of the electricity markets.
Amid this dynamic environment, opportunities abound for market power and gaming strategies to develop.
Controlling this potential threat to competitive markets will require substantial regulatory review, as well as physical changes in the marketplace itself. In many areas of the country, only a small number of suppliers are capable of delivering power to consumers on a particular bus bar, and each of the suppliers can easily anticipate the bids of the others. In such "thin" markets, the price of electricity can be driven by market power rather than by the marginal costs of production.
The need for overall market transparency will be critical to traders and to the market monitors.

Conservation and Demand.

One of the key tools available to regulators for reducing the volatility of electricity prices is demand-side management programs. Electricity prices are likely to be most volatile during the on-peak hours of the day and substantially more stable (and lower) during the off-peak periods.

This fact, coupled with the hockey stick shaped supply cost curve suggests that substantial reductions in volatility could be achieved through the use of market mechanisms and demand-side management programs to shift consumption to off-peak hours. State and Federal authorities have been examining a variety of possible methods for shifting consumer demand for electricity; however, one of the most direct methods—real-time pricing for large electricity consumers—remains largely untapped.

Ideal features of the contract

Baseload and Peakload contracts shoul;d be listed based on the power supply calendar and settlement cycle favoured by the industry with 12 months, 6 quarters and 4 seasons;
No requirement to be a power supplier party;
Margin offset between Electricity Futures and Natural Gas Futures/Coal Futures/Crude Oil Futures;
Each contract will be physically deliverable and will be cleared by one central counterparty,
Minimum trading size will be 10 lots;
Months, Quarters and Seasons will be listed in parallel – no cascading;
All positions will be held as months for maximum flexibility for participants;

There should ideally be 50% margin offsets between Peak and Base Load contracts;
Inter-month spreads should be made available and there will be price implication down the curve;
Outright margin rates are envisaged to be about Rs. 136 per MWh for baseload contracts and Rs. 248 per MWh for peakload contracts.
Inter-month spread rates are envisaged to be Rs. 180/- per MWh for baseload contracts and Rs. 300 per MWh for peakload contracts;
The Contracts will initially be available for trading through existing commodity exchanges and will then be rolled out to ISV solutions

The Exchanges should provide financially settled monthly futures contracts for on-peak and off-peak electricity transactions based on the daily floating price for each peak day of the month at the respective regional hub. For eg The western hub could consist of delivery points, primarily on the BSES /TATA Power transmission systems.
Additional risk management and trading opportunities should be offered through options on the monthly futures contract

The peak daily floating prices should be the weighted exponential average of say the western hub real-time locational marginal pricing for the 16 peak hours of each peak day, provided by the Utility service providers in the western hub.
Peak hours should be designated from 7:00 AM to 11:00 PM (the hour ending 0800 to the hour ending 2300) prevailing local time.
Peak days are Mondays through Fridays, excluding the Railways consumption.

Off-peak hours are from midnight to 7:00 AM (the hour ending 0100 to the hour ending 0700) and 11:00 PM to midnight (the hour ending 2400) Mondays through Fridays; also, all day Saturdays and Sundays (the hour ending 0100 to the hour ending 2400). All times are prevailing local time Locational marginal pricing is the marginal cost of supplying the next increment of power demand at a specific location on the network, taking into account the marginal cost of generation and the physical aspects of the transmission system

Quality Specification

Electric energy delivered under this contract shall be in the form of three phase current alternating at a nominal frequency as prescribed by the Central Electricity regulatory authority, and be in conformance with the specifications of the CERC.

TRANSMISSION

Except as set forth in , seller shall be required to make all transmission arrangements to deliver electric energy to central buyers, and buyer shall be required to make all transmission arrangements to receive electric energy at Central sellers

Alternative Delivery Procedure

seller or buyer may agree with the buyer or seller with which it has been matched by the Exchange Rules to make and take delivery under terms or conditions which differ from the terms and conditions prescribed by the exchange. In such a case, Clearing Members shall execute an Alternative Delivery Notice on the form prescribed by the Exchange and shall deliver a completed executed copy of such Notice to the Exchange. The delivery of an executed Alternative Delivery Notice to the Exchange shall release the Clearing Members and the Exchange from their respective obligations under the Exchange contracts.

In executing such Notice, Clearing Members shall indemnify the Exchange against any liability, cost or expense it may incur for any reason as a result of the execution, delivery or performance of such contracts or such agreement, or any breach thereof or default thereunder. Upon receipt of an executed Alternative Delivery Notice, the Exchange will return to the Clearing Members all margin monies held for the account of each with respect to the contracts involved.

Conclusion

There is an urgent impending need for a market driven ,vibrant instrument for electricity futures which would attract huge market participation automatically.
The electricity futures/options markets may provide useful information about forward prices. Futures prices represent the market participants' forecasts of what future spot prices will be. An essential feature of electricity futures contracts (for delivery at a specific location) is that as the delivery date of the futures contract approaches, the futures contract price and the spot price will converge. While the futures contract prices provide forecasts of forward spot prices, there is no assurance that the forecast will be correct, although the forecast error can be expected to diminish, the shorter the time remaining to futures contract maturity.

To start with futures price data may provide imperfect information for estimating forward contracts prices because of locational and product differences. As mentioned above, locational differences in spot price may make the spot price at one location in south India a poor proxy for the market clearing price for another location say Mumbai. Similarly, the price for a futures contract for delivery at one location may not be a good proxy for the price of a futures contract at another location. Product differences could also occur because the product specification for a tradeable futures contract may not adequately reflect the product (primarily in terms of delivery schedule) specifications for a forward contract.
The power and natural gas markets are interesting examples of the spectrum of wholesale commodity transactions. Historically, the regulation of those transactions was largely separated between CERC, which primarily regulates physical transactions, and the FMC which primarily regulates commodity derivatives transactions

Policy makers need to consider carefully whether the current regulatory structure should be modified. If they conclude that the answer is yes, they should be careful to ensure that any change in the regulatory scheme does not stifle innovation and increased efficiency in these emerging commodity derivatives markets