Posted on 03/26/2003 1:26:04 PM PST by snopercod
Statement of Chairman Wood, March 26, 2003 [pdf]
Commission Readies Tough Action, March 26, 2003 [pdf]
Commission Expects Jump In California Energy Refunds, March 26, 2003 [pdf]
Show Cause Orders Address Manipulation, March 26, 2003
Staff Report on Western Markets Investigation
Findings at a Glance, March 26, 2003 [pdf]
Awright! I takes the danged blame!! I done it!!!
I still wanna know WHY the governMental entity known as MWA who wuz the biggest gouger ain't bein named and prosecuted as hard as these private sector entities?
Will sumbudy pleese 'splain THAT ta me?
Sorry Robert357, I wuz tryin ta rememer yer scream name when I wuz Freep mailin everbudy urlier taday an mist ya.
I hope Ernust the beach boy is ok. I sent him 2 privut pings. I just messed up tryin ta ping Dog Gone an typed Dong Gone by assident, sorta like yer mammery, Mr. cod. (grimace)
In their opinion, the system not only invited and enhanced the gaming but masked the gaming trail.
California further compounded its error by initially imposing the expense of its complicity upon the only innocent party, the rate payer.
The commission recommmends that the gamers refund their artificial profit, not to the State of California, but to the rate payers. Not to the general fund, but directly to rate payers, in the form of rate reductions.
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Flawed Market Rules and
Regulatory Policies
Magnified Adverse
Conditions
California’s then-prevailing regulatory scheme forbade much forward contracting by the state’s three largest investor-owned utilities (IOUs). The three California IOUs were required to purchase power through the PX with little or no ability to purchase through forward contracts, exposing the utilities to the volatility of the spot market without the ability to mitigate that volatility. Even the generation that was not divested by the three California IOUs could not be used directly to self-supply their retail load. Under the California market design, this retained generation had to be bid into the spot market. The California IOUs were required to buy the output of their resources to supply their retail customers. In its December 15, 2000 Order, the Commission eliminated this aspect of the California market design that required that the IOUs must sell all of their generation into, and buy all of their energy from, the California PX.19
A second market design flaw was the lack of demand responsiveness. This flaw was exacerbated by a retail rate freeze that insulated residential customers from high wholesale prices, thereby thwarting the ability of price signals to shape and limit demand.
A third major flaw was the underscheduling of load by the three California IOUs. Economic incentives to underschedule tended to increase during high demand periods, which created operational and reliability problems for the Cal ISO and required it to obtain out-of market energy at high prices. In its December 15, 2000 Order, the Commission established penalties for underscheduling load.
As a result of the conditions and market rules noted above, hourly prices in the PX reached as high as $750/MWh twice in May and eight times in June; average prices were $47/MWh in May, $120/MWh in June, $106/MWh in July, and $166/MWh in August.20 These prices were vastly higher than year-ago prices. For example, the monthly average unconstrained market-clearing price for May 2000 in the PX’s day-ahead market represented a 100-percent increase over May 1999.21
Finally, emission compliance costs also increased markedly in the summer of 2000. The cost of credits for complying with nitrous oxide standards rose from approximately $6 per pound in May 2000 to $35 per pound in August. Because a combined-cycle gas generator typically emits from 1 to 1.5 pounds of nitrous oxide per MWh, these increased costs were significant.
Gas market rules were also flawed. In particular, the CPUC’s rules did not require that storage facilities be filled during the nonpeak season, as discussed in greater detail below. The lack of stored gas in California contributed to higher border prices in the winter of 2000– 2001.
19 San Diego Gas & Electric Company v. Sellers of Energy and Ancillary Services, 93 FERC ¶ 61,294 (2000).
20 San Diego, 93 FERC at 61,353 (citing an ISO source); Staff Report to the Federal Energy Regulatory Commission on Western Markets and the Causes of Summer 2000 Price Abnormalities (2000 Western Markets Staff Report), p. 5-1.
21San Diego, 93 FERC at 61,353 (citing a PX source).
Transportation Constraints
and Spot Market
Dysfunctions Contributed
Significantly to Higher Spot
Market Natural Gas Prices at
the California Border
The disparity in prices between the primary production basins that serve southern California, Permian and San Juan, and the spot market price at Topock, Arizona, near the Southern California Border, suggests that natural gas transportation between these points was constrained.
Three major interstate pipelines serve southern California. Table I-2 indicates the limited choices available to gas purchasers for purchasing gas for resale or consumption in southern California. Table I-2. Interstate Pipeline Design Capacity to California
Pipeline Design Capacity to California (MMcf/d)
El Paso Natural Gas Company 3,290Transwestern Pipeline Company 1.090
Kern River 700
Total Design Capacity 5,080
A rupture occurred on El Paso Natural Gas Company’s (El Paso’s) pipeline in southeast New Mexico in August 2001; capacity was immediately reduced by approximately 1 Bcf/d for about 2 weeks following the rupture.22 During the winter of 2000–2001, El Paso operated its pipelines immediately upstream and downstream of the rupture site at reduced pressures pursuant to an Order of the U.S. Department of Transportation.23 Operation at reduced pressure caused a reduction in El Paso’s capacity in the amount of 270 MMcf/d during this time.24 The loss of capacity was “a major shock to supplies of natural gas in the Western Region, particularly in California, Arizona, and New Mexico.”25 The amount of gas needed to serve 1 million homes is approximately 270 MMcf/d.
High spot prices in southern California were reflected in the willingness of some shippers to pay more than the maximum tariff rate for transportation on pipelines serving southern California.26 The following table provides a barometer of pipeline capacity scarcity. It shows that shippers were able to release capacity on El Paso’s and Transwestern Pipeline Company’s (Transwestern’s) systems above the maximum tariff rate.27
Table I-3. Capacity Releases Above the Maximum Tariff Rate Month Pipeline Amount Released Above Maximum Rate (MMBtu/d)28
November 2000 El Paso 33,800December 2000 El Paso 7,000
January 2001 El Paso 12,500
January 2001 Transwestern 7,766
February 2001 El Paso 19,269
March 2001 El Paso 34,566
As the Commission pointed out in an order addressing the data in Table I-3, the volumes of released capacity above the maximum tariff were not large relative to the total capacity serving California.29 Nonetheless, the data provide an indication of the persistence of capacity scarcity because they show that some shippers were willing to pay above-tariff prices to avoid paying high bundled prices at the California border. The volumes of released capacity may have been relatively low, not because a market for capacity above the maximum tariff rate did not exist, but because shippers holding capacity wanted to use it themselves to transport gas to the California border rather than release that capacity to other shippers.
In short, demand for interstate pipeline capacity and capacity from the border into California exceeded supply. Border prices would not have exceeded production basin prices as dramatically as they did had there been sufficient transportation capacity to meet all of the gas demanded by customers in southern California.
Low storage levels contributed to higher prices and greater volatility in the gas market in southern California. If the CPUC rules required that storage facilities be filled, gas supplies would have been increased during the winter of 2000–2001. Shippers use storage during peak periods to supplement interstate pipeline deliveries. Storage levels were historically low approaching and during the winter of 2000– 2001. California began the 2000–2001 winter season with 152 Bcf in storage, which was 34 Bcf below the 5-year (1995–1999) average.30 By mid-February 2001, California’s working gas inventories were estimated at less than 70 Bcf, as compared to the 1995–1999 average of 100 Bcf for the end of March.31 Storage levels were low for several reasons. First, the Carlsbad rupture caused shippers to draw down storage inventories in August that would otherwise have been available for the winter heating season.32 Second, natural gas prices above the historical average in southern California in the summer of 2000 caused market participants to reduce the amount of gas they put in storage. These market participants believed that gas prices would moderate, permitting them to fill storage later in the season or purchase natural gas on the spot market at lower prices.33
Additional factors, including higher gas-fired generation output due to low hydropower availability, nuclear plant outages in November 2000, and unusually cold temperatures in November 2000, contributed to the drawdown of storage serving southern California customers.34
Many of the market participants that sold natural gas at the Southern California Border during the winter of 2000–2001 were trading companies that engaged in major business activities outside of California. However, handwritten daily transaction sheets that Southern California Gas Company (SoCalGas), a local distribution company,35 provides each month to the CPUC indicate that SoCalGas profited significantly from border sales at elevated prices. These records show, for example, that for the flow date December 12, 2000, a date on which natural gas prices at the California border were extraordinarily high, SoCalGas purchased gas for approximately $11 from production area sources and sold gas at Topock for as much as $65. For the flow dates February 10 through 12, 2001, the days preceding a run-up of border prices, SoCalGas purchased gas at an average price of less than $14. From February 14 through 16, when gas prices were spiking, SoCalGas sold gas at an average price that exceeded $30. SoCalGas’ ability to store gas suggests the potential for substantial earnings stemming from these transactions. Under a performance-based rates program authorized by the CPUC, a portion of profits derived from trading activity would have been realized by shareholders of SoCalGas’ parent company. For the period October 2000 through March 2001, SoCalGas purchased approximately 56,816,000 MMcf for a total of approximately $626,900,000, or $11.04/MMcf, and sold at wholesale 12,856,000 MMcf for $213,640,000, or $16.60/MMcf. These data show that SoCalGas benefited from higher bundled prices and general volatility during this period. Taken as a whole, SoCalGas’ trading activity indicates that profiteers included at least one market participant subject to California’s regulatory oversight.
Staff concludes that transportation constraints and spot market dysfunctions contributed significantly to high spot gas prices and that this justifies the substitution of a new methodology for calculating electric prices for this period of market dysfunction that the Staff proposed in Chapter IV.
22. “Status of Natural Gas Pipeline System Capacity Entering the 2000–2001 Heating Season,” Energy Information Administration (October 2000), p. xviii (Internet pagination).
23. See Corrective Action Order, issued by the Research and Special Programs Administration of the U.S. Department of Transportation, CPF No. 420001004-H (August 23, 2000).
24. El Paso press release, October 23, 2002.
25. “Status of Natural Gas Pipeline System Capacity Entering the 2000–2001 Heating Season,” Energy Information Administration (October 2000), p. xviii (Internet pagination).
26. In Order No. 637, the Commission temporarily removed the rate ceiling for shortterm capacity release transactions. The Commission explained that “[d]uring peak demand periods, when capacity is at a premium, the need to provide shippers with the greatest number of potential options and the most efficient competitive marketplace is crucial. Shippers that most need capacity during periods of scarce supply need a market that can efficiently respond to their demands and provide the capacity they need.” FERC Stats. & Regs, July 1996 – December 2000 ¶ 31,091 at 31,270 (2000). While this provision of Order No. 637 expired on September 30, 2002, 18 C.F.R. § 284.8(i) (2002), it was effective during the winter of 2000–2001.
27. San Diego Gas & Electric Company, 95 FERC ¶ 61,264 (2001) (Appendix). Chapter I
28. An MMBtu is roughly equal to an Mcf.
29. San Diego, 95 FERC at 61,934-935.
30. “U.S. Natural Gas Markets: Recent Trends and Prospects for the Future,” Energy Information Agency, May 2001, p. 22.
31. “U.S. Natural Gas Markets: Recent Trends and Prospects for the Future,” Energy Information Agency, May 2001, p. 23.
32. “U.S. Natural Gas Markets: Recent Trends and Prospects for the Future,” Energy Information Agency, May 2001, p. 14.
33. This is suggested in part by data for nationwide futures prices for natural gas. “Natural Gas Winter Outlook 2000–2001,” Energy Information Administration, Natural Gas Monthly, October 2000, p. xxiii.
34. “U.S. Natural Gas Markets: Recent Trends and Prospects for the Future,” Energy Information Agency, May 2001, p. 23. Staff Report to the Federal Energy Regulatory Commission on Northwest Power Markets in November and December 2000, February 1, 2001, pp. 21-22.
35. SoCalGas, whose facilities are located solely within the state of California, is a socalled “Hinshaw” pipeline that is exempt from the Commission’s jurisdiction under section 1(c) of the Natural Gas Act, 15 U.S.C. 717(c) (1994).
FERC report blasts roles energy companies played-Enron just one company in California crisis
Rather it was joined by dozens of other companies that either generated power or marketed it, including some of California's largest utilities and many city-owned utilities."This is not the activity that I associate with good old American commerce, not even tough competition on the edge," ...That's contrary to your (paraphrased) 'sounds like good business practice' idiocy."This is not the activity that I associate with good old American commerce, not even tough competition on the edge," FERC Chairman Pat Wood III said. "I'm pretty disappointed with this kind of activity, that this happened in our markets."
As I accurately stated: "Vindicated once again".
At the end of the article it says...."This was a very ugly situation in the West, one where I don't think anyone was on the side of the angels," said Commissioner Brownell.
Unfortunately, the litigation will continue and the attorneys will be the significant beneficiaries of any real money that changes hands.
I ask again. Have you read the report?
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