III. The 2000/2001 Natural Gas Crisis in Southern California

A. The "Perfect Storm" for Gas Price Spikes

SoCalGas maintains that several factors combined to create a "perfect storm" of conditions causing the border gas price spikes. Other parties acknowledge such events, but Edison argues in addition that certain SoCalGas actions contributed to the problems. We address allegations regarding SoCalGas' behavior, including its hub loan program, sales of gas to noncore customers, and management of storage, in Section V. We will examine Sempra affiliate actions and their interrelationships with SoCalGas and SDG&E in Phase I.B of this investigation and actions by other California regulated companies in Phase II and, as a result, do not discuss them in today's order, except for the brief discussion above about Sempra's ERMOC.

Natural gas prices were elevated nationwide during the subject period, but prices in the rest of the country were not as high and the spikes in spot prices were not as extreme and were of shorter duration than occurred in southern California. The record indicates that the higher gas prices nationally were due in part to increases in gas demand for power generation and also perhaps due to low U.S. storage levels, particularly in the eastern and producing regions. The American Gas Association reported in mid-2000 that national storage levels were in a 414 Bcf deficit while the west was in a surplus of 42 Bcf relative to the prior year. Concerns regarding potential injection shortfalls for the 2000/2001 winter may have contributed to the higher gas prices nationwide.

In southern California, demand for natural gas increased due to several factors, some of which elevated gas demand for electricity generation. The monthly gas demand for electricity generation in southern California rose above previous years beginning in May 2000 and stayed above average throughout the rest of the subject period. The amount of gas-fired electric generation increased due to dry hydroelectric conditions and unplanned plant outages (e.g., a May 15, 2000 electrical fire at Diablo Canyon and a San Onofre outage). In addition, SoCalGas submits that a Commission change in the prices paid to Qualifying Facility (QF) generators led to a reduction in their electricity output. Edison stopped payment to QFs in its service territory between December 2000 and March 2001, which increased demand for gas-fired electric generation. In addition, environmental limits in southern California, e.g., for NOx emissions, resulted in some gas-fired generation being shifted to less efficient units.

Colder than normal winter weather in portions of the 2000/2001 winter produced above-average heating loads.

Noncore customers in southern California filled only a fraction of their storage prior to the winter of 2000/2001, and SoCalGas' core storage levels were also low, as discussed in more detail in Section V.B, so there was more reliance on flowing supplies during the winter. While SoCalGas points to low noncore storage as an external factor putting pressure on natural gas prices, Edison asserts that the storage behavior of such customers in reliance on the backwardated market was influenced by lack of public information regarding SoCalGas' winter hub loan repayments forcing reliance on flowing supplies for core needs typically met by storage withdrawals.

In addition to demand increases, several factors reducing the supply of gas to meet those needs put upward pressure on gas prices.

Deliveries on the El Paso pipeline were significantly less than nominated amounts throughout the subject period. From November 2000 through March 2001, EPNG flowed an average of 2,594 MMcfd to California, only 79% of its certificated capacity to California. SoCalGas reports that border purchases could have been reduced by 50 Bcf during the subject period if EPNG had delivered SoCalGas' nominated volumes. The reductions have been attributed to several problems, which are addressed in turn below.

On August 19, 2000, a rupture occurred on the El Paso pipeline at Carlsbad, New Mexico. The immediate effect of the rupture was a decrease in flowing supplies on El Paso's southern system of more than 700 MMcfd, with deliveries into southern California reduced by about 450 MMcfd. Most of this capacity was restored within a few weeks, but the El Paso pipeline capacity was reduced by 210 MMcfd for the remainder of the subject period.

Unlike most pipelines, El Paso did not assign shippers firm transportation capacity rights at specific receipt points. Rather, shippers contracted for firm transportation service with system-wide basin access. El Paso used a pro rata allocation methodology when valid nominations at a specific point exceeded meter capacity. A FERC order dated May 31, 2002 found that El Paso's method of capacity allocation was unjust and unreasonable. FERC required, among other things, that El Paso assign specific receipt point rights.

EPNG provided preferential scheduling treatment for shippers east of California with full requirements contracts. The east-of-California shippers experienced unusually high demand and as a result limited gas supplies reaching California. As we showed in our FERC complaint, EPNG anticipated the tightening of its system, including the growth in demand east of California, but failed to take steps to rectify problems on its system.

Throughout spring and summer 2000 and other periods including the first half of January 2001, EPME withheld capacity and limited its border sales by failing to nominate significant portions of its capacity. In addition, throughout spring 2000 EPME posted capacity for release at prices that were well above competitive market levels, resulting in no releases.

The FERC ALJ's September 23, 2002 Initial Decision in our complaint found that EPNG had withheld capacity based on a variety of operational issues. El Paso filed a settlement on June 4, 2001 to resolve the complaint and all related litigation against El Paso and EPME, and there was no final FERC decision on the allegations raised in the complaint. SoCalGas takes the position that, given the limited evidence regarding El Paso in this proceeding, it is not possible to determine whether alleged El Paso withholding of capacity during the subject period affected conditions in California.

Edison presented evidence regarding Enron Corp. (Enron) activities to manipulate California's natural gas market through its dominant trading platform position. Enron used its electronic trading platform EnronOnline (EOL) to trade natural gas at SoCal-Topock and, beginning in March 2001, at SoCal-Ehrenberg. Information gleaned through EOL regarding the buying and selling patterns of its competitors enabled Enron "to better assess the risk/reward of held or planned sales." Edison describes how EOL made it possible for Enron to manipulate daily gas prices in southern California. SoCalGas also describes EOL's dominance and its effect on SoCalGas-Topock prices. Enron gas price manipulations had broader effects, since the EOL spot price was used as a benchmark price for other border gas transactions. In addition, Enron manipulation carried over to the forward basis markets, as recognized in a contemporaneous paper by Gas Acquisition's Energy Risk Manager (Ex. 90, Att. 1-1, see also Ex. 90, Att. A-5).

Exxon terminated its contract for intrastate delivery of 60 MMcfd to SoCalGas from Pacific Offshore Pipeline Company (POPCO) effective October 1, 2000. SoCalGas reports that termination of the POPCO contract forced SoCalGas to purchase an additional 11 Bcf of gas in the border market from October 2000 through March 2001.

It has been alleged that Reliant's trading behavior affected natural gas prices. A FERC staff analysis indicated that Reliant's trading behavior had substantial impacts on natural gas prices,² but SoCalGas disputes the estimated effect. Reliant purchased spot gas for LADWP to supply last minute power to the ISO and relied on supply from EOL. Edison describes a netting arrangement between Enron and Reliant that provided financial benefits to Reliant and partially explained its reliance on EOL. SoCalGas described that on several occasions Reliant turned down more competitive SoCalGas offers in favor of EOL.

SoCalGas also asserts that a number of regulatory and structural problems, including failure to raise retail electric rates, contributed to the gas price run-up at the southern California border in 2000/2001.

The parties disagree regarding quantification of the impacts of the identified demand and supply factors in southern California during the subject period. SoCalGas submits that the shocks increased demand for border gas by 322.7 Bcf and decreased supply by 106.4 Bcf, for a total of 429.1 Bcf of supply and demand shocks during the subject period. The following table summarizes SoCalGas estimates of supply and demand shocks during the subject period.

Table 1

SoCalGas Estimates of Impacts of Factors

Affecting Gas Supply and Demand in Southern California

During the Subject Period

(Bcf)

Demand shocks:

Increased electricity generator demand:

March - October 2000 85.4

November - March 94.0

April - May 2001 24.3

Cold weather 38.0

Other 81.0

Supply shocks:

El Paso Carlsbad rupture 23.6

El Paso east-of-California demand 82.8

TOTAL demand and supply impacts 429.1

Edison disputes SoCalGas' quantification, including SoCalGas' use of the 1999 BCAP forecast and the 1999 electric generator demand as baselines for measuring the impacts. Edison submits that the 1999 BCAP is an inappropriate baseline since the SoCalGas system is designed to handle colder temperatures than what is reflected in the BCAP average temperature forecast and that SoCalGas has not explained why 1999 would be the appropriate baseline for measuring increases in gas demand for electric generation.

SoCalGas uses its estimate of demand and supply shocks to argue that any alleged shortcomings in its management of storage pale by comparison to these broader impacts. Edison counters that inadequate storage affects, at most, a 5-month withdrawal period and that the effect can be concentrated in shorter periods. SoCalGas estimated that 117 Bcf of the claimed demand shocks occurred between November 2000 and March 2001 and that 10 Bcf of the demand impacts occurred in December. Edison points out that this 10 Bcf is very close to the amount of hub loan repayments SoCalGas received in December 2000, and is less than the 13.6 Bcf storage shortfall that Edison claims for October 31, 2000. Edison concludes that SoCalGas' own demand shock estimate is of the same magnitude as the loan repayments and storage shortfall.

B. Effects on Southern California Natural Gas System and Prices

In 2000 and 2001, gas prices were high nationwide, but reached unprecedented levels at the California border. Gas prices at the California border rose throughout 2000, with Gas Daily average monthly border prices increasing from $2.42 per MMBtu in January 2000, to $4.63 in June 2000, to $10.00 in November, and to a high of $25.08 per MMBtu in December 2000. Border prices reached $60 per MMBtu in the daily spot market in December 2000.

The parties disagree regarding the cause of the increased bidweek and spot prices at the California border during the subject period. SoCalGas asserts that scarcity rents due to interstate capacity constraints and scheduling breakdowns, in conjunction with demand shocks in California, explain the wide basis differentials. Edison's opinion is that, while interstate capacity constraints and scheduling problems were factors, SoCalGas' analysis does not take into account other factors such as EPME capacity withholding or the fact that stored gas could be (but in Edison's view was not) used to moderate prices when interstate capacity was constrained.

A question central to our investigation is the extent to which the natural gas system was or should have been able to absorb the confluence of supply and demand conditions without constraints sufficient to raise southern California gas prices above prices in other areas. The total firm delivery capability into California from the southwest pipelines during the subject period was 4,040 MMcfd. However, basis differentials were routinely elevated above maximum transportation rates when total flow was in the 3,200 MMcfd range, indicating other problems with the supply of gas.

Border/basin basis differentials provide the best indication of the extent to which the southern California system was constrained during the subject period. Whenever border prices were above basin prices plus the regulated maximum cost of transportation, that is an indication that the total gas supplies being made available in southern California-whether transported by SoCalGas or noncore capacity holders via interstate pipelines, produced in-state, or withdrawn from storage-were less than the demand at a price equal to the border price plus the maximum cost of transportation.

The record establishes that monthly average border/basin basis differentials were below the EPNG maximum tariff transportation rate until June 2000 for the San Juan basin and until July 2000 for the Permian basin. The border/San Juan basis differential was above the EPNG maximum tariff rate every day from June 9, 2000 through the remainder of the year. While monthly average basis differentials for the Permian basin were above the EPNG maximum tariff rate from July through the remainder of 2000, the daily basis differential fell below the maximum tariff rate for portions of July, August, September, and October, indicating periods when capacity was available on related pipelines.

We agree with SoCalGas that it may not be possible to provide a definitive explanation of price movements on specific days. Qualitatively, a number of events drove demand up and reduced the availability of gas in southern California. Under already tight market conditions, day-to-day events or buyer reactions to uncertainty about upcoming days could cause price spikes in the daily market. Although daily prices are reported, total daily volumes transacted at those prices are not. Lack of this information complicates efforts to explain any given day's price events.

While we are not able to quantify the effect of each individual supply or demand factor on southern California gas prices, we observe correlations at times between price movements and contemporaneous events. Without always knowing why, it is clear that there were times during the subject period when any increase in inelastic demand or decrease in supply (flowing, in-state production, or storage withdrawal) could have a disproportionate and at times exponential effect on price (spot and/or bidweek depending on the timing and duration of the factor).³

C. Relationship between Gas and Electricity Prices

Edison asserts that high and volatile border gas prices translated into high and volatile electricity prices. SoCalGas argues that the cause-and-effect relationship is not clear and that, contrary to Edison's view, electricity demand that was inelastic with respect to price tended to drive gas prices up.

During the subject period, bids from natural gas-fired generators tended to set the price of electricity during most hours, and always on peak. While electricity price spikes in summer 2000 were not accompanied by spikes in natural gas prices, Edison maintains that the most severe of the gas price spikes in the winter of 2000/2001 were translated directly into price spikes in the electricity market, particularly during December 2000.

It would be simplistic to say either that high gas prices caused high electricity prices, or vice versa. Instead, electricity generation demand contributed to higher gas prices, which reinforced and contributed to high electricity prices. The gas and electricity markets (flawed though they may have been) jointly determined the market clearing prices and amounts of both border gas and gas-fired electric generation. A host of market factors, including increased and largely inelastic demand for gas-fired electric generation, caused the supply and demand curves for both electricity and natural gas to intersect at points with higher electricity prices and higher gas prices relative to what market clearing prices would have been absent the adverse conditions.

That being said, it is possible and reasonable to focus on the effect of discretionary actions on the electricity and gas markets. At times when the southern California gas system was stressed, any factor that increased the gas supply/demand imbalance, including SoCalGas actions as discussed in Section V, would increase border gas prices and volatility. This in turn would increase electricity prices and volatility. Thus, we agree with Edison that SoCalGas' choices to enter into hub loans with winter paybacks and to enter the winter season with minimal physical storage increased electricity prices for at least some portion of the winter. But the evidence does not allow us to quantify the cost to electric customers.