VIII. Assignment of Proceeding
Loretta M. Lynch is the Assigned Commissioner and Charlotte F. TerKeurst is the assigned ALJ in this proceeding.
1. 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.
2. In southern California, demand for natural gas increased due to several factors, some of which elevated gas demand for electricity generation.
3. Noncore gas customers in southern California filled only a fraction of their storage prior to the winter of 2000/2001.
4. In addition to demand increases, several factors reducing the supply of gas to meet those needs put upward pressure on gas prices in southern California during the subject period.
5. Border/basin gas price differentials provide the best indication of the extent to which the southern California gas system was constrained at the border during the subject period.
6. Monthly average border/basin basis differentials rose above the EPNG maximum tariff rate, indicating southern California gas system constraints, commencing in June 2000 for the San Juan basin and July 2000 for the Permian basin.
7. There were times during the subject period when any increase in inelastic demand or decrease in supply (flowing from out-of-state producing basins, in-state production, or storage withdrawal) could have a disproportionate and at times exponential effect on border prices.
8. During the subject period, increased electricity generation demand contributed to higher gas prices, which reinforced and contributed to high electricity prices.
9. 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.
10. During periods of system constraints in the subject period, SoCalGas had the ability to move the price of gas above the competitive level by restricting the supply of gas through its hub services and storage activities.
11. SoCalGas understood during the summer and fall of 2000 that actions it took that increased winter reliance on flowing gas and decreased the availability of stored gas would contribute to market constraints and put upward pressure on border prices.
12. During the subject period, SoCalGas correlated California southwest and east-of-California gas flows with daily basis differentials and compared the results to forecasted California southwest and east-of-California flows, thus gaining insight into what basis differentials might be during the 2000/2001 winter.
13. SoCalGas tracked the electricity market and understood during the summer and fall of 2000 that gas demand for electricity generation was high and would remain high through the winter.
14. SoCalGas' forecasts of gas demand and monthly flows into California, combined with its knowledge about current market conditions, provided SoCalGas with knowledge when it was making its hub loans that there was a high likelihood of winter price spikes and congestion and that winter hub loan repayments would push prices even higher. To the extent that SoCalGas had already scheduled or was planning December hub loan repayments larger than those reflected in the forecasts, it still would have been aware of their impacts on December flows.
15. A reasonable inference is that SoCalGas expected throughout the summer and fall of 2000, based on its own forecasts, that average basis differentials would be higher in the 2000/2001 winter than the forward markets were indicating and would have known that there was a high likelihood of daily price spikes.
16. A reasonable inference is that SoCalGas knew throughout the summer and fall of 2000, based on its own forecasts, that the addition of incremental flowing supplies, e.g., in the form of hub loan repayments, would have an atypically large effect on gas prices at the California border.
17. SoCalGas planned to profit from volatility in the gas market during the subject period.
18. Border gas prices were volatile throughout the 2000/2001 winter, with spikes occurring each month.
19. SoCalGas made after-market (spot) gas sales every month during the 2000/2001 winter, even though it was drawing down core storage to historic lows.
20. SoCalGas was a net seller in the spot market every day when there was a price spike.
21. Beginning in June 2000, SoCalGas entered into a hub loan program with unprecedented levels of winter repayments with, for example, a net flow of 7.9 Bcf into the hub (loan repayments net of parks) in December 2000.
22. In five of the six years between 1994 and 1999 the peak demand month for SoCalGas was December.
23. Between September and November of 2000, SoCalGas continued to enter into hub loans with winter repayments, increasing total December loan repayments from about 6 Bcf at the time of the Carlsbad rupture to 8.9 Bcf at the end of November.
24. SoCalGas reducing its planned storage injections as basis differentials were increasing during the summer of 2000.
25. SoCalGas entered the 2000/2001 winter storage withdrawal season with 53.1 Bcf of core gas in its four operating storage fields, the lowest level of gas in core storage since the GCIM has been in effect and 11.9 Bcf less than the bottom of the Commission-established target range of 70 Bcf plus or minus 5 Bcf.
26. It is not reasonable to include parked gas in assessing SoCalGas' compliance with the Commission-established storage targets or in assessing core storage adequacy and reliability.
27. SoCalGas did not request, and the Commission did not approve in D.97-11-070, the use of a purchased gas storage target.
28. SoCalGas inappropriately switched to a purchased gas storage inventory target without Commission authorization.
29. If SoCalGas had sold less gas to noncore customers during the injection period or had loaned less gas for winter repayment, it could have filled its core storage before the beginning of the 2000/2001 winter withdrawal season.
30. In November 2000, with historically low storage levels for the month, SoCalGas purchased and sold 3.3 Bcf of after-market gas rather than using it to meet core gas needs and conserve stored gas supplies.
31. The timing of gas flows into and out of the hub can affect border gas prices and noncore customers would have benefited from the knowledge that SoCalGas had scheduled loan repayments in winter periods, especially December.
32. SoCalGas took short financial positions at the southern California border through August 2000 but switched to long positions starting on September 1, 2000.
33. SoCalGas emphasizes its reliance on financial hedges during the subject period, undertaken counter to market expectations as reflected in forward prices, but argues inexplicably that its storage and hub loan decisions should be assessed solely by reference to futures prices at the time they were undertaken.
34. SoCalGas' hub loan program commenced in June 2000 and its after-market sales commencing in June 2000 deferred the acquisition of gas needed for core customers' winter use, thus requiring more expensive replacement purchases later in the yearly cycle, an outcome detrimental to core customers but with no shareholder consequences under the current GCIM structure.
35. Because SoCalGas' actions contributed to bidweek border price increases during the 2000/2001 winter, the GCIM benchmark was set higher and the savings calculation for border purchases is not an accurate reflection of whether SoCalGas saved money on border gas purchases.
36. While SoCalgas' core customers were protected from the higher cost of winter gas needed for loan repayments, they were exposed to the unhedged portion of the cost of SoCalGas' border purchases.
37. To determine the true impact of SoCalGas' actions on core customers, GCIM customer "benefits" would have to be netted against increases in core costs. While we cannot establish the impact definitively, it is clear that the net effect was an increase in core customer bills.
38. SoCalGas' hub loan program and its decision to not fill core storage before commencement of the winter withdrawal period, combined with after-market sales during the winter withdrawal period, constrained market supplies during the 2000/2001 winter and increased winter gas prices at the California border.
39. In December 2000, net hub loan repayments and SoCalGas' own border purchases constituted 30% of core burn and over 11 % of total SoCalGas sendout that month. With the tight supply/demand conditions, this reliance on flowing gas supplies was sufficient to affect gas prices at the California border.
40. The fact that SoCalGas did not have the storage reserves to weather one month of unexpectedly high withdrawals (November) and respond adequately to tight conditions in December confirms that SoCalGas' physical storage was insufficient entering the winter season.
41. SoCalGas' scheduling significant volumes of winter hub loan repayments, which caused increased reliance on gas supplies flowing across the California border, when it had information that the winter market would be constrained effectively withheld gas supply during peak winter months and increased gas prices and volatility at the California border.
42. SoCalGas' failure to file core storage adequately during the 2000 injection season when it had information that the winter market would be constrained effectively withheld gas supply during peak winter months and increased gas prices and volatility at the California border.
43. SoCalGas' choice not to withdraw the core's working gas in the Montebello storage field effectively withheld gas supply during constrained system conditions and increased gas prices and volatility at the California border.
44. SoCalGas sold gas to noncore customers during each of the border spot gas price spikes, thus profiting from price increases caused by its actions.
45. SoCalGas exercised market power between June 2000 and March 2001 in that it increased border gas prices by actions that effectively withheld gas supplies and then profited from those price increases.
46. SoCalGas' GCIM profits between June 2000 and March 2001 were the result of its exercise of market power.
47. Shareholder receipt of SoCalGas' GCIM profits between June 2000 and March 2001 was not reasonable.
48. It is reasonable to require SoCalGas to refund to core ratepayers all profits that shareholders received due to operation of the GCIM mechanism between June 1, 2000 and March 31, 2001, with interest. A credit to SoCalGas' Purchased Gas Account is a reasonable mechanism for accomplishing this refund.
49. In requiring that SoCalGas refund the specified GCIM profits to ratepayers, we do not address potential culpability for harm to market participants other than core gas customers.
50. Local distribution companies, as regulated entities providing service to core customers, should refrain from market speculation through financial transactions.
51. SoCalGas' establishment of a goal for GCIM profits due to financial transactions, coupled with the manner in which this goal was presented at an April 2000 planning conference, supports a reasonable inference that SoCalGas expected its Gas Acquisition employees to engage in hedging activities other than "bona fide" hedging to protect against price increases.
52. SoCalGas took some of its financial positions during the subject period for speculative purposes.
53. During the subject period, SoCalGas entered into some of its California border hedges with an intent to profit from the tight winter conditions occurring, in part, due to SoCalGas own hub loan and storage activities.
54. The fact that SoCalGas undertook California border hedges with an intent to profit from the tight winter conditions supports our finding that SoCalGas exerted market power between June 2000 and March 2001.
55. The GCIM measures Gas Acquisition's purchases against basin and border monthly benchmark gas commodity costs, calculated using the bidweek monthly price for the basin or border, respectively, that is established during the final days of the preceding month.
56. The GCIM benchmark changes depending on the relative amounts and sources from which SoCalGas chooses to procure in any given month.
57. Gas Acquisition planned to achieve GCIM Year 7 earnings through sales in the daily market (after-market activity) in the amount of $18 million, hub transactions of $8.5 million, and trading in natural gas financial positions.
58. At the end of GCIM Year 7, SoCalGas reported savings relative to its benchmark of $223.6 million.
59. PG&E's core procurement department does not provide hub services, and revenues from hub services do not flow through the PG&E CPIM. PG&E also does not include system sales to others as part of the CPIM.
60. The CPIM benchmarks are calculated assuming a sequencing of supplies that take into account the various transmission and storage assets available to PG&E's core, and storage is integrated fully into the sequencing methodology.
61. Because PG&E's CPIM is tied to specific, pre-determined purchasing sources and storage fill obligations, its opportunities for after-market and other gas sales are much more limited than are SoCalGas' opportunities.
62. The two most significant differences between PG&E's CPIM and SoCalGas' GCIM are that (1) the GCIM benchmark is calculated using SoCalGas' actual monthly net purchase quantities, in contrast to the CPIM benchmark which is calculated using purchase quantities independent of actual purchase decisions, and (2) revenues from hub services and noncore gas sales are included in the GCIM but not in the CPIM.
63. Using actual net purchase quantities in the GCIM benchmark creates conflicting incentives for SoCalGas because the utility can shift purchases between months, adjusting storage injection and withdrawal schedules accordingly, with no GCIM impact even if these choices have a large impact on core gas cost.
64. Using actual net purchase quantities in the benchmark, in combination with other GCIM attributes, creates opportunities and incentives for generating significant incremental GCIM rewards through actions that may not reduce, and may actually increase, gas costs to core customers.
65. The GCIM structure provides incentives for SoCalGas to engage in after-market (i.e., daily) sales and purchases whenever there is an opportunity for short-term profits.
66. The GCIM provides an incentive, whenever spot prices are high, for SoCalGas to sell gas that had been purchased previously for core customers while correspondingly reducing storage injections or increasing storage withdrawals.
67. Hub loans may increase core gas costs if speculatively purchased gas used for hub loans costs more than the gas that would be purchased otherwise in synch with core customer needs.
68. The GCIM provides no explicit tools or incentives for engaging in financial transactions or forward purchases.
69. Risk management is not the same as low cost gas procurement.
70. The Gas Acquisition group defined low cost gas relative to index prices, and not necessarily to procuring the lowest cost gas possible.
71. The vast majority of SoCalGas' GCIM profits for the subject period were not due to exceptionally good performance in buying low cost gas, but rather to after-market sales, hub transactions, and financial transactions.
72. Numerous changes have taken place in California's natural gas market since 2000, including important modifications to the GCIM in D.02-06-023, significant capacity additions in southern California, increased assurance of nominated deliveries over the El Paso system into southern California, establishment of a pre-approval process for more diversified gas utility portfolios in D.04-09-022, and the imminent implementation of a system of firm access rights on the SoCalGas system.
73. Because the CPIM is structured so that benefits can only accrue to shareholders if commensurate benefits are generated for ratepayers, the Commission's need to monitor PG&E's conduct, to determine whether PG&E is seeking low gas prices to achieve benefits under the CPIM, is greatly reduced.
74. A continued expanded role of the GCIM is inappropriate in light of its effect on the California natural gas market during the subject period, the changes that have occurred in California's natural gas market during and after the subject period, and the further changes we anticipate unfolding in the near future.
75. Many of the changes that have taken place since 2000 have reduced or eliminated the differences ORA and SoCalGas have identified between the SoCalGas and PG&E systems that previously may have necessitated the differences in their respective procurement incentive mechanisms.
76. Profits from hub services and sales of gas to noncore customers were more of a motivating factor than procurement of low cost gas for core ratepayers during the subject period.
77. SoCalGas' GCIM currently allows the Gas Acquisition department the flexibility to delve into areas that require much more monitoring than the CPIM.
78. It is reasonable to modify SoCalGas' GCIM to improve incentives to make lowest-cost gas procurement the primary goal of the GCIM.
79. SoCalGas' GCIM should align shareholder interests with ratepayer interests to ensure that least-cost, stable and reliable prices result from the procurement process itself; it should not rely on the utility's ability to offset procurement costs with revenues from other activities.
80. A more exogenous gas cost benchmark would help ensure that SoCalGas' incentives remain focused on procurement of low-cost gas.
81. It is reasonable to evaluate in a subsequent phase of this proceeding options for further modifications to the GCIM, including implementation of a more exogenous gas cost benchmark and the appropriate role of risk management strategies, either within or complementary to the GCIM.
1. SoCalGas should refund to core ratepayers all profits, with interest, that shareholders received due to operation of the GCIM mechanism between June 1, 2000 and March 31, 2001.
2. SoCalGas' Gas Acquisition group should not be allowed to provide hub services or sell gas to noncore customers after April 5, 2004 and these services and sales should be removed from the GCIM at that time.
3. SoCalGas' GCIM should be modified to make the gas cost benchmark more exogenous, that is, less reliant on SoCalGas' actual purchase decisions.
4. This order should be effective today, so that the ordered refund of GCIM profits to ratepayers may commence in a timely fashion.
IT IS ORDERED that:
1. Southern California Gas Company (SoCalGas) shall refund to core customers, with interest, all profits that shareholders received due to operation of the Gas Cost Adjustment Mechanism (GCIM) during the period commencing June 1, 2000 and ending March 31, 2001.
2. To effect the required refund, SoCalGas shall credit its Purchased Gas Account within 15 days of the effective date of this decision by an amount equal to the earnings, with interest, that shareholders received due to operation of the GCIM during the period commencing June 1, 2000 and ending March 31, 2001.
3. Within 20 days of the effective date of this decision, SoCalGas shall make a compliance filing demonstrating that it has complied with Ordering Paragraphs 1 and 2.
4. We refer our findings in Phase I.A of this proceeding to the Attorney General of the State of California or to other appropriate law enforcement agencies, and shall cooperate with any such agencies regarding this matter if they so request.
5. The Commission takes official notice of the Federal Energy Regulatory Commission (FERC) Order on Capacity Allocation and Complaints (May 31, 2002) and the FERC Order on Clarification and Adopting Capacity Allocation Methodology (September 20, 2002).
6. SoCalGas' Gas Acquisition group shall not provide hub services or sell gas to noncore customers after April 1, 2005, and SoCalGas shall not include such services and sales in its GCIM after that date.
7. The Commission shall undertake a subsequent phase of this proceeding to modify the GCIM's purchase gas cost benchmark to make it more exogenous, consider options for further modifications to the GCIM, and examine the appropriate role for risk management strategies either within or complementary to the GCIM.
This order is effective today.
Dated , at San Francisco, California.
