XXII. Assignment of Proceeding
Loretta M. Lynch is the Assigned Commissioner, and John S. Wong is the assigned Administrative Law Judge in this proceeding.
1. The Gas Accord market structure was approved in D.97-08-055, modified in part in D.00-02-050 and D.00-05-049, and extended through 2003 in D.02-08-070.
2. The Gas Accord Settlement Agreement, attached to D.97-08-055 as Appendix B, describes more fully the market structure for PG&E.
3. PG&E's application proposes to retain the basic market structure of the Gas Accord, with certain proposed changes.
4. PG&E's gas transmission and storage systems are currently operated under the rules set forth in the decisions noted in Finding of Fact 1.
5. Since the Gas Accord structure and rates are to expire at the end of 2003, PG&E's application had to address the kind of market structure that should be adopted for 2004, and what rates should look like.
6. PG&E's application and its supporting testimony essentially amounted to a GRC for PG&E's gas transmission and storage system.
7. No one has proposed a different market structure for PG&E's gas transmission and storage system, and all of the parties use the existing Gas Accord structure as the basis of their market structure.
8. Extending the gas structure beyond 2004 will provide market participants with some certainty about what kind of structure will remain in place if the Commission retains jurisdiction over PG&E's gas transmission system.
9. The evidence regarding how the Gas Accord structure has performed since its inception, is relevant in deciding what kind of gas structure should be in place beyond 2004.
10. No one disagrees that the Gas Accord structure has brought many benefits to market participants in PG&E's service territory.
11. Unlike D.02-11-073, the central focus of this proceeding is to address the gas market structure for PG&E's gas transmission and storage systems, and to set rates for 2004.
12. PG&E provided little support to justify why a proceeding investigating a specific set of circumstances in Southern California should be applied equally to PG&E.
13. The planning and design of the size of the transmission facilities to serve customer load is not a gas market structure issue.
14. A system-wide diversion of PG&E's noncore customers has never been called.
15. Approval of PG&E's Winter Reliability Standard proposal would be a commitment to upgrades over four years with costs that are subject to change.
16. No one opposes the proposal to continue the Gas Accord structure for backbone transmission services.
17. Except for the concern about whether backbone-only customers should have to pay local transmission charges, no one else opposes any other part of the proposal to continue the Gas Accord structure for local transmission service.
18. The uncertainty regarding what the future firm tariff rate will be, is just one risk factor the customer will analyze and consider.
19. Negotiated contracts for backbone transmission for up to five years is currently permitted.
20. The proposed change to the commensurate discount rule allows PG&E to operate with more flexibility with respect to the offering of discounts.
21. Although the avoidance of Commission-authorized charges is a concern from a revenue standpoint in this proceeding, this proceeding is not designed to determine whether bypass of these charges is occurring.
22. PG&E has not demonstrated that its allegations regarding bypass are occurring.
23. Since the proposed Winter Firm Capacity Requirement is not adopted, an adjustment to the assignment of storage capacity to Core Firm Storage needs to be made.
24. Core Firm Storage shall be assigned the following for 2004: 156.6 MDth/d of injection; 33,477.7 MDth of inventory; and 1,111.2 MDth/d of withdrawal.
25. As a result of the denial of PG&E's request to sell 4.5 MMDth of non-cycle working gas, the proposed inventory level for Standard Firm Storage will be reduced from 9.4 MMDth to 4.8 MMDth.
26. The inventory reduction for Standard Firm Storage affects PG&E's proposed injection and withdrawal.
27. Standard Firm Storage shall be assigned the following for 2004: 22.4 MDth/d of injection; 4,782.5 MDth of inventory; and 158.7 MDth/d of withdrawal.
28. Balancing shall be assigned the following for 2004: 76 MDth/d of injection; 4.1 MMDth of inventory; and 76 MDth/d of withdrawal.
29. No one objects to PG&E's proposal to provide Core Firm Storage to both its Core Procurement Department and to CPGs under a single tariff.
30. Since the Winter Firm Capacity Requirement is not adopted, the existing guideline in the Gas Accord shall be used to set the firm injection and withdrawal rights for CPGs that accept an assignment of less than 1000 MDth.
31. Since PG&E's proposed withdrawal rights are tied to the Winter Firm Capacity Requirement, the injection and withdrawal rights curve in Table 6-3 of Exhibit 1, and the overall ratio of injection to inventory to withdrawal, are affected by our non-adoption of the Winter Firm Capacity Requirement.
32. PG&E's seasonal adjustment in the injection and withdrawal rights curve appears to be of benefit in lowering the core storage rate, but there is insufficient information to allow us to develop a new injection and withdrawal rights curve which reflects seasonal use only.
33. Since the injection to inventory to withdrawal ratio affects the cost allocation for storage rates, the Gas Accord's assignment of injection, inventory, and withdrawal, as shown in Table 6.1 of Exhibit 1, and the Gas Accord's ratio of injection to inventory to withdrawal, shall be used for Core Firm Service in 2004.
34. Counter-cyclical storage rights provide CPGs with additional flexibility to meet their gas needs during the non-injection season.
35. This proceeding is not the appropriate forum to address PG&E's request to sell the non-cycle working gas.
36. PG&E's testimony lacks the necessary details for us to properly evaluate whether the sale of non-cycle working gas should be permitted.
37. The arguments of LGS and ORA against using rental compressors to provide additional firm injection for Schedule G-SFS, for balancing, and for providing counter-cyclical injection rights to the core, are offset by the benefits.
38. Since PG&E's request to sell 4.5 MMDth of non-cycle working gas is denied, the inventory assigned to Standard Firm Storage will be reduced to 4.8 MMDth.
39. The reduction in Standard Firm Storage affects the injection to inventory to withdrawal ratio, and PG&E's plans to lower the withdrawal ratio for Schedule G-SFS customers.
40. Since the inventory remains unchanged from the Gas Accord, the Gas Accord's assignment of injection, inventory, and withdrawal, as shown in Table 6.1 of Exhibit 1, shall be used for Standard Firm Storage in 2004, and the Gas Accord's ratio of injection to inventory to withdrawal, shall be used for Standard Firm Storage in 2004.
41. Except for the concern about the use of rental compression, no one has objected to PG&E's proposed counter-cyclical storage rights for Standard Firm Storage.
42. The counter-cyclical service will provide Schedule G-SFS customers with additional flexibility to meet their gas needs.
43. The Gas Accord II Settlement Agreement did not address what kind of process there should be for obtaining transmission and storage capacity for 2004.
44. PG&E and the other parties were free in this proceeding to propose one or more processes to obtain transmission and storage capacity.
45. To allow an extension of a 2003 contract for 2004, at the same price that was negotiated in 2003, would be unfair to both parties.
46. The transmission capacity to obtain the fuel for the DWR contracts was not raised in the testimony of any parties to this proceeding.
47. Based on PG&E's storage study, and assuming customer balancing behavior remains constant, PG&E predicts that an additional 25 MDth/d of injection will reduce the number of high OFOs by 20%, or by about 15 OFOs.
48. PG&E is the entity that has the responsibility and certificated authority to provide gas services to its customers.
49. No one has objected to PG&E's proposal to reclassify 2 MMDth of non-cycle working gas as working gas for use in its balancing service.
50. PG&E's daily imbalance limit proposal seems to affect a large group of customers who are not the cause of large system imbalances, and to impose an excess imbalance charge on them on a daily basis would be counterproductive.
51. The additional storage capacity for balancing should be used first to determine its effect on managing imbalances and OFOs before additional measures to remedy these problems are considered.
52. The current cash-out mechanism is advantageous for ratepayers.
53. The additional storage capacity for balancing should alleviate the effect of a cash-out on system operations.
54. PG&E's data shows that in 35 of 45 OFO events, California gas production imbalances exceeded the tolerance band required by the OFO.
55. PG&E has not demonstrated why the core's noncompliance charge for an EFO should be higher than the noncore's charge.
56. No party submitted any testimony or objected to the proposal that the EFO noncompliance charge for all CPGs be calculated using the lower of the Determined Usage or the end-of-flow-day core demand forecast, or the proposal that the EFO noncompliance charges for CPGs be set at a higher level than for noncore customers.
57. No party submitted any testimony or objected to the proposal to include the NAESB bumping process as part of the gas nomination process.
58. PG&E's curtailment process should be developed further before considering whether it should replace the diversion process.
59. No party submitted any testimony on the local curtailment process or the proposed noncompliance charge.
60. No other parties submitted testimony or filed comments on PG&E's shrinkage proposals.
61. Due to the non-adoption of PG&E's request to sell the non-cycle working gas, the storage cycle quantity has been changed, which affects the in-kind shrinkage allowance for the 2004 injection season.
62. Adding a gas index price as a component of the noncompliance charges will better reflect supply conditions and result in responsive behavior.
63. No party submitted testimony or commented on PG&E's proposal regarding the third party trading platform.
64. A comprehensive review of PG&E's expenses was not performed due to time and resource constraints of the parties.
65. The deadlines in the Pipeline Safety Act do not require the baseline integrity assessment to begin until mid-year of 2004.
66. Since much of the work related to the Pipeline Safety Act is not required to begin until mid-2004, the O&M expense for 2004 should be reduced by half.
67. PG&E's request for rate base treatment of its non-cycle working gas appeared in just several lines of text, and did not mention the rate base amount of $80.5 million or the revenue effect that this change in treatment would have.
68. PG&E did not comment on the rate base treatment of the non-cycle working gas in either its opening or reply briefs.
69. PG&E's position regarding its non-cycle working gas is contradictory, and it has not justified why the treatment of its non-cycle working gas should be changed in 2004.
70. Since much of the work related to the Pipeline Safety Act is not required to begin until mid-2004, the capital expenditures for 2004 should be reduced by half.
71. Since PG&E's proposal for a Winter Reliability Standard is not adopted, the forecast of expenditures to upgrade local transmission facilities is not needed.
72. A reduction to the 2004 capital expenditures for Power Plant Metering and Power Plant Connections should be made because the reduced number of new power plants was not reflected.
73. The insurance recovery issue for the Gerber Compressor Station, and what should be done with the proceeds, should be explored in a separate application.
74. This is the appropriate proceeding in which to address PG&E's cost of providing transmission and storage services to its customers, and to develop a revenue requirement and rates to recover those costs.
75. Updating the demand forecast at this point would be impractical given the time constraint.
76. The sensitivity runs that PG&E performed show that if power plants are delayed by one year, the 2004 EG throughput would be 14% higher, or using PG&E's EG forecast, it would increase to 663 MDth/d.
77. Using the sensitivity run for a one year delay, PG&E's total combined EG and cogeneration forecast would be 926.2 MDth/d.
78. Based on the information contained in the CEC report, PG&E's sensitivity run, and the forecast recommended by CCC/Calpine, PG&E's electric generation and cogeneration forecast for 2004 should not be changed.
79. PG&E is requesting that it be permitted to allow eligible off-system end users to connect directly to PG&E's backbone transmission service, while at the same time forecasting that its off-system throughput in 2004 will drop from 298 MDth/d to 219 MDth/d.
80. PG&E's off-system throughput should remain at 298 MDth/d for 2004.
81. PG&E's witness acknowledged that the 20% roll-in proposal is the beginning of a movement toward a full roll-in of Line 401 costs to the core.
82. The term "substantial customer benefits" originated in the Gas Accord decision in the section entitled "Features Opposing Approval" of the Gas Accord Settlement Agreement.
83. All of the passages in section 5.4 of D.97-08-055 make clear that the Commission's policy is in favor of incremental rates, and that the approval of the Gas Accord Settlement Agreement "cannot be cited as precedent in favor of rolled-in rates."
84. The Gas Accord decision expressed a strong disfavor for any future request for a full roll-in of Line 401 costs if such a roll-in increase core or noncore rates.
85. D.94-02-042 assigned "all risks of undersubscription, and most of the risks of underutilization" of Line 401 to PG&E's shareholders.
86. PG&E's proposal to roll-in 20% of the costs of Line 401 in 2004 would affect core rates by approximately $17.7 million.
87. When high gas costs are factored in with the cost of a full or partial roll-in of Line 401 costs, core customers will experience severe rate shock.
88. When the regulatory history of Line 401, the commitments made by the Commission and PG&E, the prior decisions, and the additional costs, are considered against the substantial benefits the core may have received from Line 401, the considerations outweigh the substantial benefits.
89. PG&E and the other parties have come up with four different ways of calculating the load factor.
90. PG&E's use of the net firm capacity of 3195.292 as the denominator for the load factor is a departure from the design capacities used in the Gas Accord.
91. The load factor that we adopt will affect the rates, and PG&E's ability to recover the adopted revenue requirement.
92. PG&E's load factor of 68.4% is quite a bit below the load factors that were experienced during the Gas Accord period.
93. The utilization factor of 95% that TURN uses in its load factor adjustment comes from D.94-02-042, and is very close to the load factors experienced on the combined Redwood paths during the Gas Accord period.
94. Using TURN's method of adjustment, and the off-system delivery adjustment in the demand forecast, the system load factor upon which backbone rates shall be based is 77.46%.
95. No one raised any objection to the use of the total net firm capacity to calculate the load factor, and to allocate the costs to the backbone paths.
96. No one objected to PG&E's proposal that the Redwood Path off-system rate be set to equal the Redwood on-system rate.
97. Requests for a backbone-only rate have come before the Commission previously.
98. The cost impact examples show that the four-tier proposal and the backbone-only proposal will shift the cost burden onto the core and the other customers who are not in a position to bypass the system.
99. The four-tier proposal and the backbone-only proposal raise the fundamental issue of who should pay for the cost of facilities to serve customers.
100. Under a backbone-only rate, customers connected to the backbone would avoid all local transmission charges, and the costs these customers avoid will be shifted to the remaining customers.
101. Although a stranded cost charge could recover part of the avoided local transmission charges, none of the parties developed concrete suggestions for determining how much this charge should be.
102. Core wholesale customers have attributes which clearly distinguish them as a noncore customer, and have been treated as such for more than 15 years.
103. The four-tier proposal and the backbone-only proposal require careful thought on how far we should unbundle, and who will end up paying the costs, policies which should not be considered today.
104. The balancing of higher rates for the majority of customers versus lower rates for a small number of customers, clearly weighs in favor of not adopting the proposals which would increase rates for the majority of customers.
105. Since the O&M expenses and capital expenditures were at issue in this proceeding, resolution of the customer access charges will not be deferred.
106. None of the other parties presented any evidence to show that the growth in connections of electric generators over the last seven years has not raised PG&E's costs to connect these additional customers.
107. PG&E has not provided any support for adding two additional tiers to Schedule G-NT.
108. It is appropriate to consider PG&E's proposal to apply the Schedule G-NT rates to Schedule G-EG since one of PG&E's other proposals is for a single electric generation class.
109. No one opposed PG&E's proposal to impose a distribution rate component on the industrial transmission customer class, or its proposal to eliminate the cogeneration distribution shortfall rate component in the customer class charge.
110. No one opposed PG&E's proposal to change the transmission-level eligibility standard.
111. The issue of balancing account treatment for PG&E's noncore distribution revenues should be raised in PG&E's BCAP.
112. No evidence has been presented about what the consequences might be for distributed generation if the proposal for a single electric generation class is adopted.
113. A single electric generation customer class was adopted for SoCalGas and SDG&E in D.00-04-060.
114. PG&E's proposed method of using an average heat rate for similarly sized electric generation facilities may not correctly reflect the customer's actual heat rate.
115. The financial impact of the distribution costs allocated to distribution level electric generation customers will be lessened if PG&E's proposal for recovering these costs is adopted.
116. The distribution level electric generation customer should be prepared to take 100% responsibility in 2005 for the distribution costs that are allocated to them.
117. The Governmental Mechanism would allow PG&E to reach back in 2003 to include costs in its gas transmission and storage rates and charges for 2004.
118. The Governmental Mechanism is more favorable to PG&E's shareholders as compared to the z-factor that was agreed to in the Gas Accord.
119. The amount of firm interstate capacity at Topock is being addressed in Phase II of the El Paso proceeding.
120. PG&E has not sought to modify the CPIM.
121. SPURR/ABAG's spin-off proposal raises issues that are too complex to address in this proceeding.
122. PG&E's core transport paths, instead of unbundling the various ways in which gas ESPs can obtain gas, would require them to take service over the entire transport path.
123. An annual election to a pro rata share of the core transport paths, as opposed to the current monthly election, reduces the operating flexibility that gas ESPs have because it requires them to make an annual commitment for capacity.
124. PG&E already provides information regarding its monthly gas price.
125. There are still a number of issues regarding proposed Gas Rule 27 that the parties have not been able to agree on.
126. During the last five years, there have been no exceptional case facilities agreements for transmission-level facilities.
127. The projects that require interconnection to transmission-level service can or have used exceptional case agreements or the standard provisions of Gas Rules 2, 15 and 16.
128. No one objected to PG&E's off-system direct connect proposal.
129. No one objected to PG&E's request to continue the CGT Risk Management Program, or to the proposed changes which it seeks.
1. The recommendation to extend the Gas Accord structure and current rates for 2004 is not adopted.
2. We adopt the Gas Accord market structure referenced in Finding of Fact 1, and as changed by the specific proposals adopted in today's decision, as the gas market structure for PG&E in 2004 and 2005.
3. PG&E has not met its burden of proving that the Winter Reliability Standard is needed at this point in time.
4. We do not adopt PG&E's proposal for a Winter Reliability Standard.
5. We do not adopt PG&E's proposal for a Winter Firm Capacity Requirement.
6. PG&E's proposal to continue the Gas Accord structure for backbone transmission service is adopted, and the other proposals that we adopt which affect this service, shall also be part of the structure for backbone transmission service.
7. PG&E's proposal to continue the Gas Accord structure for local transmission service is adopted, and the other proposals that we adopt which affect this service, shall also be part of the structure for local transmission service.
8. PG&E's proposal to offer long-term backbone transmission contracts for up to 15 years is adopted.
9. PG&E's proposal to change the commensurate discount rule is adopted.
10. PG&E's proposal to limit the MDQ of any as-available contract for backbone service to the expected usage of that contract by a shipper, and to reduce the contract's MDQ to the previous day's actual usage if scheduling non-performance continues, is adopted.
11. PG&E's proposal to impose a monthly reporting and registration requirement, and authority to charge for transportation charges which allegedly have been avoided, is not adopted.
12. PG&E's proposal to use a single tariff, Schedule G-CFS, to provide Core Firm Storage to PG&E's Core Procurement Department and to CPGs is adopted.
13. PG&E's proposal to add firm counter-cyclical injection and withdrawal to Core Firm Storage is adopted.
14. PG&E's proposal to have Schedule G-SFS replace the existing Schedule G-FS is adopted, and such schedule shall conform to the other proposals that we adopt.
15. PG&E shall file a § 851 application if it wants to sell the non-cycle working gas.
16. PG&E's request to sell the 4.5 MMDth of non-cycle working gas is denied without prejudice.
17. PG&E shall be permitted to use rental compression to provide the injection for Schedule G-SFS, for balancing, and for providing counter-cyclical injection rights to the core.
18. PG&E's proposal to offer firm counter-cyclical storage rights to Schedule G-SFS customers is adopted.
19. PG&E's proposal for a contract extension and open season process as set forth in Appendix A of Chapter 7 of Exhibit 1 is adopted.
20. PG&E's proposal to increase its storage capacity for its balancing service is adopted.
21. PG&E's proposal to reclassify the 2 MMDth of gas as working gas for use in PG&E's balancing service is adopted.
22. PG&E's proposal for a daily imbalance limit and related excess imbalance charge is not adopted.
23. PG&E's proposal to replace the cash-out mechanism with an imbalance charge for monthly imbalances in excess of the tolerance band is not adopted, and PG&E shall continue to use the existing cash-out mechanism.
24. PG&E's proposal that the cash-out prices for terminated contracts be changed, is adopted.
25. PG&E's proposed application of the existing EFO and OFO rules to California gas producers in 2004 is not discriminatory.
26. PG&E's proposed application of the existing EFO and OFO rules to California gas producers in 2004 does not violate § 785 and 785.2.
27. PG&E's proposal to apply the same OFO and EFO tolerance bands and noncompliance charges that are currently in place for end-use customers, to California gas production, is adopted.
28. PG&E's proposal that the EFO noncompliance charge for CPGs be set at a higher level than for noncore customers is not adopted, and PG&E shall use the same EFO noncompliance charge for both CPGs and noncore.
29. PG&E's proposal to use the Determined Usage forecast to calculate the compliance of CPGs with flow orders is adopted.
30. PG&E's proposal that the EFO noncompliance charge for all CPGs be calculated using the lower of the Determined Usage or the end-of-flow-day core demand forecast, as compared to the CPG's scheduled supply, is adopted.
31. PG&E's proposal to include the NAESB bumping process as part of PG&E's gas nomination process is adopted.
32. PG&E's proposal to replace the existing diversion process with a curtailment process for 2004, and the related noncompliance charge, is not adopted.
33. PG&E's proposal that the current local curtailment process be continued is adopted for 2004 and 2005.
34. PG&E's proposal for a noncompliance charge for local curtailments for use in 2004 is adopted.
35. PG&E's proposal to allow PG&E to update its shrinkage allowances on an annual basis through an advice letter compliance, or more often if needed, is adopted.
36. PG&E's proposal that an in-kind shrinkage allowance be applied to all scheduled storage injection volumes is adopted.
37. PG&E's proposal that most of the noncompliance charges incorporate one of three relevant gas indexes is adopted.
38. PG&E is authorized to use the noncompliance charges shown in Table 8-6 of Exhibit 1 for 2004, except as noted in the text of this decision.
39. PG&E's proposal to eliminate the third party trading platform and services, and to credit the unused monies back to the BCA is adopted.
40. The adopted revenue requirement for 2004 shall serve as the maximum cap, and shall not be adjusted as a result of the fiscal impact that any of today's adopted adjustments may have on the revenue requirement.
41. The O&M expense for work related to the Pipeline Safety Act in 2004 shall be reduced by half.
42. PG&E's forecast of O&M expense for 2004, less the adjustment for the Pipeline Safety Act, is adopted.
43. PG&E's forecast of capital expenditures for 2004, less the adjustments we have made, is adopted.
44. Based on the proposals adopted in this decision, the adjustments to PG&E's forecast of O&M expenses and to its capital expenditures, a revenue requirement of $437,564,000 should be adopted for 2004.
45. Official notice is taken of the CEC report dated August 2003, which is entitled "Natural Gas Market Assessment."
46. The forecasts of demand and throughput and the backbone load factor adjustment that are shown in Table 13-1 of Exhibit 1, as modified by the increase to off-system delivery, is adopted for use in 2004.
47. The reference to substantial customer benefits must be read in context with the rest of the Gas Accord decision, including the noncore's willingness in the Gas Accord settlement to a partial roll-in of Line 401 costs.
48. The Gas Accord Settlement Agreement was adopted with the express understanding that "core retail and core wholesale customers will continue to benefit from low, vintaged rates on Line 400 and will not have to pay for Line 401 costs."
49. To renege on our prior commitments regarding Line 401 will undermine our regulatory authority.
50. PG&E's proposal, and the other parties' proposals, to roll-in some or all of the costs of Line 401 to the core is not adopted.
51. Since we do not adopt the proposal to roll-in some or all of the costs of Line 401 to the core, CAPP's proposal for path-specific rates and for a postage stamp rate are not adopted.
52. Based on the load factors experienced during the Gas Accord period, and the need for just and reasonable rates while providing PG&E with the opportunity to recover its costs and a reasonable rate of return, an adjustment to PG&E's load factor using TURN's load factor method should be made so that PG&E's load factor correlates more closely to the load factors experienced during the Gas Accord period.
53. The adjusted load factor of 77.46% is at or below the load factors experienced on PG&E's transmission system during the Gas Accord period, and represents an equitable balance between just and reasonable rates, while providing PG&E with a reasonable opportunity to recover its revenue requirement.
54. The firm design capacities in Table 14.4 of Exhibit 3 are adopted, and they shall be used to allocate costs to the backbone paths, and for use in the denominator to calculate the adopted load factor of 77.46%.
55. PG&E's proposal that the Redwood off-system rate equal the Redwood on-system rate is adopted.
56. PG&E's proposal to assign vintage Redwood capacity to core retail and core wholesale is adopted.
57. Since the Winter Firm Capacity Requirement is not adopted, PG&E's assignment of non-vintage Redwood Path and Baja capacity shall be done on the basis of meeting the current guidelines, which is close to a 1-in-3 year cold temperature event.
58. PG&E's proposal that Schedule G-XF rates continue to be designed on an incremental basis is adopted.
59. The backbone rates attached to this decision in Tables 3 to 9 of Appendix A shall be adopted as the backbone rates in this proceeding.
60. PG&E's proposal to continue the rate design structure for Core Firm Storage is adopted.
61. PG&E's proposal to combine the capacity charge and the withdrawal charge into a single capacity charge on Schedule G-SFS is adopted.
62. PG&E's proposal to continue the self-balancing option is adopted.
63. Since we do not adopt the Winter Reliability Standard, TURN's suggestion that the local transmission cost allocation be done on the basis of a cold year non-coincident peak month is moot.
64. Under the four-tier proposal and the backbone-only proposal, the rate increases to the core, core wholesale, and to the smaller noncore customers, would not be just and reasonable.
65. The proposals for a backbone-only rate, and for a four-tier local transmission rate for the noncore, are not adopted.
66. PG&E shall continue to use the existing cost allocation and rate design methodology from the Gas Accord for local transmission charges in 2004.
67. PG&E's proposal to add tiers 7 and 8 to Schedule G-NT is not adopted.
68. PG&E's proposal to apply the Schedule G-NT customer access charges, as revised by this decision, to Schedule G-EG is adopted.
69. PG&E is permitted to update its cost of service for transmission-level customer level, as adopted in this decision, and PG&E shall continue to use the existing cost allocation.
70. PG&E's proposal to impose a distribution rate component on the industrial transmission customer class to recover the distribution costs allocated to this class is adopted.
71. PG&E's proposal to eliminate the cogeneration distribution shortfall rate component in the customer class charge is adopted.
72. PG&E's proposal to modify the transmission-level eligibility criteria is adopted.
73. PG&E's proposal to adopt 100% balancing account protection for PG&E's noncore distribution revenues is not adopted.
74. Since PG&E's single electric generation customer class proposal treats electric generators alike, it grants parity to cogenerators, and is therefore in compliance with § 454.4.
75. PG&E's anti-gaming measure shall use the method set forth in Special Conditions 19 through 22 of SoCalGas' Schedule GT-F tariff.
76. PG&E's proposal for a single electric generation customer class, as revised by our discussion, is adopted.
77. PG&E's proposal for a Governmental Mechanism is not adopted.
78. The z-factor adjustment from the Gas Accord shall be retained as part of the gas structure that we adopt for 2004 and 2005.
79. We authorize the continuation of the CEMA and HSM mechanisms as contingency adjustments to the gas structure.
80. PG&E shall be permitted to make an adjustment to replace the A&G placeholder with the A&G expenses adopted in PG&E's GRC.
81. PG&E is authorized to establish a memorandum account to track the difference between the A&G expenses authorized in this decision, with the amount adopted in the 2003 GRC, escalated to 2004, plus interest.
82. PG&E's proposal that additional storage withdrawal capacity be assigned to the core to meet the Winter Firm Capacity Requirement is not adopted.
83. PG&E's proposal to tailor the core's holdings of Baja transmission capacity to match the firm interstate capacity holdings at Topock is not adopted at this time.
84. PG&E's proposal to retain the current CPIM as the default incentive mechanism for PG&E's Core Procurement Department for 2004 and 2005, or until a revised CPIM is adopted by the Commission, is adopted.
85. PG&E's proposal to clarify the reliability planning standards, and to eliminate the alternate benchmark in the CPIM are not adopted because the Winter Firm Capacity Requirement is not adopted.
86. PG&E may make tariff changes that are consistent with the proposals that have been adopted in this decision.
87. Section 328.2 suggests that PG&E's Core Procurement Department cannot be spun-off unless there is a structure that allows the gas corporation to continue providing bundled basic gas service.
88. SPURR/ABAG's proposal to spin-off PG&E's Core Procurement Department is not adopted.
89. PG&E's proposal that gas ESPs serving core customers be subject to the same Winter Firm Capacity Requirement as PG&E's Core Procurement Department is moot because the Winter Firm Capacity Requirement is not adopted.
90. Gas ESPs serving core customers shall be allowed to obtain a proportionate share of core holdings on the GTN, Redwood, and Baja pipelines.
91. If capacity on El Paso and possibly Transwestern is assigned to the core and included as part of the CPIM, gas ESPs serving core customers shall be allowed a proportionate share of those holdings.
92. Based on the Commission's January 23, 2002 action, and the Gas Accord's precondition to NOVA and ANG capacity, we will not allow gas ESPs to obtain a proportionate share of those pipelines at this time.
93. Except for the changes related to the Winter Firm Capacity Requirement, PG&E may make the other changes to the core storage program.
94. For 2004 and 2005, the core firm storage provisions shall be based on D.00-05-049 and the adopted core firm storage changes.
95. PG&E's proposal to make it mandatory for gas ESPs serving core customers to accept a pro rata share of core transmission and storage capacity once the CAT program serves ten percent of peak core loads is adopted.
96. SPURR/ABAG's proposal for PG&E to provide information regarding its monthly gas price is not adopted.
97. PG&E's proposed Gas Rule 27 shall not be adopted at this time.
98. PG&E request to establish an off-system direct connect tariff, as clarified in today's decision, shall be permitted, and PG&E may file such a tariff via an advice letter filing.
99. PG&E is authorized to continue using financial derivative instruments to manage price and revenue risks pursuant to the CGT Risk Management Program that was approved in D.98-12-082, as modified in D.99-04-013, as extended by D.02-08-070, and as changed by today's decision.
100. The authority for PG&E to use financial derivative instruments to manage price and revenue risks pursuant to the CGT Risk Management Program shall expire on December 31, 2005, unless further extended by the Commission.
IT IS ORDERED that:
1. The existing gas market structure contained in Decision (D.) 97-08-055, as modified by D.00-02-050 and D.00-05-049, and as changed by the proposals adopted in today's decision, shall serve as the gas market structure for the gas transmission and storage facilities and operations of Pacific Gas and Electric Company (PG&E) for 2004 and 2005.
a. The proposals adopted today, as set forth in the Conclusions of Law and as described and discussed in this decision, shall be incorporated into the gas market structure.
b. PG&E shall conduct its transmission and storage operations in accordance with the adopted gas market structure, and with all other applicable rules, regulations, and Commission decisions.
2. A revenue requirement of $437,564,000 is adopted for PG&E's gas transmission and storage facilities and operations for 2004.
a. The adopted revenue requirement is set forth in Tables 1 and 2 of Appendix A of this decision, and reflects the adopted adjustments that were made to PG&E's proposed revenue requirement for 2004.
3. The rates set forth in Tables 3 to 13 of Appendix A of this decision are adopted, and PG&E shall use these adopted rates in 2004 for its transmission and storage services.
4. Within five days of today's date, PG&E shall file an advice letter or letters to change all of its transmission and storage rates to reflect the adopted rates, and to change its affected gas schedules and rules to reflect the revised gas market structure as adopted in today's decision.
a. The advice letter filing(s) shall be consistent with and comply with the adopted revenue requirement and rates, and the adopted proposals concerning its transmission and storage operations and related issues.
b. The advice letter filing(s) shall go into effect seven days after filing, and shall remain in effect, even if protested, until a Commission resolution or decision rescinds, suspends, or changes the rate(s) or practice(s) described in the advice letter filing(s).
c. The advice letter filing(s) may be protested, and such a protest shall be filed within ten days after the advice letter has been filed.
d. PG&E shall serve the advice letter filing(s) on the service list to this proceeding by e-mail and by mail.
5. PG&E is authorized to do the following:
a. To engage in the adopted contract extension and open season process using the rates adopted in this decision.
b. To continue using financial derivative instruments to manage price and revenue risks pursuant to the CGT Risk Management Program as adopted in today's decision.
c. To file an advice letter for a tariff which allows off-system end users the ability to directly connect to PG&E's backbone transmission facilities, as discussed and adopted in today's decision.
d. Submit an advice letter filing establishing a memorandum account to track the difference between the placeholder amount for the Administrative & General (A&G) expenses adopted in this decision, and the A&G amount to be adopted in PG&E's 2003 General Rate Case, escalated to 2004, plus interest.
6. PG&E shall do the following:
a. For 2004, submit its annual advice letter filing regarding transmission and distribution shrinkage allowances, which shall be filed on or before December 26, 2003, with an effective date of January 1, 2004.
b. On or before March 19, 2004, file an advice letter which calculates the in-kind storage shrinkage allowance for the 2004 injection season.
c. Monitor the effectiveness of the additional storage capacity in its daily operations and balancing, and include in its transmission and storage rate case for 2005, a report about the additional storage capacity, and its effects on system balancing and operations.
d. Work with the California Natural Gas Producers Association and interested California gas producers to resolve operational issues regarding flow orders.
e. File an application within 90 days of today's date addressing the status of possible insurance claims with respect to the fire at the Gerber Compressor Station, what should be done with any insurance proceeds, and whether the Commission should look into the actions of PG&E with respect to the plant fire.
f. File an advice letter within 20 days of today's date to establish a memorandum account to track all the revenues that PG&E receives in rates for the Gerber Compressor Station, and all the proceeds PG&E may receive from any associated insurance claims, plus interest, and to make those revenues subject to possible refund to ratepayers.
g. File on or before March 19, 2004, its gas transmission and storage rate case application for 2005.
h. File an application no later than February 4, 2005 proposing the kind of gas market structure and rates that PG&E's gas transmission and storage system should operate under beginning January 1, 2006, and how long the rates and such a structure should remain in place.
7.
8. Application 01-10-011 is closed.
This order is effective today.
Dated _____________________, at San Francisco, California.
APPENDIX A
APPENDIX B
2004 GAS STRUCTURE MATRIX
Proposal Description |
Adopt |
Adopt As Changed |
Do Not Adopt | |
Should the current Gas Accord structure, rates, and terms and conditions, as modified and extended through 2003, be extended through 2004? |
X | |||
Should the Commission adopt a gas market structure for PG&E's transmission and storage systems for 2004 and 2005 that is based on the Gas Accord structure, as changed and extended by prior decisions, and as changed by the proposals adopted in this decision? |
X |
|||
Should PG&E's proposal for a 1-in-10 year cold temperature Winter Reliability Standard for the design of PG&E's local transmission and central backbone facilities be adopted? |
X | |||
Should PG&E's proposal for a Winter Firm Capacity Requirement for all CPGs be adopted? |
X | |||
TURN's proposal to change the peak month allocator if the Winter Reliability Standard is adopted. |
X | |||
LGS' proposal that third party storage providers be allowed to provide the additional withdrawal capacity created by the need to meet the Winter Reliability Standard. |
X | |||
PG&E's proposal to continue the Gas Accord structure for backbone transmission service. |
X |
|||
PG&E's proposal to continue the Gas Accord structure for local transmission service. |
X |
|||
PG&E's proposal to offer long-term backbone transmission contracts for up to 15 years. |
X |
|||
PG&E's proposal to change the commensurate discount rule. |
X |
|||
PG&E's proposal regarding scheduling non-performance. |
X |
|||
PG&E's bypass reporting and registration proposal. |
X | |||
PG&E's proposed assignment of storage capacity for 2004. |
X |
|||
PG&E's proposal to use Schedule G-CFS to serve its Core Procurement Department and CPGs. |
X |
|||
Use existing guideline in the Gas Accord to set the firm injection and withdrawal rights for CPGs accepting a storage inventory of less than 1000 MDth. |
X |
|||
PG&E's proposal to use the injection and withdrawal rights curve for CPGs shown in Table 6-3 of Exhibit 1. |
|
X | ||
Use the Gas Accord's assignments for Core Firm Storage in 2004, and the Gas Accord's ratio for Core Firm Storage in 2004. |
X |
|||
PG&E's proposal to add firm counter-cyclical injection and withdrawal to Core Firm Storage. |
X |
|||
PG&E's proposal to have Schedule G-SFS replace Schedule G-FS. |
X |
|||
PG&E's request to sell 4.5 MMDth of non-cycle working gas. |
X | |||
PG&E's proposal to use rental compressors. |
X |
|||
Use the Gas Accord's assignments for Standard Firm Storage in 2004, and the Gas Accord's ratio for Standard Firm Storage in 2004. |
X |
|||
PG&E's proposal to add firm counter-cyclical storage rights to Standard Firm Storage. |
X |
|||
PG&E's proposal to offer long-term firm storage contracts. |
X |
|||
PG&E's proposal for a 2004 contract extension and open season. |
X |
|||
Other parties' proposal for a full open season for transmission and storage capacity. |
X | |||
Should PG&E be required to extend a negotiated contract at the same negotiated contract price? |
X | |||
NCGC's suggestion to add capacity amounts to shippers' name on the Pipe Ranger website. |
X | |||
NCGC's recommendation to add an additional 25 MDth/d of injection to balancing. |
X | |||
PG&E's proposal to increase its storage capacity for balancing. |
X |
|||
PG&E's proposal to reclassify 2 MMDth of non-cycle working gas as working gas for its balancing service. |
X |
|||
PG&E's proposal to impose a daily imbalance limit and a $0.25 per Dth excess imbalance charge. |
X |
|||
PG&E's proposal to replace the current cash-out process with an imbalance charge (market-index based) for monthly imbalances in excess of the tolerance band, and that the customer be responsible for ultimately clearing its entire physical imbalance. |
X | |||
PG&E's proposal that the cash-out prices for terminated contracts be changed. |
X |
|||
PG&E's proposal to apply the OFO and EFO intolerance bands and noncompliance charges to California production imbalances. |
X |
|||
PG&E's proposal that the EFO noncompliance charge for CPGs be set at a higher level than noncore customers. |
X |
|||
PG&E's proposal to change the forecast used to determine a CPG's OFO and EFO compliance. |
X |
|||
PG&E's proposal to base the noncompliance charge using the lower of the Determined Usage Forecast or the end-of-flow day core demand forecast. |
X |
|||
PG&E's proposal to implement the NAESB bumping process as part of the nomination process. |
X |
|||
PG&E's proposal to replace the current diversion process with its proposed curtailment process. |
X | |||
PG&E's proposal to continue the local curtailment process. |
X |
|||
PG&E's proposal to impose a local curtailment noncompliance charge. |
X |
|||
PG&E's proposal to adjust shrinkage on a yearly basis, and additional adjustments during the year as may be needed. |
X |
|||
PG&E's proposal for a gas storage shrinkage allowance. |
|
X |
||
PG&E's proposal that the noncompliance charges shown in Table 8-6 of Exhibit 1 include a cost of gas component. |
X |
|||
PG&E's proposal that the third party electronic trading platform adopted in D.00-05-049 be terminated, and the unused funds credited back to the BCA. |
X |
|||
Whether an adjustment to PG&E's O&M expense for the Pipeline Safety Act should be made. |
X |
|||
TURN's proposal for three adjustments to PG&E's O&M expenses. |
X | |||
PG&E's forecast of O&M expenses for 2004. |
X |
|||
PG&E's proposal to add $80.5 million of non-cycle working gas to ratebase for 2004. |
X | |||
Should the capital expenditures for the Pipeline Safety Act be reduced by half to reflect the deadlines for starting the assessment work? |
X |
|||
Should the $2 million in capital expenditures for upgrading of local transmission facilities to meet the Winter Reliability Standard be removed? |
X |
|||
Should the capital expenditures for Power Plant Metering and Power Plant Connections be reduced to reflect fewer power plants being built? |
X |
|||
TURN's proposal that a prudency hearing be held to look into the circumstances regarding the Gerber Compressor Station fire, and whether a memorandum account should be established. |
X |
|||
PG&E's forecast of capital expenditures for 2004. |
X |
|||
PG&E's proposed revenue requirement of $454 million for 2004. |
X | |||
Should a total revenue requirement of $437,564,000 for PG&E's gas transmission and storage systems be adopted for 2004? |
X |
|||
Proposals to update the demand forecasts. |
X | |||
Whether PG&E's demand forecasts should be adopted. |
X |
|||
Whether PG&E's EG demand forecast should be changed. |
X | |||
Whether PG&E's off-system delivery forecast should be changed. |
X |
|||
Whether PG&E's backbone throughput adjustment should be adopted. |
X |
|||
Core vintage Line 400 Redwood Path rates to be 20% rolled-in with noncore Redwood Path costs for 2004. |
X | |||
Proposals of other parties for a full roll-in of Line 401 costs to the core. |
X | |||
PG&E's proposal to design backbone rates using a system average load factor of 68.4%. |
X | |||
Should PG&E's load factor be adjusted? |
X |
|||
PG&E's use of net firm capacity to calculate the load factor and to allocate costs |
|
X |
||
PG&E's proposal that the Redwood Path off-system rate be set to equal the Redwood Path on-system rate. |
X |
|||
PG&E's proposal to assign vintage Redwood capacity to core retail and core wholesale. |
X |
|||
PG&E's proposal to assign non-vintage Redwood Path and Baja to the core to meet 1-in-10 year demand requirements. |
|
X | ||
PG&E's proposal that Schedule G-XF rates be designed on an incremental basis. |
X |
|||
PG&E's proposal to continue the rate design structure for Core Firm Storage. |
X |
|||
PG&E's proposal to simplify the G-SFS storage rate design by combining two charges into a single capacity charge. |
X |
|||
PG&E proposes to continue the self-balancing service option. |
X |
|||
PG&E's proposal that local transmission rates for noncore utilize a four-tier rate design based on a customer's annual usage. |
X | |||
Proposal for a backbone-only rate. |
X | |||
PG&E's proposal to add two tiers to Schedule G-NT. |
X | |||
PG&E's proposal to apply the customer access charges in Schedule G-NT to Schedule G-EG. |
|
X |
||
PG&E's proposal to impose a distribution rate component on the industrial transmission customer class to recover the distribution costs. |
X |
|||
PG&E's proposal that the cogeneration distribution shortfall rate component in the customer class charge be eliminated. |
X |
|||
PG&E's proposal to modify the transmission-level eligibility criteria. |
X |
|||
PG&E's proposal for 100% balancing account protection for noncore distribution revenues. |
X | |||
PG&E's proposal for a single electric generation customer class. |
X |
|||
PG&E's proposal that the Governmental Mechanism replace the z-factor adjustment. |
X | |||
Should the z-factor adjustment of the Gas Accord be retained as part of the gas market structure for 2004 and beyond. |
X |
|||
PG&E's proposal to retain the CEMA and HSM adjustment mechanisms. |
X |
|||
PG&E's proposal to create a memorandum account, with interest, to track the difference in A&G expenses adopted in the 2003 GRC, with escalation, to the A&G placeholder for the 2004 gas structure, and to file an adjustment by an advice letter filing. |
X |
|||
PG&E's proposal to increase the core firm storage assignment through 75 MDth/d of withdrawal capacity. |
X | |||
PG&E's proposal to match core holdings on the Baja Path with the firm interstate capacity holdings at Topock. |
X | |||
PG&E's proposal that the current CPIM, and that it reflect the new core Winter Firm Capacity Requirement and additional capacity additions, be adopted as the default structure until a revised CPIM is adopted. |
|
X | ||
Should the current CPIM be adopted as the default incentive mechanism for 2004-2005, or until a revised CPIM is adopted. |
X |
|||
PG&E's proposals to clarify the reliability planning standards and to eliminate the alternate benchmark in the CPIM. |
|
X | ||
PG&E's proposal to make a series of tariff changes. |
X |
|||
SPURR/ABAG's proposal to spin-off PG&E's Core Procurement Department. |
X | |||
PG&E's proposal that gas ESPs serving core customers be expected to conform to the Winter Firm Capacity Requirement. |
X | |||
PG&E's proposal that gas ESPs serving core customers have the option to obtain pro rata shares of core transmission capacity over four core transport paths. |
X | |||
PG&E's proposal that five changes be made to the core firm storage program. |
X |
|||
PG&E's proposal that once the CAT program grows beyond 10% of core load, that the storage and transportation options become mandatory assignments. |
X |
|||
SPURR/ABAG proposal that PG&E provide additional information regarding its core procurement pricing. |
X | |||
PG&E's proposal to adopt new gas Rule 27 regarding interconnection services. |
|
X | ||
PG&E's proposal to establish a new tariffed service to allow eligible off-system end users to connect directly to PG&E's backbone. |
X |
|||
PG&E's proposal to continue the use of the CGT Risk Management Program, and to make some modifications to the program. |
X |
|||
(END OF APPENDIX B)
