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QUESTION 2.1

Please update SoCalGas’ and SDG&E’s response (spreadsheet) to SCGC’s Data Request 3, Question 3, in R.04-01-025 to include the years 2004, 2005 and 2006. For your convenience, both the request and response are replicated below. Please ensure that the information presented in the spreadsheet for years 2004-2006 is broken out in the same manner as it was for the years 2000-2003.

QUESTION 3

The SoCalGas Noncore Storage Balancing Account (“NSBA”) is a balancing account that SoCalGas uses to balance the authorized at-risk non-gas costs for unbundled storage service with the reservation and in-kind energy charge revenues collected from customers who contract for these unbundled storage services.  SoCalGas maintains the NSBA by making a variety of debit and credit entries each month, as specified in the SoCalGas Preliminary Statement.  For each month of the years 2000 through 2003, please provide the balance in the NSBA.  To the extent that SoCalGas makes entries in subaccounts to the NSBA, please provide the monthly balance in each subaccount.  Also, please provide the amounts debited and the amounts credited to the NSBA and each subaccount.  Please provide this information electronically in a working Excel spreadsheet.

RESPONSE 3

Attached is an Excel spreadsheet with the requested information for the years 2000 through 2003.

RESPONSE 2.1

Attached is an Excel spreadsheet with the requested information updated for the years 2004 through 2006.

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QUESTION 2.2

In the Excel spreadsheet showing the breakdown of the NSBA for years 2000-2003, there is a line item called “amortization” that shows up as either a positive or negative amount at lines 28 and 73 for years 2001, 2002, and 2003 and lines 27 and 71 for year 2000. Please explain what is being amortized and how the amount of the amortization is being determined.

RESPONSE 2.2

The line item called “amortization” represents the monthly amortization of the prior year’s ending balance of the NSBA regulatory account. Annually, SoCalGas files with the Commission its Regulatory Account Balance Update filing projecting year-end balances for its regulatory accounts, including the NSBA, which are authorized for inclusion into the subsequent year’s transportation rates. For example, the amortization included in the NSBA for the year 2003 was based on the year-end balance for 2002 authorized in transportation rates effective January 1, 2003.

QUESTION 2.3

Please update SoCalGas’ and SDG&E’s response to SCGC’s Data Request 3, Question 4, in R.04-01-025 to include the years 2004, 2005 and 2006. For your convenience, both the request and response are replicated below.

QUESTION 4

For each month, 2000 through 2003, please identify the applicable percentage of balancing account protection that SoCalGas was authorized to receive for the balance in the NSBA, and identify the Commission decision that authorized such percentage.  For each of the months, please identify the amount that was the responsibility of the ratepayers and the amount that was the responsibility of the shareholders.  Please provide this information electronically in a working Excel spreadsheet.

RESPONSE 4

Effective April 1, 1993, pursuant to D.93-02-013, “subscribed” and “unsubscribed” storage revenues were subject to 75% and 100% balancing account treatment, respectively, while shareholders were at risk for the remaining 25% of subscribed storage revenues. Effective June 1, 2000, pursuant to D.00-04-060 dated April 20, 2000 in SoCalGas’ 1999 Biennial Cost Allocation Proceeding, unbundled storage costs totaling $21 million were subject to 50% balancing account treatment while storage costs in excess of this amount (i.e., “unallocated” storage costs) were subject to 100% balancing account treatment. Shareholders were at risk for the remaining 50% of the unbundled storage costs. Please refer to the attached spreadsheet provided in Response 3 for the dollar amounts that apply to the ratepayers and shareholders.

RESPONSE 2.3

The balancing account treatment between ratepayers and shareholders for unbundled storage costs and unallocated storage costs effective June 1, 2000 described above in Response 4 remained the same for the years 2004 through 2006. Please refer to the attached spreadsheet provided in Response 2.1 for the dollar amounts that apply to the ratepayers and shareholders.

QUESTION 2.4

Please provide aggregate results of the storage auctions for the storage years 2004-2005 and 2007-2008. Please make the responses consistent with those provided in response to SCGC Data Request 9, Question 9.1, in A.04-12-004. For your convenience, both the request and response are replicated below.

QUESTION: 9.1

Please provide a list of the contracts for storage inventory, injection, and/or withdrawal services that are currently in effect. For each contract, state the following information:

The amount of inventory, injection, and/or withdrawal capacity that is under contract.

The date the contract began.

The date the contract will end.

The contract price in $/dth or other stated terms.

The pricing guideline under which the price was accepted.

The applicable tariff, that is, Large GTBS, reassignment of earlier contract as stated, small customer rollover of GLTS, or other, as stated.

RESPONSE 2.4

See Response 1.3. All contracts were under GTBS.

QUESTION 2.5

According to the non-protected portion of SoCalGas’ and SDG&E’s response to SCGC’s Data Request 4, Question 4.18, in R.04-01-025, SoCalGas did not conduct open seasons prior to storage year 2004/05.

1. Please describe how SoCalGas obtained bids for storage services during each of the storage years 2000/01, 2001/02, 2002/03, and 2003/04.

2. For each of the storage years 2000/01, 2001/02, 2002/03, and 2003/04 please provide the following information about the storage services in aggregate:

1. Total amount of each service (inventory, injection, withdrawal) reserved under one year contracts.

2. Total amount of each service (inventory, injection, withdrawal) reserved under contracts in excess of one year—indicate number of years.

3. Average price for packages of one year firm inventory, injection, and withdrawal services.

4. Maximum price for packages of one year firm inventory, injection, and withdrawal services.

5. Minimum price for packages of one year firm inventory, injection, and withdrawal services.

6. Average price for packages of multi-year firm inventory, injection, and withdrawal services.

7. Maximum price for packages of multi-year firm inventory, injection, and withdrawal services.

8. Minimum price for packages of multi-year firm inventory, injection, and withdrawal services.

RESPONSE 2.5.1

SoCalGas objects to this question on the grounds that it seeks confidential and proprietary trade secrets of SoCalGas. It would cause substantial harm to SoCalGas and its customers if this information were to be publicly disclosed. Without waiving these objections, and subject thereto, SoCalGas responds as follows: SoCalGas would be willing to provide the requested materials as Protected Materials subject to a Protective Order with the same provisions as the Protective Order in R.04-01-025.

RESPONSE 2.5.2

As agreed in the Meet and Confer, here is a general description of the storage negotiating process:

The negotiation process is described in the G-TBS tariff under Special Conditions 8-12. SoCalGas begins by informing the public through informational postings on its website and on Envoy that natural gas storage rights are being offered. Information is provided on the procedure for submitting offers. The customer begins the process by submitting a written offer describing the storage package (inventory, injection, and withdrawal) sought, its term, its price, and a time deadline for the response. The Utility may choose to accept the offer or make a counteroffer. The Utility’s decision on each offer is based on the available capacity, the need to balance the sale of inventory, injection, and withdrawal capacity to minimize the stranding of capacity, the value of storage, and on the ever-changing competitive environment for the storage. When agreement is reached, a contract is sent to the customer for execution.

Discussions of offers/counters can be through phone, email, text messaging, or a combination thereof. Several communications may occur in a single day, or there may be weeks between such communications. Those parties who respond with offers that are well above SoCalGas’ view of the market value of storage at that particular time will usually have their bids accepted—subject to portfolio and other considerations. If SoCalGas has limited amounts of withdrawal (or injection) it may suggest alternative packages that have less withdrawal (or injection) because SoCalGas must try to allocate that withdrawal (or injection) among a myriad of competing offers.

QUESTION 2.6

The current rates under the storage schedules G-LTS and G-BSS are 21.40 cents per therm for annual firm inventory, 9.425 cents per dth per day for unbundled monthly firm storage injection service, and $11.584 per dth per day unbundled firm annual withdrawal service (existing capacity). G-LTS at Sheets 1-2, G-BSS at Sheets 1-2.

1. Are these rates considered to be “cost based”?

2. Was the 21.40 cents per therm rate for annual firm inventory based upon the LRMC of storage inventory adopted in D.00-04-060 at Appendix D, Table 9? For your convenience, a copy of this page has been replicated below.

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2.6.3 Was the 9.425 cents per dth per day injection rate based upon the LRMC of storage injection adopted in D.00-04-060 at Appendix D, Table 9?

2.6.4 Was the $11.584 per dth per day unbundled withdrawal rate based upon the LRMC of storage injection adopted in D.00-04-060 at Appendix D, Table 9?

2.6.5 Why was the tariff rate for withdrawal stated as the annual tariff reservation rate rather than the daily rate while the tariff rate for injection was stated in terms of a daily rate?

RESPONSE 2.6.1

The quoted “rates” are not used for recent G-LTS or G-BSS contracts. Sheet 1 of both tariffs state:

“The Utility has the pricing flexibility to charge different rates than those stated below provided that the reservation charge is no higher than the maximum reservation charge allowed in the G-TBS tariff.”

Although established in D.00-04-060, these LRMC rates under-recover storage costs and are therefore not cost-based.

2005 embedded cost of storage was $100.7 M. See, the attached spreadsheet.

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Further, as illustrated in the table below, the product of the “LRMC rates” times SoCalGas’ storage assets in 2005 produces a storage cost of less than $82 M. The 1999 LRMC rates do not reflect current storage costs.

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LRMC rates from Table 9 in 2.6.2.

RESPONSE 2.6.2

Yes. However, the cheap inventory expansions that established marginal costs in D.00-04-060, such as the cushion projects, have been used. (See Mr. Watson’s BCAP testimony, O-9, lines 4-10). The capital cost of inventory expansions used to generate the 21.4 cents/decatherm was $12 million for a 6.6 Bcf expansion. Mr. Watson’s testimony, Table 12, in R.04-01-025, Phase 2, shows a more current estimate of $20 million for 5 Bcf of expansion, with today’s cost even higher since most of that 5 Bcf expansion has already been used in the Cushion Gas II project.

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RESPONSE 2.6.3

Yes. However, the marginal cost used in D.00-04-060 was actually the cost of maintaining injection capacity, not the much higher cost of expanding injection capacity. (See Mr. Watson testimony O-9, lines 18-26). In 1999, most parties did not perceive a need to expand injection. The higher cost of expanding injection capacity today is described in Mr. Watson’s R.04-01-025 Phase 2 testimony, Table 12.

RESPONSE 2.6.4

Yes. However, withdrawal expansions are more expensive today than when estimated for D.00-04-060. In D.00-04-060 it was estimated that a $15 million investment would expand withdrawal by 200 MMcfd. (See Mr. Watson testimony for 1999 BCAP, O-8, lines 12-26.) In Mr. Watson’s R.04-01-025, Phase 2 testimony, Table 12, Mr. Watson estimates at least $20 million is needed to expand withdrawal by 152 MMcfd. Also, both of these estimates exclude the costs of dehydration, field-piping de-bottlenecking, and mainline expansions that may need to be considered.

RESPONSE 2.6.5

This difference is a historical anachronism that is difficult to explain and does not make sense today. The injection tariff should be made consistent with the withdrawal tariff, which represents the annualized “marginal cost” of the capacity in question. To convert the injection tariff to an equivalent, annualized figure, multiply by the 214 days of the injection season,

214 x 9.425 = $20.169/dthd of injection capacity throughout injection season.

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