REDLINED
Application No: A.0802001
Exhibit No.:
Witness: Steve Watson
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(Filed February 4, 2008)
PREPARED DIRECT TESTIMONY
OF STEVE WATSON
SAN DIEGO GAS & ELECTRIC COMPANY
AND
SOUTHERN CALIFORNIA GAS COMPANY
ON PHASE II ISSUES
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
April 24December 5, 2008
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TABLE OF CONTENTS
Page
I. QUALIFICATIONS 1
II. PURPOSE 1
V. BALANCING SERVICE 4
VIII. IN-KIND FUEL 10
I. QUALIFICATIONS 1
II. PURPOSE 1
III. SOCALGAS’ STORAGE CAPACITIES 1
IV. COST ALLOCATION FOR THE UNBUNDLED STORAGE PROGRAM 2
V. BALANCING SERVICE 4
VI. UNBUNDLED STORAGE ASSETS 9
VII. STORAGE RESOURCE PLAN 9
VIII. IN-KIND FUEL 10
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PREPARED DIRECT TESTIMONY
OF STEVE WATSON
I. QUALIFICATIONS
My name is Steve Watson. I am employed by SoCalGas as the Capacity Products Staff Manager. My business address is 555 West Fifth Street, Los Angeles, California, 90013-1011. I received a Bachelor’s degree in History and International Relations from the University of California, Davis, and a Master’s Degree in Public Policy from the University of California, Berkeley. I have been employed by SoCalGas since 1986. I have worked in Gas Supply, Customer Services, the Strategic Planning and Transmission Capacity Planning Departments. I am currently the Capacity Products Staff Manager, responsible for staff support to our Pipeline Product Manager and Storage Product Manager. Before joining SoCalGas I worked as a natural gas analyst at the Department of Energy. I have previously testified before this Commission.
II. PURPOSE
The purpose of this testimony is to (1) identify SoCalGas storage capacities for cost-allocation purposes, (2) describe new balancing services and the assets needed to provide those services, (3) describe the recommended asset allocation to the unbundled storage program, (4) describe an LRMC-required Storage Resource Plan, (5) and recommend in-kind fuel factors for storage.
III. SOCALGAS’ STORAGE CAPACITIES
Table 1 shows SoCalGas’ storage capabilities at its four storage fields. Based on the data shown in this table, I recommend that SoCalGas’ inventory for cost allocation purposes be increased from 105.6 Bcf to 131.1 Bcf. I recommend that its firm withdrawal capacity for cost allocation purposes be increased from 3125 MMcfd to 3195 MMcfd. And I recommend that firm injection capacity for cost allocation purposes be increased from 803 MMcfd to 850 MMcfd. All of these capacity estimates assume that the incentive mechanism recommended by SDG&E/SoCalGas in this proceeding for unbundled storage revenues is adopted. Without such a mechanism, it would be more profitable for shareholders to reduce available capacities by up to 5% so as to significantly reduce incremental O&M costs in the storage fields.
Table 1: Recommended Storage Capacities
1999 BCAP / 2009 BCAPInventory, Bcf / 105.6 / 131.1
Withdrawal @ 25 Bcf, MMcfd / 3125 / 3195
Injection, MMcfd / 803 / 850
Eighteen Bcf of the expansion have been due to Cushion Projects 1 & 2 at Aliso and LaGoleta.[1]/ Inventory at Honor Rancho and Aliso Canyon has also slowly increased through the production of liquids in those fields.[2]/
In the 1999 BCAP, deliverability at the 25 Bcf level was estimated at 3125 MMcfd. Today, we estimate deliverability at that same inventory level to be 3195 MMcfd. January peak day minimums in the previous BCAP averaged near 25 Bcf. 25 Bcf is the minimum inventory SoCalGas expects through January; therefore, 3195 MMcfd is a reasonable minimum firm withdrawal capacity.
For the 1999 BCAP, SoCalGas estimated that the firm injection rates at high inventory levels was 803 MMcfd, assuming that all the compressors were functioning. Using that same assumption, today’s minimum firm injection capability is 850 MMcfd.[3]/
IV. COST ALLOCATION FOR THE UNBUNDLED STORAGE PROGRAM
The $21 million unbundled storage cost level established in the 1999 BCAP should be re-established at the $27.25 million level shown in Table 27 of Mr. Emmrich’s embedded cost analysis, which shows an asset allocation to the unbundled storage program consistent with the recommended asset allocations SoCalGas is making in the BCAP proceeding for both core storage and new balancing services. If the Commission adopts a different asset allocation to the unbundled storage program, then the cost allocated to unbundled storage should still be consistent with the embedded cost methodology described by Mr. Emmrich. If the Commission adopts LRMC pricing rather than the recommended embedded cost pricing, then the Commission should adjust the scalar in that LRMC method to ensure that storage costs for all customers, core and noncore, are set at the embedded cost of storage. The Utility should not be placed at risk to recover distribution/customer costs associated with the scalar factor in any unbundled storage program. Conversely, it would be inappropriate for distribution customers to subsidize unbundled storage services by allocating anything less than embedded costs to the unbundled storage program. Finally, much confusion on core parity, fully-scaled vs. unbundled storage rates, and other items can be prevented by charging core storage customers the same per unit embedded costs for storage as are allocated to the at-risk unbundled storage program.
At the time of this writing, DRA and SCGC have already proposed that the account include the LRMC scalar on the cost side of the ledger.[4]/ As the Commission determined in D.07-12-019, 50/50 (or any shareholder) sharing of the LRMC scalar would be inappropriate:
“SCGC’s proposed allocation for unbundled storage revenues is predicated on the assumption that the LRMC scalar is fully allocated to the at-risk unbundled storage program. The Commission, however, rejected that approach in the 1999 BCAP proceeding and instead, applied unscaled marginal costs for purposes of allocating risk to shareholders.[5]/
Mr. Emmrich’s testimony shows that the current full embedded cost of unbundled storage is $27 million,[6]/ not more than $37 million (including full LRMC scalar) as SCGC and DRA have suggested using in this account. If the Commission allocates 79 Bcf of inventory to the combined core portfolio, then the embedded costs of unbundled storage would be even lower than $27 million and closer to the $21 million figure determined as the embedded cost level in the 1999 BCAP.[7]/ As mentioned throughout the Omnibus proceedings, LRMC scalars have nothing to do with current storage embedded costs– instead they merely reflect unaccounted-for (under LRMC) distribution and customer costs.
VIII. BALANCING SERVICE
SoCalGas’ current balancing rules work well and SoCalGas therefore is not proposing significant change to those rules. Nevertheless, we propose that the current 10% monthly balancing tolerance be reduced to a 5% monthly tolerance.
SoCalGas recommends changing the 10% tolerance in its monthly balancing rules to a 5% tolerance for the following reasons:
1. This change will help to narrow the regulatory gap and bring SoCalGas’ monthly tolerances more in line with those of surrounding interstate pipelines.
2. Noncore customers do not frequently use more than a five percent monthly tolerance; therefore, it makes sense to reduce noncore customer rates by not allocating balancing assets to them that they do not use. Monthly trading tools make it relatively easy for customers to stay within any tolerance band.
3. A five percent tolerance requires 4-5 Bcf less inventory for monthly balancing that can then be allocated to the unbundled storage function. This, in turn, will reduce transportation rates for noncore and core customers.
Table 2 below compares the monthly tolerances of surrounding interstate pipelines.
Table 2: Monthly Tolerance Levels
Monthly Balancing %PG&E / 5
El Paso / 5
Mojave / 2.5
Kern River / 0
Transwestern / 0
Questar / 2.5
Adopting balancing tolerances more in line with potential competitors will discourage customers from switching their “stable” base loads to competing lines, but then using SoCalGas’ laxer balancing rules for any over/under deliveries relative to that base load commitment to the interstate pipeline. An adjustment to the monthly balancing tolerance will help narrow the regulatory gap on the balancing dimension that will have minimal impact on the majority of customers not considering partial bypass.
The impact of this proposal is minimal because noncore customers do not use the ten percent monthly tolerance they pay for in transportation rates. For example, 5.3 Bcf of inventory is allocated to balancing to allow noncore customers to nominate ten percent more than their monthly burn. Yet, a 3 Bcf allocation would have been sufficient to accommodate noncore month-end transportation imbalances over the critical October/November period in six of the last eight years.[8]/
SoCalGas’ OFO and winter balancing rules work and therefore we are not proposing significant changes to those rules. The institution of interruptible injection and withdrawal rights as adopted in the Omnibus Application will make it easier for customers to balance. On summer OFO days, SoCalGas will no longer totally cut off all “as-available” injection (interruptible injection with a zero price). Instead it will allow customers to meet the new 110% balancing provision by using firm and interruptible injection rights. Interruptible injection on any given day will be prorated according to price. The provision of interruptible injection on summer OFO days will also help to ensure that injection capacity is fully used on those days.
Similarly, under the winter balancing rules, SoCalGas will no longer cut “as-available” withdrawal under the 70 or 90% daily balancing regimes. Instead, it will allow customers to meet the 70% or 90% of burn requirements (or 5-day 50% requirement) by using firm and interruptible withdrawal rights.[9]/ The System Operator will determine how much withdrawal can safely be made available without impinging on system reliability and firm withdrawal customers’ rights. Interruptible withdrawal on these days will be prorated according to price. One minor change SoCalGas proposes to the winter balancing rules is to waive any penalties for underdeliveries during the winter if, at the same time, SoCalGas has called a high OFO. This has occurred during 50%, 5-day balancing periods in early November and late March. It is unnecessary to penalize a customer for underdelivery if, at the same time, SoCalGas is penalizing a customer for overdelivery.
Another change to the balancing rules proposed here is to add a low OFO condition (customer’s supply must be > 90% of burn) that mirrors the high OFO (customer’s supply must be < 110% of burn) condition. Currently, high OFOs are triggered whenever the System Operator forecasts injection use exceeding injection capacity. The low OFO would be triggered any time during the winter when the operator forecasts 80% or more of the withdrawal capacity being used.[10]/ Under this condition, the System Operator must ensure that firm storage customers’ withdrawal rights are not jeopardized; requiring transportation-only customers to deliver 90% or more of their burn will achieve this.
SoCalGas also recommends triggering low or high OFOs based on balancing inventory levels in a manner similar to that employed on the PG&E system. A low OFO would be triggered whenever cumulative monthly imbalances reach – 1 Bcf (zero with 1 Bcf of tolerance). Whenever transportation imbalances are negative, storage customers’ (core and/or noncore) inventory is being confiscated through that imbalance. The institution of a low OFO would ensure this situation is not exacerbated. Also, a high OFO would be triggered whenever imbalances exceed 5.2 Bcf (4.2 + 1 Bcf tolerance) during October-November and total system inventory is >90% of capacity. Imbalance inventory levels over this amount could indirectly confiscate storage customer inventory by denying them the ability to inject their remaining volumes into storage before the winter.
Assuming that the recommendations herein are adopted, the storage assets required for the balancing function are shown in Table 3:
Table 3: Balancing Asset Recommendation
1999 BCAP / RecommendationInventory, Bcf / 5.3 Bcf for 10% noncore / 4.2 Bcf, 5% core & noncore
MMcfd injection / 355 MMcfd, 10% core & noncore / 200 MMcfd, 10% core & noncore
MMcfd withdrawal / 250 MMcfd, 10% noncore / 340 MMcfd, 10% core & noncore
The 4.2 Bcf inventory recommendation for the balancing service represents 5% of average peak October/November sendout (2000-2007) of 82.8 Bcf. (See Table 4) The 200 MMcfd injection recommendation represents the maximum injection that SoCalGas has observed being used for balancing when the 110% summer OFO days were called.[11]/ (See Chart1) The 340 MMcfd of withdrawal recommendation represents 8% of the average peak day observed over the last five years, or 4.23 Bcf (See Table 5) and over 10% of average daily winter demand. Our analysis shows that customers, in aggregate, do not use more than 8 percent of their 10 percent tolerance on high OFO days. We assume the same will be true on low OFO days.
Table 4. Monthly Sendout (MMcf)
Table 5 Peak and Average Winter Day
VI. UNBUNDLED STORAGE ASSETS
Table 6 below shows the assets allocated to unbundled storage assuming that my balancing recommendations are adopted along with Mr. Emmrich’s withdrawal recommendation for the combined core portfolio:
Table 6: Storage Asset Allocations
Total / Core / Balancing / UnbundledInventory, Bcf / 131.1 / 70 / 4.2 / 56.9
Injection, MMcfd / 850 / 327 / 200 / 323
Withdrawal, MMcfd / 3195 / 2225 / 340 / 630*
* These are the firm rights at total storage inventory levels of 25 Bcf or more. Core and unbundled storage withdrawal rights will decline proportionally in the event that total deliverability drops below 3195 MMcfd. Per Rule 30, the core ensures that system inventory remains above peak day minimum inventory levels.
VII. STORAGE RESOURCE PLAN
A best-guess estimate concerning storage investments is needed under the LRMC method to allocate storage costs. SoCalGas intends to test the unbundled storage market need and interest in storage expansions during 2008. If potential customers are willing to pay the incremental cost of expansions (over their choice of contract term) and if the open season volume interest approaches existing unbundled storage capacities, then SoCalGas will expand its facilities.
SoCalGas is currently estimating that it can expand its injection capability at Aliso Canyon (the field that requires the longest period of time to fill) by 150 MMcfd at a capital cost of $48 million.[12]/ There would be no incremental O&M costs associated with this expansion. SoCalGas is currently estimating that it can create a significant amount of new storage inventory at a capital cost of approximately $6 million per Bcf. There would be no incremental O&M costs associated with this new inventory.[13]/ Withdrawal can be expanded by 150 MMcfd for a capital cost of $28 million. This cost is so high that we believe customers will not be willing to pay this cost. SoCalGas is predicting no need to expand withdrawal. Traditionally, the GTBS program has had the most difficulty selling out its withdrawal capacity, even at today’s current low embedded cost levels.