Direct Testimony of Dr. Michael Alexander

Transcription

1 Application No.: Exhibit No.: SCE- Witness: M. Alexander, Ph. D (U -E) Direct Testimony of Dr. Michael Alexander Before the Public Utilities Commission of the State of California Rosemead, California December, 00 LAW

2 I. INTRODUCTION Q. Please state your name for the record. A. I am Dr. Michael Alexander. Q. Who are you appearing for in this proceeding? A. I am appearing on behalf of Southern California Edison (SCE). My background and experience appears in Attachment MSA-1 to this testimony. Q. What is the purpose of this testimony? A. My testimony will address: Why Embedded Cost Pricing should be preferred over Scaled Long Run Marginal Cost Pricing 1 Why the Commission should not approve SoCalGas Proposed Replacement for the Peaking Rate, and an alternative to both of these rates. Why the Sempra-wide Electric Generation (EG) rate should be abandoned Whether Cost Allocation Proceedings (CAPs), should be held biennially or triennially 1 1 SCE is also presenting one other witness, Curt Roney, who will discuss the G-SRF tariff II EMBEDDED VS. SCALED LONG RUN MARGINAL COST PRICING 1 Q. Does SCE support SoCalGas/SDG&E s proposal to set its rates based on embedded costs rather than on a long run marginal cost basis such as it currently uses? A. Yes. While SCE generally would support Long Run Marginal Costs based ratemaking if it were done properly, I concur with SoCalGas that an embedded cost allocation is actually closer to an 1 Usually erroneously called simply Long Run Marginal Cost (or LRMC ) pricing. LAW

3 efficient allocation method than the flawed long run marginal cost based methodology that has developed for SoCalGas over the years. Q. Why is that? A. There are a number of practical and theoretical problems with the current long run marginal cost based approach. As a result, it does not send proper price signals, or fairly allocate costs. Q. Does SoCalGas/SDG&E currently charge its customers the long run marginal cost of serving them? A. No, it charges its estimate of the Long Run Marginal Cost (I shall refer to this estimate as LRMC ) multiplied by a scalar. Later in this testimony, I will discuss in more detail the differences between true Long Run Marginal Cost, and the estimates which SoCalGas/SDG&E uses. In addition, SoCalGas collects some customer surcharges (such as the Public Purpose surcharge) on an equal cents per therm basis, which is inconsistent with any Long Run Marginal Cost based theory or methodology. Q. What is the purpose of the scalar? A. If SoCalGas/SDG&E were to charge its customers the calculated LRMC, it would over or under collect its total revenue requirements. In order to recover the entire incurred cost of its operations, SoCalGas divides its total recoverable costs by the amount it would recover if it charged the estimated LRMC rate to each customer. This ratio is called the scalar. SoCalGas/SDG&E charges its customers the scaled LRMC, which I shall refer to as the slrmc. Q. According to SoCalGas, that with one possible exception, no other state uses LRMC pricing. Should that actually be slrmc pricing? I will use the term LRMC only to refer to the number which SoCalGas actually uses for Long Run Marginal Cost based calculations. I will not use it to refer to the true theoretical Long Run Marginal Cost, nor to refer to the scaled Long Run Marginal Cost which results from the Long Run Marginal Cost based calculations of rates. In this testimony, my use of LRMC will probably have a different meaning than the use of most other parties in this proceeding. In the current case it would overcollect by about 0%, see Direct Testimony of Herb Emmrich page line. SoCalGas response to DRA s Data Request PZS1- and to DRA s Data Request PZS1- identifies this state as New Mexico. However, SoCalGas response to DRA Data Request PZS1-, reproduced as Attachment MSA- and calls into page

4 1 1 1 A. Yes. To the best of my knowledge, every party to this proceeding, with the exception of myself, uses LRMC when they are, in fact, talking about slrmc. However, the distinction is very important, and I will endeavor to maintain the distinction between the Long Run Marginal Cost and the slrmc. Q. Mr. Emmrich also states that Cost analysts and economists generally agree that marginal costing principles are based on well-established economic principles. Do you agree? A. Yes, in theory. However, the application of those principals to slrmc as it is practiced in California violates well-established economic principles in a number of ways. Q. Could you give an example? A. Yes. Basic economic theory indicates that prices should be set equal to short run marginal cost. The theory is very simple, if it costs more to produce an additional unit than consumers are 1 willing to pay, then the additional unit should not be produced. On the other hand, if it costs less than the amount consumers are willing to pay, then the unit should be produced. The matching of the price of a good or service to the cost of the good or service results in a proper price signal. Q. Why would economic theory suggest that the price be set equal to the short run marginal cost as opposed to the long run marginal cost? A. In the short run, some costs are fixed and unavoidable. So, the short run marginal cost is the cost, at any given point in time, to produce an additional unit. One wishes to recover as much of the cost as one can in that short run. question whether New Mexico actually uses slrmc pricing, stating, SoCalGas has concluded that California remains the only state to rely on marginal costs for allocation purposes. Direct Testimony of Herb Emmrich page line through page line 1. At a competitive equilibrium, short run marginal costs equal long run marginal costs equal average costs. However, in practice utilities are never at equilibrium. This principal will also prove important later in my testimony, when I am discussing alternatives to the current Peaking Rate. page

5 Q. Would you recommend SoCalGas/SDG&E set prices equal to short run marginal costs? A. No. First of all, due to the lumpy nature of utility investment, the use of short run marginal cost could create an inappropriate level of price volatility, making long run marginal costs better in most (but not all) circumstances, since it is much more stable Second of all, utilities are natural monopolies and have a regulated rate of return, and should, in general, be permitted an opportunity to earn a reasonable profit based on its costs. However, because of economies (or diseconomies) of scale charging at marginal cost would either result in unreasonably large profit or loss. Q. Is this why the scalar is employed? A. Yes. Q. Does economic theory support the use of a scalar? A. Yes, but not in the way it is currently done in California. Economic theory also says that the scalar should be different for each customer class. This is commonly called Ramsey Pricing or the inverse elasticity rule. Q. Please explain. A. Economists recognize that, in situations where there is a monopoly rather than perfect competition, normal equilibrium conditions where price equals marginal cost, are not practical. In such cases, the best pricing strategy from the point of view of (social) economic welfare is to charge customers differently depending upon their elasticity of demand. Q. What is elasticity of demand? A. Elasticity of demand is a measure of the price responsiveness of a customer. A customer which does not respond to price would have a low price elasticity, and a customer which dramatically changes the quantity of a product based on the price charged would have a high price elasticity of demand. Q. And how would the scalar vary depending upon elasticity? page

6 A. The economic theory underlying Ramsey pricing indicates that the less elastic the demand, the larger the scalar should be. More precisely, the scalar should be inversely proportional to the elasticity of demand. Q. In practical terms what would this mean? A. In practical terms this would mean that core customers, whose demand is relatively inelastic (insensitive to price) would have a higher scalar (pay a greater mark-up over the marginal price) than noncore customers who are relatively price sensitive. Q. Is this what the utilities in California do? A. No. When the Commission adopted slrmc pricing, it was concerned that setting the scalar based on elasticity, as economic theory calls for, would result in higher prices for residential customers than it felt would be appropriate from a public policy point of view. Therefore, they decided, as a matter of policy to use the same scalar for all customer classes. Q. Does this result in a problem? A. Yes. The use of uniform scalars results in a sub-optimal allocation of resources. Q. Would SCE support the use of inversely proportional scalars as opposed to the current practice of using the same scalar for each customer class? A. Yes, assuming a scaled LRMC method were used. SCE generally supports setting prices based on solid economic theory, and would therefore prefer use of inversely proportional scalars over the use of a universal scalar. 0 1 However, and probably more importantly, SCE is also concerned about the problems associated with developing good estimates of marginal cost. In light of those problems, SCE would prefer that SoCalGas return to embedded cost pricing, as SoCalGas has proposed. Q. Could you please elaborate on the difference between the actual long run marginal cost and the estimated long run marginal cost? The slrmc allocation methodology was adopted in D.-1-0, with implementation effective June 1, 1 per D page

7 A. No estimate is perfect. But, if that were the only distinction, it would not be worth making. What I am concerned by is far less trivial. The problem that concerns me is that the method of developing LRMCs is fundamentally flawed. Q. In what way is it flawed? A. There are several key flaws. In reality some costs (for example billing) vary with the number of customers and not to the volumes of gas which flow. Others, of course, vary with the volumes of gas that flow, but not with the number of customers. Still other costs vary depending upon the peak volumes flowing regardless either of the number of customers or of the average amount of gas flowing. Generally speaking, however, SoCalGas/SDG&E charges its customers at most a nominal customer charge and primarily recovers its costs on a volumetric basis. This results in a mismatch between marginal costs as charged (LRMC) and marginal costs as estimated. As they say in school, the units don t line up. In many cases, the estimated marginal cost is, in fact, an average incremental cost. This is only theoretically valid if costs are linear over the relevant range. However, SoCalGas is forced to use this crude proxy because of customer classes with small growth rates and the very diverse characteristics of individual customers. There are several other problems with the definition of what the marginal costs such as the use of the New Customer Only (NCO) method, and the use of Replacement Cost Adders, which are mentioned in SoCalGas/SDG&E witness Smith s testimony. The effect of these definitions is to shift the estimates of marginal costs, further undercutting any theoretical underpinnings to the slrmc methodology, as does the way various charges (for example the Public Purpose Surcharge) are passed on in rates on an equal cents per therm basis, rather than a basis which is consistent with See SoCalGas response to DRA s Data Request PZS1- which appears as Attachment MSA-. page

8 the slrmc methodology, creating a patchwork of application methodologies, rather than a straightforward and consistent one. Q. Does DRA have any theoretical objection to the use of embedded cost methodology? A. No, it does not. In fact, DRA recommends that the gas margin be allocated based on the EC [Embedded Cost] method for SDG&E, which is SDG&E s preferred method, Ms. Sabino also states that: This is not to say that the EC cost allocation method adheres less to cost causation principles. Both methods are both [sic] anchored on cost causation principles. The primary difference between the two methods is that the EC relies on actual recorded cost of service while the LRMC relies on the incremental costs to provide the service. If one were to consider a one or two year time horizon, then EC could also provide realistic price signals as they would likely not deviate significantly from actual recorded costs within only such short period. She also admits that: The Commission somehow recognizes this in Finding of Fact # in D.-1-0 where it states Generally, the marginal costs for transmission and storage are higher than the book-valued capital assets while marginal distribution and customer costs are quite close to embedded costs. 1 Q. Does DRA have any objection to the use of embedded cost methodology for the SoCalGas system? A. Yes, but the objection is not based on theory, merely on a desire to lower gas rates for core customers. Ms. Sabino is refreshingly honest when she admits that her objection is that the use of the embedded cost methodology in the SoCalGas territory will allocate a greater share of the SoCalGas base margin to core customers, resulting in higher rates for SoCalGas core customers. 1 And when she admits that she supports the slrmc/nco method because: Direct Testimony of Kelly C. Lee, DRA exhibit DRA-, page 1 line to page line 1. See also Direct Testimony of Jackie Grieg, DRA exhibit DRA-1, page, lines 1-1. Direct Testimony of Pearlie Sabino, DRA exhibit, page line to page line. 1 Direct Testimony of Pearlie Sabino, DRA exhibit, page footnote. 1 Direct Testimony of Pearlie Sabino, page lines -. page

9 the LRMC/NCO results in a clear financial benefit to SoCalGas core customers compared to those in both LRMC/Rental and the EC methods. 1 However, the purpose of a cost allocation proceeding is to allocate costs based on proper economic principles, not merely to find the lowest rates for core customers. Q. Would DRA s proposal reduce energy costs to residential consumers? A. No. While DRA s proposal may, on a relative basis reduce the residential consumer s cost of natural gas, it is likely to raise that same customer s cost of electricity, and that would eclipse any presumed savings. Q. Why is that so? A. DRA s methodology ignores the fact that the higher costs of transportation for natural gas for electric generation raises the market clearing price of electricity, since natural gas is the fuel consumed by the electric generation facilities that typically set the marginal cost of electricity in California. That cost is passed on to residential electric customers in every kilowatt hour of electricity they consume. It is probable, if not highly likely, that those additional costs will, over the course of any given year, swamp any theoretical savings under DRA s proposed methodology. Q. In the case of SoCalGas rates, DRA testimony recommends the use of slrmc based on the 0 1 New Customer Only (NCO) method over the rental method which SoCalGas prefers. 1 you please describe the difference? Could A. Yes. Under the NCO method, the costs of hooking up a new customer are multiplied by the projected number of new customers to come up with a new customer cost. This cost is then divided by the total number of customers (not simply by the number of new customers). Under the rental method, the hookup costs (including carrying charges, taxes, and inflation) are divided by the lifetime of the equipment. 1 1 Direct Testimony of Pearlie Sabino, page lines -. Direct Testimony of Jackie Grieg, DRA exhibit DRA-1, page lines -. page

10 Q. If one divides the number of hookups by the total number of customers, doesn t that underestimate the cost of hookups per customer? A. Yes, it does. The NCO method underestimates the cost per customer by using the wrong denominator. It also underestimates it by ignoring replacement costs for hookups that wear out and it underestimates it by not accounting for the costs associated with financing the hookups over time or of taxes, etc. Q. How does the rate of growth of a customer class affect the estimate of the number of customers under the NCO method? A. It can have a dramatic impact. Let us consider a situation where the cost to SoCalGas of hooking up a new customer is $1,000 per customer, under three scenarios: 1. There are no new customers in the class: In this scenario, there would be no cost for new hookups, and the NCO would estimate a value of zero.. The number of new customers is small relative to the number of existing customers: In this case, a change from, say 1% growth to % growth would nearly double the estimated costs under the NCO method. If the growth rate were 1%, the estimated cost under the NCO method would be ($1,000*1/1) $.0. However, if the growth rate were %, the estimated cost under the NCO method would be roughly twice as high, ($00*/) $1.1.. The number of new customers is large relative to the number of existing customers: In this case, the price estimated by the NCO method would be higher. For instance, if the growth rate were 0%, the NCO estimated cost would be ($00*0/) $., and if the growth rate were 0%, the NCO estimate would be ($00*0/00) $00. Q. What is the actual annual marginal cost of an additional customer? A. Hookups are a durable good. That is, they last for a long, but limited, time. Let us assume for this example that a hookup has a 0 year life. The very simple reality is that every year one 0 th of the hookups will have to be replaced, which says that, if we look at the number of customers the utility has, and multiply that number by $1,000 and divide by 0, we will get the annual page

11 expenditure that the utility has to make on new hookups, which is $ per customer. 1 Every new customer who comes on line increases costs by $ per year, which by definition means they impose a marginal cost of $ per year on the system. 1 The 0 year lifetime limit does not affect the estimates derived under the NCO method. 1 that the NCO method would produce a $ estimate only if growth were.% Note ($1,000*./. = $). Note that if the growth rate were higher than.%, in this example, the NCO method would actually produce an estimated cost which is higher than the true $ cost. Q. Is there a method that would consistently produce a $ outcome, regardless of the number of customers or the growth rate? A. Yes, it is called the rental method. Many people get lost in the name, and try to compare the rental method to renting a property. This is unfortunate. It is easy to hyperextend a metaphor, and lose track of the benefits of the technique. The important thing is that the rental method accurately estimates the incremental cost of serving an additional customer by looking at the full costs imposed over time by each customer. Q. With that in mind, what would the price estimates be under the rental method in each of the scenarios you have posited above? A. All would result in the same estimate of the cost of a hookup. All would produce an estimate of ($1,000/0) $ per customer per year. 1 Thus, under the rental method, the estimated cost to the utility of hookups is consistent with the expenditures imposed on the utility regardless of the growth rate in a customer class. 1 1 unit. 1 I am ignoring carrying charges, taxes, etc. in order to simplify the discussion. The textbook definition of marginal cost being the additional cost imposed by adding (or saved by eliminating) one Hence the name New Customer Only 1 Properly speaking, the calculation is slightly more complicated, as there is a need to adjust for financing, taxes and inflation. page

12 Q. Does the NCO method ignore the cost of replacement? A. Yes. Under the NCO method the entire cost for a customer is estimated based only upon the initial installation of the hookups. The NCO method completely ignores the fact that some hookups must periodically be replaced, and therefore underestimates the costs each customer imposes on the system. Q. Are there any real costs to the utility which the NCO method does not include? A. Yes. Because hookups are a durable good, the utility finances them over time, and incurs financing and carry charges. They must make tax payments based on the return on their investment, and of course, the value changes over time, due to inflation. These are included in the calculation of the marginal cost under the rental method. The NCO method would not capture these costs, and instead would inappropriately distribute them to other customers through the scalar. Q. Some people have claimed that the NCO method is more realistic, because hookups are a one time cost. Do you agree? A. No, I do not. The utility does not charge customers the full cost of a hookup every time one is installed or replaced. They charge customers over the course of the lifetime of the equipment. And the utilities finance the equipment over its lifetime as well. Therefore, the financial cost to utilities is an ongoing cost, and should be modeled as such. Q. What is the implication of misestimating the LRMC based on using the wrong method? A. If LRMC is too low, then the amount of overhead paid for by other customer classes is increased, which, in turn results in a cross subsidy through the scalar. Q. DRA contends that the Commission determined that the NCO method results in just and reasonable rates in D Do you agree? A. I think that is a mischaracterization. SoCalGas entered into a settlement with ORA (now DRA) and other parties 1 in favor of the NCO in that proceeding, and the Commission did accept the 0 Direct Testimony of Pearlie Sabino, DRA exhibit DRA-, page lines -. page

13 settlement. However, a key provision of the settlement was that it would not be considered a precedent. Specifically, the settlement states that: Unless expressly noted otherwise, it is the intention of the Parties that this Joint Recommendation and sponsoring testimony applies for the purposes of this BCAP proceeding only. It is disingenuous of DRA to ignore that provision of the settlement in this case However, more importantly, the Commission in making rates is acting in a quasi-legislative mode and, therefore its past decisions cannot preclude their taking a fresh look at the problem, particularly after years. Q. Are there any other modifications to the proposed cost allocations which DRA recommends? A. Yes. On page of her testimony, Ms. Sabino offers several proposed changes to the cost allocations. I will restrict my comments to two of them: Modifying the Administrative & General (A&G) cost allocation by allocating 0% of A&G costs on the basis of the average year throughput, in particular, on an equal cents per therm basis (ECPT); Modifying the allocation of the remaining 0% of A&G costs based on O&M costs by using the Multi-factor, including the functionalization of FERC Accounts 0 (A&G Salaries), 1 (Office Supplies & Expense), (Employee Pensions & Benefits), 1 (Rents), 0 (Payroll taxes), (AdmGen Mnt- General Plant) and.1 thru (General Plant depreciation) instead of the Labor Factor, and for the general plant returns and taxes functionalization; Q. Why does DRA recommend these changes? A. Merely in order to shift costs from the core customers to the noncore customers. Ms. Sabino admits that DRA has not fully investigated the applicability of the allocators proposed by 1 The Utility Reform Network (TURN), California Industrial Group/California Manufactures Association, Chevron U.S.A. and Texaco Inc. Joint Recommendation of SoCalGas, ORA, TURN, CIG/CMA, SDG&E, Chevron, and Texaco page 1. See California Public Utilities Code, Section. page 1

14 SoCalGas for its EC allocation and reasonable allocation options. It is not appropriate to shift allocations merely to shift costs to another customer class. Therefore, I recommend that these proposed changes not be made. Q. Based on the problems you have identified with the slrmc method what do you recommend? A. I recommend that the Commission order SoCalGas/SDG&E to adopt an embedded cost methodology for pricing natural gas service on the SoCalGas/SDG&E system. However, if the Commission were not to accept my suggestion, I would recommend that a) the Commission adopt an inverse elasticity rule, rather than a universal scalar, and b) the Commission order adoption of the rental method rather than the NCO method III PROPOSED ALTERNATIVE TO THE PEAKING RATE Q. In D Ordering Paragraph (a) SoCalGas was ordered to present an alternative to the peaking service rate (GT-PS). Have they done so? A. Yes. SoCalGas proposed Transmission Level Service (TLS) is an alternative to the peaking rate. In addition to presenting the basic TLS tariff, SoCalGas also proposes that it be permitted to discount the price, if necessary, to compete with other (pipeline) alternatives available to potential bypass customers. Q. Do you support SoCalGas proposed TLS rate? A. No, I do not. I want to emphasize that SoCalGas has done what the Commission ordered them to do. The problem can be daunting and SoCalGas has made a good faith effort. However, there would be serious negative policy implications of enforcing the TLS tariff on EG customers. I shall discuss these policy implications later in this testimony. I shall also present an alternative both to the current peaking rate and to the TLS rate which SoCalGas has proposed. Direct Testimony of Pearlie Sabino, DRA exhibit, page lines -. page 1

15 Q. What is the fundamental problem which SoCalGas peaking rate and its proposed alternative TLS designed to solve? A. Some of SoCalGas customers can take gas either from SoCalGas or from a competing pipeline. If a customer takes all of its gas from one or the other, it may be a simple matter of competition based on price. However, differences in the price structure may cause a customer to take some gas from SoCalGas and other gas from a competing pipeline There is a problem, however, in that SoCalGas currently recovers all of its costs, fixed and variable on a variable cost basis, whereas pipelines tend to recover their costs based on fixed costs and variable costs. This means that SoCalGas tends to have higher rates for an additional unit of gas throughput than it otherwise might (since it is recovering fixed costs in that variable rate) whereas pipelines recover their costs by a combination of fixed and variable rates, which makes the incremental cost of transporting gas on the SoCalGas higher than the incremental cost of transporting gas on competing pipelines. This means that a customer could be tempted to take gas on the competing pipeline, even if the actual economic cost were less on the SoCalGas pipeline. This is called uneconomic bypass. As I will discuss later in my testimony, the Peaking rate and the proposed TLS rate actually make this problem worse if transported volumes exceed the reservation rate Further, because SoCalGas charges its customers an all volumetric rate rather than a mixture of fixed customer rates to cover all of the fixed costs and variable (throughput) rates, if a customer were to bypass SoCalGas for the majority of its gas, using only small amounts of gas on the SoCalGas system, that customer would not pay the fixed (non-volumetric) costs which that customer imposes on the system. Q. How does SoCalGas handle this problem today? A. Should a customer choose to take service from both, SoCalGas would charge them a higher customer charge, a reservation charge, as well as a throughput charge through the GT-PS rate. page 1

16 A. Similarities Between the TLS and the Existing Peaking Rate Q. Could you please summarize your concerns over the TLS rate? A. I have three main concerns about the TLS rate Unlike the Peaking Rate, the TLS will raise rates to some customers whether or not they connect to a competing pipeline The TLS rate will not properly allocate costs. The TLS is not compatible with increasing the amount of electric generation from renewable resources. Q. How does the proposed TLS rate compare with the existing GT-PS rate? A. Actually, the two are very similar. Both consist of two options: 1. a fixed reservation charge, a volumetric charge for gas within the amount reserved by that reservation rate, and a volumetric charge for gas (which will be delivered on an interruptible rate) above that reserved rate, or. An interruptible all volumetric rate which is equal to the volumetric charge for gas used above the reserved volume. In both cases, the volumetric charge (for volumes in excess of any reservation) are very high, and, in fact, exceed the interruptible charge for throughput The fundamental difference between the two is that the Peaking rate would apply only to customers who bypass the SoCalGas system whereas the TLS rate would apply to all customers connected directly to the Transmission line. One might say that the SoCalGas proposal does not eliminate the Peaking Rate, rather it extends the Peaking Rate to all customers, whether they bypass the SoCalGas system or not. Q. Do the existing peaking rate and the proposed alternative send the right price signals to customers? page 1

17 A. No. In both cases the volumetric charge for shipping gas (over and above the reservation level) exceeds the cost to the system. For instance, under the current GT-PS rate, the volumetric costs over the reservation level for large EG customers is 1. /dth (under the proposed TLS rate it would be.0 /dth), however, the GT-I rate (which should include the full incremental cost of shipping gas, plus a component of fixed costs) for those same customers is only. /dth (Similarly, the proposed rate in this proceeding for Large EGs on the Distribution system is only. /dth). Q. What are the implications for economic bypass? A. The fact that the rate for peaking customers or TLS customers exceeds the actual incremental cost of throughput means that the TLS and Peaking rates will actually suppress economic bypass. Q. Please explain. A. A customer will not ship gas on the SoCalGas system if the value of the gas is less than 1. /dth to them or if the cost of gas from the competing pipeline is less than 1. /dth, even though at a rate as low. /dth if the customer were to ship the gas on the SoCalGas system it would benefit both itself and other customers (through a contribution to SoCalGas balanced revenue requirement). Thus, the costs are too high at the margin, encouraging uneconomic bypass and harming both the bypassing shipper and everyone else on the SoCalGas system B. The Adverse Effect of the Proposed TLS rate on EGs and other Low Load Factor Customers Q. Does the TLS rate create problems that do not exist under the existing peaking rate? A. Yes, the GT-PS rate only applies to those customers who choose to use a competing pipeline in addition to the SoCalGas system, but the TLS rate will compound the problem by extending the problem to customers who do not choose to connect to a competing pipeline. Q. How would the TLS rate raise rates to customers who do not connect to a competing pipeline? page 1

18 A. The fixed and variable rate for the TLS will have the effect of raising the rates paid by low load factor customers, such as the EGs. Currently, a customer who has no interest or chooses not to bypass SoCalGas is unaffected by the Peaking rate. However, the proposed TLS rate would negatively impact low load factor customers whether they choose to bypass or not. While there are some high load factor EG customers, the EGs as a class tend to experience a fair amount of variation in their demand and therefore to have lower load factors than other noncore customers, which would raise electric costs and rates throughout the Southern California region In addition, the state is in the process of encouraging the utilities to substantially increase the amount of electricity generated by renewable resources and to decrease electricity use through increased conservation efforts. However, increasing the amount of electricity generated with a fuel other than natural gas and decreasing the use of electricity can be reasonably expected to increase the peaky nature of EG demand for gas, and therefore lower an EG's load factor, which would mean a higher throughput cost for EGs' natural gas fired generation under the TLS rate. Therefore, the practical effects of the TLS rate could well be to create certain financial disincentives which would be inconsistent with California s energy policy. Q. Is the difference between the load factor of electric generation customers and those of other noncore customers significant? A. Yes. While not all customers within a class have the same load factor, if one looks at the annual use in 00, as an example for EG customers and compares it with the annual use for the rest of the noncore customers a dramatic difference is quite evident. EG throughput is quite uneven over the year (showing a low load factor) compared with the other noncore customers. This is also the sentiment of Mr. Schweke. Direct Testimony of Rodger Schwecke, p. 1, lines -. page 1

19 FIGURE MSA-1 Throughput in 00 on the SoCalGas System 00,000 0,000 0,000 00,000 00,000 Large EG Throughput 0,000 00,000,000 0,000 EG load factor = 0. Other Noncore Load factor = 0.0,000 0,000 0,000 Non Core Throughput w/o EG's Lg. EG NC - EG 0,000 - Jan-0 Feb-0 Mar-0 Apr-0 May-0 Jun-0 Jul-0 Aug-0 Sep-0 Oct-0 Nov-0 Dec-0-1 Based on Emmrich's Forecasting Work papers 1 Any pricing scheme which has the effect of charging more per unit of throughput for low load factor customers than for higher load factor customers would raise the rates for EG customers, even if these same EG customers have absolutely no intention of bypassing SoCalGas. Q. Could you please show how this would affect the average cost of service to EG customers? A. Yes. Below I submit a simplistic analysis, based on monthly (for the year 00), rather than daily numbers, using a typical customer, by which I mean that I assume the customer s behavior is the same as the class average. In practice, I would expect that some customers will be closer to the class average, some will have better load factors but most will have a lower load factor than the class average. I will also make the simplifying assumption that the customers perfectly predicted their throughput. This will result in a best case for those customers, but it should do as an illustrative first pass. 1 page 1

20 In order to estimate the effect on customers, one must first estimate how much throughput the customers will reserve on a firm basis. I will start with Rodger Schwecke s assumption that Customers will likely choose to have their baseloads (load levels that occur frequently and/or are almost equal to annual average levels) served by the reservation rate design. They will likely choose to have infrequent, high load levels served by the higher allvolumetric rate. Q. What would the cost of gas be to the typical EG customer under your simplified assumptions? A. The cost of gas would be 0.0 /dth, (0.0/.1 1) 1% higher for an EG customer than the estimated.1 /dth for a non-eg noncore customer. Q. How did you calculate the 1%? A. I looked at the 00 throughput numbers provided in Mr. Emmrich s workpapers. I then calculated the average annual levels of throughput of the EG class and of the remaining noncore customers, which Mr. Schwecke suggested would be the reservation levels chosen. Then, for each month, in turn, I estimated the costs from the reservation levels, the cost of the throughput within that reservation level and the cost of the throughput (if any) in excess of that reservation level. My workpapers appear in Attachment MSA-. Q. Before you go on, do you agree that the base load levels are almost equal to the average annual level? A. No (although I do not believe that the optimum reservation level would be the baseload level either). According to the data provided in Herb Emmrich s workpapers, for 00, the lowest levels (which is how I would define baseload ) for large EGs (on a monthly basis) were,1 dth. The average monthly throughput was 1, dth. Therefore the baseload is about (,1/1,) % of the average. In eight months out of twelve, the monthly throughput was below the average. (See Figure MSA-.) Direct Testimony of Rodger Schwecke, page 1 lines -. page 1

21 FIGURE MSA- Large EG Use, Baseload and Average Throughput Monthly Baseload Average Note that Average (1,) is 1% above baseload (,1) 0 Jan-0 Feb-0 Mar-0 Apr-0 May-0 Jun-0 Jul-0 Aug-0 Sep-0 Oct-0 Nov-0 Dec-0 Based on Emmrich's Forecast Workpapers 1 Q. How does this compare with the ratios for the non-eg portion of the noncore throughput? A. For non-eg noncore customers, as one would expect, there is much less difference between the baseload and the average. The baseload for the class is,1 which is about (,1/0,) % of the 0, annual average. Q. From Figure MSA-1, it would appear that EG demand peaks in the summer, is that correct? A. Yes. Q. Does SoCalGas system demand for transportation peak in the summer? A. No, SoCalGas demand peaks in the winter, as is shown in Figure MSA-. page 0

22 FIGURE MSA- SoCalGas EG and Total System Throughput 00,000 1,00,000 0,000 1,000,000 00,000 00,000 EG Throughput 0,000 00,000,000 00,000 00,000 System Throughput Lg. EG Total 0,000 00,000 0,000 - Jan-0 Feb-0 Mar-0 Apr-0 May-0 Jun-0 Jul-0 Aug-0 Sep-0 Oct-0 Nov-0 Dec-0-1 From Emmrich's Forecasting Workpapers 1 Q. What does Figure MSA- tell us about the proper allocation of costs? A. It tells us that, under a TLS rate, costs would be misallocated, since the TLS rate does not recognize the difference between customer classes. Q. How so? A. The cost of the transmission system is driven by increases in demand which require system pipeline expansions. As we can see from Figure MSA-, the SoCalGas system is generally underused during the summer, which is when EG customers have their peak, and is most constrained during the winter, when EGs are using far less of the system. If EGs were to increase their load, it most likely would not have nearly the effect on the system peak demand that customers with a higher load factor closer to the winter peak would have. Yet, under the TLS rate, the EG customers would pay more, not less per unit of throughput. This is not page 1

23 consistent with cost causation principals, whether through the slrmc or through the embedded cost method. Q. What is the primary reason that EG throughput has such a low load factor? A. Ultimately, EG demand is very sensitive to the needs of residential and small commercial customers. The overall load factor for SCE s system is % whereas SCE s load factor for residential customers is about 0% and for small commercial customers it is about %. This means that SCE s low load factor is due to serving a class very much like SoCalGas core customers and that its costs (which it would pass on to its customers) would rise as a result of serving those customers. Q. Would an increased use of renewable energy for electric generation intensify the problems you mentioned above? A. Yes, as would increased energy conservation because they would worsen the EGs' load factors on the SoCalGas system. Q. How so? A. Any new generation capacity would mean that some plants would run less of the time. Energy conservation would have the same effect. Some plants which are on the margin might cease to run. Other more efficient plants would run less of the time. If a plant runs only part of the time, then its load factor is worse, and that means that, under the TLS, the cost of running that plant would rise, raising electricity costs. Q. Does this send price signals which are consistent with the state s policy of encouraging the use of renewables? A. No, it does not. Q. Does this send price signals which are consistent with the state s policy of encouraging energy conservation? A. No, it does not. Electric, not gas demand. page

24 C. An Alternative to both the Existing Peaking Rate and to SoCalGas TLS Rate Q. Do you have an alternative proposal to present? A. Yes. I have a proposal which I believe provides an alternative to the current peaking rate, is not punitive, and which provides true and proper price signals to the market. Q. Could you please summarize your proposal? A. I recommend that SoCalGas modify the existing peaking rate by establishing a class specific rate for customers connected to SoCalGas and to another pipeline. That rate would be a straight fixed variable (SFV) rate, such that the non-volumetric ( basis margin ) costs were all paid through the customer charge. The volumetric costs would be paid through a rate which would only capture the costs which are incurred by actually flowing gas. In my testimony, I shall refer to this as the G-MSA rate The advantages of the proposed G-MSA over the existing peaking rate and over the proposed TLS rate include: The rate would be class specific, avoiding the potential for class cross subsidies. The rate would be designed to recover SoCalGas costs as they were incurred, from the same class of customers who imposed them on the system. The volumetric portion of the rate would actually be the same or lower than the interruptible rate, therefore, a customer on this rate would have more incentive to flow gas over the SoCalGas system rather than over the competing pipelines, which would lower costs to other customers through the SoCalGas balancing accounts. The rate would make SoCalGas system competitive on the margin with interstate pipelines, all of whom are required to use an SFV rate design. Q. Please compare the G-MSA rate with the existing rate structure. A. As I mentioned earlier in my testimony on embedded and scaled long run marginal cost, some costs (like billing) are actually incurred simply by virtue of the existence of a customer, regardless of throughput, some are incurred by virtue of the customer s peak day use, regardless page

25 of annual average throughput, and some are incurred based upon throughput. Currently, SoCalGas combines these costs together for each class of customers and estimates an average per dth cost and charges that, even though that is not the way costs are actually incurred Under my proposal, SoCalGas would charge customers based on the causes of the costs, charging a customer who is connected to another pipeline a customer charge equal to the costs SoCalGas incurs simply to serve the customer, which would include both the customer based charges (billing and metering) and the costs based on the customer s peak demand on the system (which I shall discuss in more detail below). The customer would then be charged the per dth cost of throughput to SoCalGas. Since these customer costs and peaking related costs are recovered in the fixed charge, the volumetric throughput charge would actually be lower than the average volumetric throughput charge on the system for a customer of the same class which was not on the G-MSA rate. Q. What would you expect to be the effect of this rate on customers who connect to alternative pipelines? A. First, they would be paying the costs they impose upon the system, and no more than those costs. Second, because they would be seeing a lower incremental cost to flow gas on the system, they would be more likely to flow gas on the SoCalGas system instead of on an alternative pipeline, lowering (through the balancing accounts) the cost of gas to other SoCalGas customers. This would not result in uneconomic bypass, since they would be paying the costs they impose upon the system, but it would not curtail economic bypass, since the cost of shipping gas on the SoCalGas system would be the actual cost imposed, rather than a punitively higher rate. Q. How would the rate components for the G-MSA rate be set? A. They would be based on the functionalization of accounts, much as they currently are. The primary difference would simply be that they would not be reallocated and charged on an all-volumetric basis. Thus, the fixed customer charge would include all plant specific costs (meters, billing, line extensions, etc.), and the volumetric charge would essentially be the current page

26 volumetric charge less those plant specific ones. The one point of complication is how the charge for the peak level component for transmission would be set. Q. Why is this a point of complication? A. It is comparatively easy to calculate the cost of metering, billing, and the line extensions from the transmission system to the plant. It is relatively simple to calculate the incremental cost of shipping gas on the SoCalGas system. However, the cost of the transmission system infrastructure is by nature shared and determining the right share is more difficult, and may be as much a matter of art as of science. For a customer who is only hooked up to the SoCalGas system, the allocation techniques are relatively well established. However, for a customer which is partially bypassing the system, the question of what level of responsibility to assign them is less clear. Q. Why is it less clear? A. As an example, let us look at a customer which can burn up to 1,000 dth a day, which is connected to the SoCalGas transmission system and also to another pipeline. Most of the time, this hypothetical customer could be taking gas from the other pipeline, but occasionally, the other pipeline might not have enough gas at a reasonable price (either due to price spikes or basin differentials, or due to limits on the pipeline) to serve the customer s needs. On those occasions, the customer would choose to take gas from the SoCalGas system. The question is, how much of the SoCalGas system should you charge the customer for? One could argue that the customer should be billed for the full 1,000 dth/day of pipeline (reservation) that it might take or one might argue that SoCalGas should bill the customer based on the amount of throughput that it would take on average (a percentage of its 1,000 dth/day maximum throughput which might be difficult to forecast.) Q. Do you have a suggested resolution? The commodity price of gas can vary for different pipelines, and that difference may result in gas from one pipeline looking more attractive than a second one, even if the second one s transportation charge is modestly less expensive.. page

27 A. Yes. The ideal would be to do a peak cold day forecast of throughput by G-MSA customers which are connected to competing pipelines. However, at the current time, there is no history to use to forecast G-MSA use. The situation should be different at the time of the next CAP, but until that time, it seems to me that the idea behind the percentage figure is reasonable, but since there is currently no history of the G-MSA rate to use as a basis for a forecast, a worthwhile compromise would be to set the transmission component equal to the class average transmission component on an all volumetric basis. This would, in practice, bring the cost to an average throughput level. However, since the cost of the transmission system infrastructure is related to the peak level rather than the average level, and since this would not result in a true peaking cost, I recommend that G-MSA customers which are hooked up to another pipeline only be served on an interruptible basis, probably with a lower priority than interruptible customers (GT-I) customers. D. Summary - Recommendation on the TLS and Peaking Rate Q. Based on your analysis, what would you recommend? A. I would recommend that proposed TLS rate be rejected. Instead, I would recommend that SoCalGas offer the alternative service (G-MSA) that I have suggested above to replace the Peaking rate (GT-PS), that it be required for all customers connecting to both SoCalGas and a competing pipeline. The proposed G-MSA rate is class specific, ensures that those who impose costs on the system pay those costs, and discourages uneconomic bypass without discouraging economic bypass. 1 page

28 1 1 IV SOUTHERN SYSTEM FLOW ORDERS Q. Please describe SoCalGas proposed Southern System Flow Order (SSFO). A. SoCalGas is proposing that, when customers are not bringing in enough of their gas through the SoCalGas Southern System on their own, that SoCalGas system operator be able to call a Southern System Flow Order (SSFO) and require SoCalGas customers to deliver a certain portion of their gas into the Southern System. Q. Do you support the proposed SSFOs? A. No, I do not. Q. Please describe the problem which the SSFOs are designed to address. A. Although, in general, SoCalGas system is fully integrated, practical local operating conditions require that a certain minimum amount of gas flow through the southern portion of the system to serve customers on that portion of the line: Riverside, Imperial, and San Diego Counties, and 1 southern San Bernadino Country, etc. 0 Most of the time, enough gas is delivered into the Southern System to meet this need, but on some occasions, historically, not enough gas was delivered to the Southern System. In order to avoid local curtailment, SoCalGas Core Procurement Department made a special effort to buy uneconomic gas and delivered it into the Southern System. Q. Was the Core expected to simply absorb the costs of bringing in additional gas on the Southern System? A. No. The costs for bringing that gas in were booked to the Blythe 1 Operational Flow Requirement Memorandum Account (BOFRMA). Q. Is that the current way low flows on the Southern System are handled today? Historically, this only referred to gas entering the system at the Blythe interconnect, however, it now includes gas coming into the SoCalGas system at Otay Mesa as well. 0 See SoCalGas Response to the nd Data Request of the Indicated Producers (IP-0) question. 1 At the time the memorandum account was set up, Blythe was the only receipt point on the Southern System. page