This section addresses the rules for contracting for service on PG&E's backbone transmission and local transmission system. It describes the contracting rules that were developed in the Gas Accord, and PG&E's proposals to improve its service offerings. For 2004, PG&E proposes that the basic Gas Accord structure for backbone transmission service be retained, and that enhancements be added to improve the service offerings.
The Gas Accord provides rate certainty for standard rates on a non-discriminatory basis, and the flexibility to negotiate transmission and storage rates. In addition, the Gas Accord created tradable rights for both transmission and storage capacity that can be purchased by any market participant.
Under the Gas Accord, PG&E was authorized to market capacity on its intrastate backbone transmission system under Commission-approved tariffs. PG&E agreed to be at risk for the revenues, and any profit or loss from the backbone. No balancing account was authorized.
For local transmission service, PG&E's end-use customers contract for local transmission service as part of their Natural Gas Service Agreement (NGSA).
PG&E's local transmission charges are non-bypassable for on-system deliveries. Although PG&E allows backbone and local transmission services to be contracted for separately, both services apply to all deliveries to all end-use customers located within PG&E's service territory. This structure obligates all customers that flow gas on PG&E's on-system backbone transmission paths to pay for a share of PG&E's local transmission system.
Direct connects to the backbone to avoid local transmission charges within PG&E's service territory are not allowed. In addition, the rules prohibit allowing gas to flow on another backbone service provider directly into PG&E's local transmission system to avoid PG&E's backbone charges. PG&E proposes to retain these same rules in 2004.
For gas producers, marketers, and noncore end-use customers, PG&E's backbone transmission service may be contracted for separately from local transmission services through a Gas Transmission Service Agreement (GTSA). For core end-use customers, a GTSA is not required because backbone service is provided to these customers through capacity holdings assigned to their CPG.
Backbone transmission services and rates are differentiated by path and type of service.
The Redwood Path is linked to Canadian and Rocky Mountain supplies. The Baja Path is linked to Southwest and Rocky Mountain supplies, and the Silverado Path is linked to California supplies. The Mission Path provides access to both PG&E and third party storage facilities in Northern California. A PG&E citygate was created at the connection between the backbone system and the local transmission system. The citygate allows direct gas-on-gas competition among supply basins and storage gas within Northern California. During the Gas Accord, the citygate has become a major trading point. PG&E proposes that the citygate be continued.
Shippers may contract for firm or as-available service on each path of PG&E's backbone transmission system. Firm service guarantees a shipper, in exchange for a monthly demand charge, use of the contracted capacity unless maintenance or some other infrequent event reduces the pipeline's overall capacity.15 Shippers holding firm service can sell their firm capacity rights to other shippers in the secondary market.
As-available service provides capacity when firm rights are not fully utilized, and is subject to interruption depending on how much pipeline capacity is available. As-available service has a lower priority than firm service, and only has a volumetric charge. As-available service requests are ranked by contract unit price, and are assigned capacity from the highest price on down until all the capacity is fully scheduled.
PG&E's on-system service is for ultimate delivery to an on-system end-use customer. On-system delivery points include deliveries to PG&E's local transmission and distribution facilities (PG&E citygate), PG&E's storage facilities, third-party storage facilities located in PG&E's service territory, or end-use or wholesale loads located in PG&E's service territory.
An off-system delivery point is any point of interconnection with an interstate pipeline, third-party pipeline delivering to an off-system customer, or regulated California utility, where the gas being delivered is eventually consumed outside of PG&E's service territory. The off-system designation is specified in a shipper's GTSA. The off-system designation is considered a separate path from the on-system designation, and currently has a separate transportation rate.
PG&E provides backbone transmission services under a variety of standard and negotiated rate schedules. Under the Gas Accord, the standard rate schedule is available to all creditworthy entities at fixed rates and at specific terms and conditions to the extent capacity is available. These standard services are also referred to as default or recourse services. If a customer prefers a rate that is different from the standard rate, then service must be provided under tariffs for negotiated services.
When contracting for standard backbone transmission services, a customer may choose the volume (depending on firm capacity availability), the term, and the rate design, either Modified Fixed Variable (MFV) or Straight Fixed Variable (SFV). Any other variations in rates or terms of service must be arranged under the negotiated services.
Under the Gas Accord, the maximum term for standard service was for the five-year term of the Gas Accord, with certain exceptions. PG&E is proposing to allow shippers the option of subscribing for longer terms of up to 15 years for standard service.
Negotiated services allow a shipper to more closely match its transportation needs, as compared to service under the standard rate schedules. Negotiable rates are available under PG&E's four negotiable backbone transportation tariffs. These four rate schedules are: G-NFT - Negotiated Firm Transportation On-System; G-NFTOFF - Negotiated Firm Transportation Off-System; G-NAA - Negotiated As-Available Transportation On-System; and G-NAAOFF - Negotiated As-Available Transportation Off-System. These tariffs allow for the negotiation of take, term, and price. The "take" refers to variations in the monthly demand charge or "take or pay" requirement. Any other negotiated contract term requires specific Commission approval of the contract.
The Gas Accord also addressed certain terms and conditions of negotiated contracts. PG&E's backbone transportation negotiable tariffs contain a specific provision which ensures that the standard tariff rates and terms are available to all customers in lieu of negotiated rates and terms. The negotiable tariffs also provide that:
"PG&E may distinguish between parties in offering negotiated rates by evaluating differences in circumstances and conditions, including, but not limited to, differences occurring upstream of, downstream of, or at, the Customer's location, and differences affecting either cost of service to the Customer or the Customer's market alternatives. Negotiations with Customers under this rate schedule will be conducted without undue preference or undue discrimination to the Customer or to any third party." (See 73 CPUC2d at 815; PG&E Schedule G-NFT.)
The Gas Accord and the negotiated tariffs also provide that in exchange for negotiable terms, the maximum negotiated rate authorized in the Gas Accord is 120% of the corresponding standard rate for the same service. The price floor for all negotiated contracts is the short-run marginal cost.
A negotiated rate under PG&E's negotiable tariff can be described as a discount from the standard rate or as a premium to the standard rate. A premium to the standard rate occurs when a service feature of the standard tariff has been revised for the benefit of the shipper, and the shipper is willing to pay a higher price for that benefit. The premium rate that is paid provides PG&E with an appropriate incentive to change the service feature.
A discount to the standard rate occurs when service is provided at a price below the standard rate. Discounting occurs when PG&E has a financial incentive to do so. For on-system shippers, PG&E discounts the negotiated rate only when the lower rate would provide an end-use customer with an incentive to use more gas than it would absent the discount. For gas flowing off-system, PG&E's negotiated rate for off-system delivery is priced to provide shippers with an incentive to use PG&E's pipelines as opposed to using interstate pipelines. When a discount is offered, PG&E benefits from the additional volume of gas that is transported on the system.
For backbone transmission services, PG&E proposes to maintain the same basic structure developed in the Gas Accord for 2004 and beyond. The paths, firm and as-available rights, on-system and off-system service, and standard and negotiable services, all would continue subject to the changes proposed below.
For local transmission services, PG&E proposes to continue with the same basic structure developed in the Gas Accord for the years 2004 and beyond. This basic structure obligates all customers that flow gas on PG&E's on-system backbone transmission paths to pay for a share of PG&E's local transmission system. As discussed in the cost allocation section of this decision, PG&E is proposing to segment local transmission rates to better reflect the cost of serving large noncore customers.
PG&E proposes to allow shippers to contract for firm backbone service for up to 15 years for standard firm service. PG&E proposes that the amount of the firm capacity available for such long-term contracts be limited for the period covered by this proceeding to 400 MDth/d on the Redwood Path, and 200 MDth/d on the Baja Path. This represents about 20% of the available firm capacity. The long-term contracting proposal would not apply to capacity assigned for core customer use.
Under PG&E's proposal, those shippers who request long-term firm capacity contracts must agree to pay the standard firm tariff rate. Thus, the long-term contracts will be subject to future rate changes. These shippers are free to participate in any future rate proceedings.
Each long-term contract would be tied to the terms of PG&E's standard firm tariff and GTSA, and be subject to any future changes by the Commission. PG&E proposes to file any agreement longer than five years with the Commission for informational purposes.
When the Gas Accord Settlement Agreement was adopted in D.97-08-055, the Commission added the commensurate discount rule as part of the negotiated rate guidelines. (73 CPUC2d at 784-785.)16 PG&E proposes to maintain this requirement in 2004, but to adjust the rule to remove certain disincentives PG&E is facing in meeting market needs.
PG&E proposes that the tariff language for the commensurate discount rule be changed to the following:17
"Whenever PG&E offers a rate under this rate schedule which is below the tariff rate cap for Schedule G-AFT on its Redwood to On-System path, PG&E shall contemporaneously offer a commensurate discount (i.e., the same penny for penny discount up to the specified quantity and up to the specified term in any discounted contract with any Redwood to On-System shipper) to all prospective shippers for firm service from the tariffed rate cap for schedule G-AFT for the Baja to On-System and Silverado to On-System paths, to the extent capacity is available up to an equivalent volume in aggregate to the discount offered for Redwood to On-System service." (Ex. 1 at 5-12.)
PG&E proposes that a discount be defined as any on-system offer with a rate below the standard firm (G-AFT) rate for a negotiated firm service contract or below the standard as-available (G-AA) rate for negotiated as-available service contract. PG&E seeks this change because it believes the commensurate discount rule should only apply when a contract's rate is below the standard rate. D.97-08-055 interpreted a discount to be any rate offered below the maximum negotiated rate, which is 120% of the standard tariff rate. PG&E believes such a definition of a discount is too restrictive. The negotiated rate cap was intended to allow PG&E to provide additional upward pricing flexibility in a negotiated contract, to encourage PG&E to provide specific services to customers who were willing to pay more than the standard rate. It is not an appropriate benchmark to use for the purpose of defining what constitutes a discount. The unintended consequence is that there is a disincentive for PG&E to reduce the negotiated contract rate below the maximum.
PG&E also proposes to separately offer the commensurate discount for an aggregate volume equal to the volume of the Redwood discount for both the Baja and Silverado paths. This means that if PG&E offers a one-month discount for 10 MDth/d on the Redwood Path, an equal one-month discount would be offered for 10 MDth/d for Silverado Path service and 10 MDth/d for Baja Path service. Resolution G-3288 requires, however, that a discount to a small volume on a Redwood-on contract be offered to all volumes on the Baja and Silverado paths, which results in a very unbalanced incentive structure. Consequently, PG&E declined to offer any on-system discounts for Redwood capacity, even in circumstances where such a discount on a stand-alone basis might be economic and better serve the market.
Scheduling non-performance usually occurs when a shipper submits a large nomination for as-available service at a constrained receipt point, receives a large share of its nomination in the confirmation process, and then only flows a small percentage of the volume that was confirmed. This over-nomination behavior reduces opportunities for other shippers who may have flowed gas if awarded the space. During periods of scarcity, scheduling non-performance can exert upward pressure on the market value of pipeline capacity and increase costs to end-users. Scheduling non-performance can also reduce revenues for the pipeline.
Under the Gas Accord, PG&E developed a process in Gas Rule 21, Section B.4, to levy a noncompliance charge for excessive scheduling non-performance behavior by a shipper. The current process and charge, however, is cumbersome to administer and is not able to manage this over-nomination problem when it occurs.
PG&E proposes to eliminate the current scheduling non-performance language in its tariffs, and replace it with a simpler and more direct process that reduces a shipper's ability to engage in scheduling non-performance.
PG&E proposes to limit the maximum daily contract quantity (MDQ) of any as-available contract for backbone transmission service to the expected usage of that contract by a shipper. Under PG&E's current procedures, a customer, with appropriate credit, can request an as-available contract quantity up to the capacity of the pipeline. For the purposes of this proposal, PG&E defines expected usage as a shipper's highest actual usage in the past 12 months. If a shipper's usage increases, the shipper may contact PG&E to have the MDQ increased. As part of the proposal to manage scheduling non-performance, PG&E also seeks authorization to reduce, on a daily basis, an as-available contract's MDQ to the previous day's actual usage, if scheduling non-performance is occurring.
PG&E believes that shippers on PG&E's transmission system have the potential to use third-party storage to bypass PG&E's transportation charges, should these third-party storage providers connect to a customer owned private transmission or gas gathering pipeline. This could result in the bypass of PG&E's local transmission charge, or the bypass of PG&E's backbone transmission charge. PG&E asserts that as a result of the bypass, other customers suffer economic harm because they end up having to pay for the bypassed charges. PG&E is harmed because it is unfairly deprived of revenues that are needed to provide its services.
PG&E recently filed a complaint case against Calpine, LGS and others in Case (C.) 03-07-031 alleging that bypass has occurred.
Private transmission pipelines, end-use customers and gas gathering facilities that connect to facilities18 owned by a third-party storage operator may be able to bypass PG&E's local transmission charges without PG&E's knowledge. This could occur in the following manner. The private pipeline that connects to a third-party storage facility would be able to nominate gas from PG&E's backbone system for delivery to the third-party storage facility, and then later withdraw the gas directly into the private pipeline for transportation to the private party's end-use facility. Since PG&E would not meter this gas, the customer could avoid PG&E's local transmission charges, customer access and customer class charges, including applicable Commission social and environmental costs and G-SUR charges.
The bypass opportunity is created because deliveries from PG&E's backbone to third-party storage operators are exempt from paying for local transmission and other end-user charges. This exemption was developed under the assumption that the gas put into third-party storage would eventually be delivered to end-use customers through PG&E's pipeline and metering facilities where local transmission and other end-user charges could be measured and billed. Such an assumption would no longer be valid if private pipelines serving their own end-use facilities directly could avoid local transmission charges by flowing their gas through third-party storage facilities.
Backbone bypass could occur if gas-gathering pipelines or new interstate pipelines connect to third-party storage facilities, and then delivery of this gas is through PG&E's transmission system using the zero rate Mission-on path backbone transportation service. Such action would allow a shipper to avoid paying the Silverado Path rate that would have been charged if the gas were delivered directly to PG&E's system.
PG&E proposes that the Commission require all third party storage operators under the Commission's jurisdiction to file a monthly report and to register all pipeline interconnections to its storage facilities. Such registration would establish the identity of the owner of the interconnected private transmission or gas gathering pipeline. The monthly report would summarize the total metered deliveries and receipts at each interconnect, and the total amount of storage gas currently held by the third-party storage operators in storage for all original gas deliveries. The gas delivery may be owned either by the owner of the interconnect or by another party who was sold the gas or took an inventory transfer of the gas.19
If the metered deliveries from the private pipeline to the third-party storage operator are greater than the receipts (deliveries from the third-party storage operator to the private pipeline) plus the amount of gas held in storage, then it should be presumed that the private pipeline owner has chosen to withdraw this gas and delivered it to PG&E under the Mission Path at a zero rate, having never paid for the backbone transportation (Silverado Path) service being used.
If the metered deliveries from the private pipeline to the third-party storage operator are less than the receipts (deliveries from the third-party storage operator to the private pipeline) plus the amount of gas held in storage, then it should be presumed that the private pipeline owner has transported a net amount of gas to their end-use facility. Since this net amount of gas originally traveled to the third-party storage facility on a PG&E backbone transmission tariff, the end-user is obligated to pay the rates under Rate Schedule G-NT or G-EG end-user tariff for that gas.
Depending on the outcome of this calculation, and only if a private pipeline's metered deliveries, receipts and storage inventory are not in balance, PG&E proposes to collect the transportation charges avoided by this customer by billing the owner of the private pipeline or gas gathering pipeline the applicable as-available rate for either Silverado path service or for transmission-level G-NT or G-EG end-user service. If the owner of the private pipeline is not a customer of PG&E, then the Commission should require that the third-party storage provider be responsible for billing the customer and reimbursing PG&E for the services provided by PG&E. The Commission should also require the third party storage provider to include this requirement in its tariffs and place the private pipeline owner on notice that they will be responsible for these charges if their accounts don't balance.
PG&E's bypass proposal is to help enforce the Commission's long-standing rate policy that PG&E's local transmission charges are non-bypassable for all end-users in PG&E's service territory.
Several customers propose that a backbone level rate structure be established in PG&E's service territory. Such a rate structure would allow a customer to connect directly to PG&E's backbone facilities without the payment of any local transmission charges. This issue is discussed more fully in the cost allocation section of this decision.
A related transmission cost allocation issue is PG&E's proposal to establish a four-tiered local transmission rate for noncore customers. This issue is also discussed in the cost allocation section.
PG&E proposes to collect a bypass charge for third party storage service. PG&E asserts that such a charge is necessary in order to ensure that customers that use private pipelines to transport gas either to or from a third party storage field do not avoid paying for local transmission service or backbone transmission service.
CCC/Calpine oppose PG&E's bypass charge. CCC/Calpine contend that this situation no different from their backbone level proposal where a backbone level customer builds a lateral to take service directly from the PG&E backbone system. CCC/Calpine assert that backbone level customers should not be forced to pay for a PG&E local transmission service that they do not use, and customers that take gas from storage using private pipelines should not have to pay for local transmission services that they do not receive.
CCC/Calpine assert that similar reasoning applies to the second scenario where the Mission path is used. CCC/Calpine contend that to the extent the shipper does not use PG&E local transmission service, it should not have to pay local transmission charges. If PG&E is allowed to assess local transmission charges to customers using the zero cost Mission path rate to transport gas to the citygate, CCC/Calpine assert that PG&E is likely to double recover its local transmission charges. First, PG&E will collect local transmission charges from shippers moving gas to the citygate. Second, PG&E will collect local transmission charges from customers who move the gas from the citygate to their end-use facilities.
CCC/Calpine agree, however, that shippers who utilize PG&E's backbone facilities to transport gas to or from third party storage should pay an appropriate backbone level rate. Such a rate, however, should not include any local transmission charges unless the shipper actually receives local transmission service.
CCC/Calpine contend that it is inappropriate to impose a storage bypass charge because this will discourage the use of third party storage by customers. Given the many benefits of third party storage, the Commission should provide incentives to use third party storage, rather than disincentives.
CCC/Calpine oppose PG&E's proposal to offer long-term contracts for up to 15 year. They assert that the proposal has limited practical value to noncore end use customers because it does not offer any rate certainty, and the 15-year term is too long. The only party that would benefit is PG&E because it could tie-up customers for 15 years. This could foreclose potential competition from alternative service providers, while retaining the flexibility to charge any rate that may be approved by the Commission.
CCC/Calpine assert that PG&E's proposal would remove a significant portion of available capacity from the short-term market and make it available only for long-term contracts. Thus, customers will face the risk of either not having short-term capacity available when needed, or the capacity will be available but at a higher price, due to the upward price pressure from a limited supply of short-term capacity.
CCC/Calpine agree with ORA's objection that PG&E anticipates that it will be at risk for the difference between the negotiated contract rate and the tariff rate only until the next rate case. CCC/Calpine assert that PG&E has not presented any explanation, let alone evidence, supporting why it is appropriate that the risk for any shortfall in revenue should shift from PG&E to customers with the next rate case.
CMTA recommends that PG&E's proposal for a 15-year contract be rejected. CMTA contends that the proposal does not offer rate certainty to customers, which customers need before committing to such a long-term. CMTA suggests that the Commission encourage a five-year rate settlement with PG&E for 2005 through 2009. Such a settlement would provide rate certainty.
The California Natural Gas Producers Association (CNGPA) provided testimony on PG&E's bypass proposal. CNGPA takes the position that if the gas never touches PG&E's system, that no backbone or local transmission charges should be owed.
Duke objected to certain aspects of PG&E's proposal to offer optional 15-year contracts for transportation services without the need for Commission approval of each such contract. In PG&E's rebuttal testimony, PG&E clarified that any such long-term arrangements would be optional, and that the capacity affected by any contracts for more than five years would be limited to 400 MDth/d on the Redwood Path and 200 MDth/d on the Baja Path.
PG&E also stated in its rebuttal testimony that it was open to negotiated long-term contracts, but noted that any negotiated rate would need to be tied to current rates. Duke notes that the absence of rate certainty requires the customer to assume the risk of forecast error while the utility benefits by having a firm commitment for whatever future capacity price is charged.
While PG&E's clarifications improve PG&E's proposal, Duke notes that the Commission may want to retain its ability to review contracts with terms of more than five years.
LGS does not oppose a bypass charge under the proper circumstances. However, PG&E should not be allowed to institute a charge based on speculation and anxiety, nor should it be allowed to charge customers for services they do not use. Before a bypass charge is imposed, LGS asserts that there needs to be proof that such a charge is needed, and a complaint proceeding would be more appropriate.
LGS contends that there is nothing in the transcript of this proceeding that points to the existence of bypass. Until bypass is shown, LGS contends it is a waste of the Commission's time and resources to debate such an issue. LGS recommends that PG&E's proposal for a bypass mechanism be denied, or that it be denied as premature.
In the event the Commission decides to look into this issue, LGS suggests that a working group be formed to address the issue. The working group could include PG&E, the third party storage providers, and any customer that PG&E believes may be engaging in bypass. The working group could then provide a report to the Commission, who could then decide what steps to take next.
If the Commission decides to adopt a bypass charge at this time, the Commission should make clear that third party storage providers may collect from PG&E their costs of acting as PG&E's billing agent. LGS is not in the business of billing and collecting for other entities. LGS would have to undertake additions to its systems if it were required to act as PG&E's billing agent. Such charges include LGS's expected return on the investment LGS would have to make in these incremental systems, as well as full reimbursement of other related costs.
PG&E proposes that it be permitted to offer contracts for firm backbone service for up to 15 years for standard firm service. The amount of firm capacity that would be available for up to 15 years would be limited "for the period covered by this proceeding" to 400 Mdth/d on the Redwood path, and 200 Mdth/d on the Baja path. These amounts represent about 20% of the capacity available on the two paths.
NCGC supports the concept of long-term agreements for backbone transmission capacity, but disagrees with PG&E's proposal that shippers who request long-term firm capacity must agree to pay the "standard firm tariff rate" for that capacity. Since the standard firm tariff rate is calculated on the basis of forecasted system load factors, the rate will change as system capacity utilization changes.
NCGC points out that a long-term contract customer assures PG&E of recovery of the revenue requirement associated with the contracted capacity. NCGC contends that pricing should reflect that assurance. Thus, the reservation charge that is billed for capacity held under a long-term contract should be based on the design capacity of the backbone pipeline, rather than the forecasted system load factor. In addition, the industry norm is to base demand charges for long-term capacity on design capacity, such as the demand charges on interstate pipelines.
NCGC contends that PG&E's proposal to impose the risk of system throughput variation on a customer creates the potential for PG&E to over-recover the costs of the transmission system.
ORA contends that the scope of this proceeding is not broad enough to consider all of the implications of PG&E's bypass proposal. Such an analysis must consider the impact on PG&E's revenue requirements. ORA suggests that the bypass proposal be reviewed in a more comprehensive proceeding.
PG&E proposes that it be allowed to enter into negotiated long-term contracts for firm backbone capacity. ORA is concerned about how this proposal will affect the treatment of any revenue shortfall resulting from such contracts. In PG&E's rebuttal testimony, PG&E states that if the negotiated contract rate differs from the tariff rate, that PG&E would expect to be at risk for the difference until the next rate case. ORA contends that this testimony suggests that PG&E expects to pass the risk of any revenue shortfall on other ratepayers. Under the Gas Accord, PG&E is at risk for any revenue shortfall. PG&E has not offered any explanation as to why the risk for the revenue shortfall should shift from PG&E to ratepayers. ORA contends that if PG&E enters into a negotiated long-term contract, that PG&E should remain at risk for the difference between the contract rate and the tariff rate. PG&E should not be allowed to automatically pass the risk of these contracts onto other ratepayers. To do so would eliminate any incentive for PG&E to protect the ratepayers from unreasonable costs associated with such contracts.
PG&E expressed concern in its application about entities using third party storage providers, such as Wild Goose, to effect a bypass of its local and/or backbone transmission charges. PG&E's witness Campbell testified that this could occur in two ways. First, with respect to the potential bypass of local transmission charges, a private pipeline connected to a third party storage facility could nominate gas from PG&E's backbone system for delivery to a third party storage facility, and then later withdraw the gas directly into the private pipeline for transportation to an end-use facility. Since PG&E would not be metering the gas, the customer could avoid PG&E's local transmission charge. The second type of bypass is if a third party pipeline is connected to a third party storage facility, gas could be injected into storage, and then delivery of the gas could occur on PG&E's transmission system using the zero rate Mission path transportation service. This would bypass the backbone transmission charge.
PG&E proposes that the third party storage providers assist PG&E in collecting the revenues which have been bypassed. Wild Goose is not opposed to the implementation of a proposal that compensates PG&E for revenue loss when a customer utilizes PG&E's system in a manner which avoids paying certain charges to PG&E. Wild Goose's parent company has encountered this situation on other pipelines, and has been able to negotiate tariff provisions satisfactory to all parties.
In order to implement such tariff provisions, Wild Goose contends that the methodology used for capturing the bypass revenues must be practical, and that PG&E must not overreach in its efforts to capture bypass revenues. PG&E may be overreaching by insisting that any accounting method must take into account the possibility of trades and exchanges that occur within the storage facility. Wild Goose contends that accounting for trades and exchanges within a storage field is burdensome, and is not needed to make PG&E whole with respect to any potential bypass.
Wild Goose contends that the focus should be on whether PG&E has been kept whole over the transaction cycle. In order to do so, one should assess what has happened at the interconnect between PG&E and the third party storage provider. If the deliveries balance, i.e., PG&E receives the same volume of gas back from the storage facility as was injected into the storage facility, then PG&E has been kept whole with respect to its transportation revenues. The fact that the 100 million cubic feet that went into the facility, is different than the 100 million cubic feet that came out, is irrelevant. Any adopted transmission bypass charge should recognize that such a charge should be assessed on a net basis, rather than transaction by transaction.
An issue that PG&E believes the Commission must address is the current or potential use of third party storage to bypass PG&E's transmission charges. Although PG&E believes that such interconnections are unlawful, PG&E proposes that an appropriate transmission charge be paid whenever there is a bypass of the transmission charges using third-party storage services.
PG&E contends that the bypass can occur in two ways. The first is bypass of local transmission charges. This occurs when gas is moved on PG&E's backbone system to a third-party storage facility, and then is redelivered to an on-system PG&E customer using a private pipeline connected to the storage facility. Under the Gas Accord, all gas that moves on PG&E's backbone system for final delivery to an on-system PG&E customer must pay local transmission charges and other applicable charges. Under the bypass situation, the on-system PG&E customer who uses a private pipeline connected to the storage facility could avoid payment of the local transmission charges because PG&E is not likely to know about the subsequent delivery from the third-party storage facility to the end-use customer.
The second bypass situation arises when pipelines receiving California gas production or new interstate pipelines connect to third-party storage facilities, and the gas is then delivered to PG&E's transmission system using the zero rate Mission Path backbone transmission service. This type of bypass can also occur if a private pipeline connected to the third-party storage facility delivers gas to that storage facility. The bypass can also arise if the gas is transported directly from the gas gathering line into the third-party storage operator's pipeline and then delivered immediately to PG&E's transportation system. These situations allow the shipper to avoid having to pay the Silverado Path rate that would have been charged if California gas production were delivered directly to PG&E's system; or avoidance of the Redwood or Baja rates if interstate gas were delivered through the storage facility to PG&E's system.
PG&E proposes that the Commission authorize PG&E to charge for transmission bypass that occurs through a connection to third-party storage facilities. PG&E points out that neither LGS nor Wild Goose oppose establishing a mechanism to collect the appropriate transmission charges that were bypassed. PG&E proposes that the charge be based on a calculation which measures the net flow between the third-party storage facility and PG&E. Depending on the outcome of the calculation, and only if a private pipeline's metered deliveries, receipts and storage inventory, including inventory transfers or exchanges, are not in balance, PG&E proposes to collect the transportation charges avoided by this customer by billing the owner of the private pipeline or gas gathering pipeline the applicable as-available rate for either Silverado path service or for transmission-level G-NT or G-EG end-user service. In the event the owner of the private pipeline is not a customer of PG&E, then the Commission should require that the third-party storage provider be responsible for billing the customer and reimbursing PG&E for the services provided by PG&E. PG&E recommends that the Commission approve PG&E's proposal in concept, and order LGS, Wild Goose Storage, and PG&E to work together on the necessary agreements, calculation methodologies, and tariff changes to implement the bypass charges.
LGS proposes that it be reimbursed by PG&E for accounting and collection activities if PG&E's bypass charge proposal is adopted. PG&E opposes the reimbursement proposal because the bypass of PG&E's transmission rates provides third-party storage facilities with additional market opportunities, and such costs should be recovered from these market revenues.
Assuming that the Commission approves a backbone level rate, and assuming that a third party storage provider may permissibly interconnect with gas facilities other than those owned by PG&E, which is an issue PG&E contends has not been presented in this proceeding, PG&E would agree with CCC/Calpine that local transmission charges would not apply to deliveries from PG&E's backbone to third party storage, and then to an end-user who utilizes facilities that are owned by the end-use customer.
PG&E contends that the CCC/Calpine suggestion that PG&E would charge twice for local transmission service is mistaken. PG&E states that for deliveries of California production to PG&E using the zero cost Mission Path, PG&E proposes to charge the bypassed Silverado Path transmission rate, not local transmission charges. The local transmission charges would apply to the on system end user that eventually receives the gas.
PG&E asserts that the record clearly demonstrates the potential for bypass using LGS storage facilities. LGS admits that it has at least two interconnections with a private pipeline that could be used to bypass legitimate PG&E charges. PG&E contends that it needs to know whether transmission bypass is occurring, and an accounting process will help monitor and quantify this bypass. PG&E states that the Commission should order that an accounting process be established to verify whether bypass is or is not occurring. If no bypass is occurring, no transmission charges to redress such bypass will be levied. Whether or not bypass is occurring now, PG&E's proposal is simply requesting a date to determine the extent of such bypass, if any, and thus be able to collect the otherwise applicable PG&E transmission charges.
PG&E proposes that shippers be allowed to voluntarily contract for standard firm backbone transmission service for up to 15 years without Commission approval for each contract. Currently, contracts that are five years and longer require Commission approval. (See D.86-12-009 [22 CPUC2d 444, 470-471].) For the period covered by this proceeding, PG&E proposes that the amount of firm capacity for the long-term contracts be limited to 400 MDth/d on the Redwood path and 200 MDth/d on the Baja path. This represents about 20% of the available firm capacity. PG&E contends that the long-term contracts will benefit customers who need long-term gas transportation and supply contracts, and provide assurance that if capacity is needed that it will be paid for by the shippers.
In response to some of the parties, PG&E is willing to look at long-term contracts for 15 years with a negotiated take, term, and price. However, the Commission would need to authorize PG&E to allow it to enter in such negotiated long-term contracts. If such authorization is granted, PG&E would include these contracts in its Negotiated Contract Report that is filed monthly with the Commission.
PG&E points out that allowing contract terms up to 15 years is only another option for the market, and if customers do not value this option, they will not sign such contracts. Some customers, however, may want long-term backbone contracts. These long-term contracts would be at standard rates that are derived using the same rate design as all other standard backbone rates.
PG&E contends that the arguments raised by individual customers that no one would want a long-term contract option without rate certainty are frivolous because a single entity cannot assess the business needs of the whole customer class. PG&E contends that its proposal provides more options to customers. If a particular entity is not interested because it doesn't meet its individual need, that is no reason for the Commission to take the option away from others that might find value in the option.
PG&E does not support NCGC's request for a standard firm rate for long-term contracts that is based on the investment in associated facilities i.e., based on design capacity. Such a requirement would shift costs to customers who have shorter-term contracts. PG&E contends there is no reason to design rates for backbone contracts with terms of 6 to 15 years differently from those with terms of 1 to 5 years.
PG&E states that there is no basis for the argument that the conservative amount of capacity that will be made available for the long-term contract option will be in such high demand that it will require bidders to bid SFV for 15 years to acquire any of this capacity. Several parties have argued in this case that there is no demand for long-term contracts. PG&E believes that the demand will be less than the amount PG&E proposes to offer. PG&E's intent for setting a limit on the capacity available to the long-term option was to provide customers with a mix of short-term and long-term capacity options, not to create scarcity.
PG&E proposes to modify the Commensurate Discount Rule so as to remove certain disincentives that PG&E is facing in meeting market needs. This would be accomplished by making certain changes to the tariff. No party has taken issue with this proposal.
PG&E proposes to eliminate the current scheduling non-performance language in its tariffs, and replace it with a simpler and more direct process that reduces a shipper's ability to engage in scheduling non-performance. Scheduling non-performance usually occurs when a shipper submits a large nomination for as-available service at a constrained receipt point, receives a large share of its nomination in the confirmation process, and then only flows a small percentage of the volume that was confirmed.
PG&E proposes that the replacement process limit the Maximum Daily Quantity (MDQ) of any as-available contract for backbone transmission service to the expected usage of that contract by a shipper. Instead of the current process where a customer can request an as-available contract quantity up to the capacity of the pipeline, PG&E would define expected usage as the shipper's highest actual usage in the past 12 months. PG&E's proposal also calls for it being able to reduce, on a daily basis, an as-available contract's MDQ to the previous day's actual usage, if scheduling non-performance is occurring.
PG&E proposes to maintain the same basic Gas Accord structure for backbone transmission services, as described by PG&E in Exhibit 1.
No one opposes the proposal to continue the Gas Accord structure for backbone transmission services.20 We adopt PG&E's proposal to continue the Gas Accord structure for backbone transmission service. Other proposals that we adopt today, which affect this service, shall also be part of the structure for backbone transmission service.
PG&E proposes to continue the same basic Gas Accord structure for local transmission services, as described by PG&E in Exhibit 1. This includes the obligation of all customers who flow gas on PG&E's on-system backbone transmission path to pay for a share of PG&E's local transmission system.
The only concern that has been raised about continuing the Gas Accord structure for local transmission service is whether customers who are directly connected to the backbone should have to pay the local transmission charges. That issue is addressed in the Cost Allocation and Rate Design section of the decision.
No one else opposes any other part of the proposal to continue the Gas Accord structure for local transmission services. We adopt PG&E's proposal to continue the Gas Accord structure for local transmission service. Other proposals that we adopt today, which affect local transmission service, shall also be part of this structure.
PG&E proposes to allow shippers to contract for firm backbone transmission service for up to 15 years for standard firm service. The amount of firm capacity available for long-term contracts would be limited to 400 MDth/d on the Redwood Path, and 200 MDth/d on the Baja path. This represents about 20% of the available capacity. Under PG&E's proposal, a shipper who requests long-term firm capacity must agree to pay the standard firm tariff rate, which is subject to change in future rate proceedings.
Several parties oppose PG&E's proposal that it be allowed to offer long-term transmission contracts for up to 15 years. They cite several reasons for their opposition. First, there is no rate certainty because the contract is tied to the standard firm tariff rate, which may change in the future. Second, PG&E anticipates that it will be able to raise its rates in these future proceedings for any shortfall that PG&E may experience from the long-term contract. Third, the proposal ties up too much capacity, which will result in higher short-term capacity prices.
PG&E's proposal is strictly voluntary for those customers who need long-term contracts. Before entering into a contract of up to 15 years, a potential customer will consider the available options, and determine whether a long-term contract is in the customer's interest. The uncertainty regarding what the future standard firm tariff rate will be, is just one risk factor the customer will analyze and consider. After analyzing and weighing the options, a potential customer will either enter into the contract or not.
The argument that the rates are uncertain suggests that very few customers will sign up for long-term contracts. If that happens, the concern about tying up too much capacity will not materialize. If the opposite occurs, the 20% limitation should provide customers with sufficient capacity to meet their short-term needs. Any long-term capacity that is not sold, will be used to provide short-term capacity.
Some parties are concerned that PG&E will seek to make up any shortfall that PG&E might experience in a long-term contract by seeking a rate increase. We note, however, that the same customers who voluntarily decide to enter into such long-term contracts, are free to participate in any proceeding which seeks to increase the rate that they are paying.
Given the concerns, and the flexibility that long-term contracts offer to certain customers, we adopt PG&E's proposal to offer long-term backbone transmission contracts for up to 15 years.
PG&E's rebuttal testimony states that it is open to having negotiable long-term contracts of up to 15 years, but the Commission would have to authorize this. Presently, negotiated contracts for up to five years are permitted. We are not prepared at this time to allow negotiated backbone transmission contracts for more than five years. The demand for long-term contracts should be examined before deciding whether negotiated contracts of up to 15 years should be permitted.
The Commensurate Discount Rule was adopted in the Gas Accord. (73 CPUC2d at 784.) The rule requires that whenever PG&E offers a discount on the Redwood path, that PG&E is required to contemporaneously offer a commensurate discount (i.e., penny for penny) to all shippers for similar services on the Baja Path, and on the Silverado Path. PG&E seeks to change some of the language in the rule to remove certain disincentives that it faces when offering a discount.
Currently, the negotiated firm tariff is used as the benchmark for what defines a discount. PG&E proposes that a discount be defined as a rate below the standard firm rate for a negotiated firm service contract, or below the standard as-available rate for a negotiated as-available service contract.
None of the other parties provided any testimony on the commensurate discount rule, or commented on the issue in their briefs.
We have reviewed PG&E's justification for changing the language in the commensurate discount rule. The change allows PG&E to operate with more flexibility with respect to the offering of discounts. We adopt PG&E's proposal to change the rule.
To address the problem of scheduling non-performance, PG&E proposes to limit the Maximum Daily Quantity (MDQ) of any as-available contract for backbone transmission service to the expected usage of that contract by a shipper.21 PG&E's proposal also seeks to reduce, on a daily basis, an as-available contract's MDQ to the previous day's actual usage, if scheduling non-performance continues.
None of the other parties provided any testimony on the scheduling non-performance issue, or commented on the issue in their briefs.
PG&E's justification for this limitation is to reduce overnominations in connection with as-available backbone transmission service. As a result of scheduling non-performance, it reduces the opportunities for other shippers who may have flowed gas if they were awarded the space. The non-performance also reduces revenues from the use of the pipeline.
We adopt 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 an as-available contract's MDQ to the previous day's actual usage, if scheduling non-performance continues.
As described in detail in the Background section above, PG&E proposes that the Commission adopt a requirement that all third party storage operators under the jurisdiction of the Commission file a monthly report, and register all pipeline interconnections to its storage facilities. PG&E also seeks authority to charge for transmission bypass that occurs through a connection to third-party storage facilities.
This proceeding is the forum for adopting a gas market structure for PG&E's transmission system and the applicable rates. The bypass, or avoidance of, Commission-authorized charges is a concern from a revenue standpoint in this proceeding. However, this proceeding is not designed to determine whether bypass of these charges are occurring.
PG&E seeks a solution to remedy a possible problem. However, PG&E has not demonstrated that such a problem exists. PG&E recently filed a complaint case against Calpine, LGS and others in C.03-07-031, alleging that bypass of transmission charges is occurring. That proceeding is an appropriate place to determine whether bypass of Commission-authorized transportation charges is occurring.
PG&E seeks to require LGS and Wild Goose to impose monthly reports and to register its interconnects. The information which PG&E seeks, shifts the burden onto the storage providers to prove something which PG&E has yet to establish is occurring. This initial burden should rest with PG&E instead. PG&E must demonstrate with some certainty that a problem exists before we consider whether reporting and registration requirements should be imposed on LGS and Wild Goose.
The information which PG&E seeks is also a cause for concern. Under PG&E's proposal, the various pipelines connecting to LGS and Wild Goose would have to be identified, and various transactions would have to be reported. Much of this information describes in detail the operations of storage providers who offer a competitive alternative to PG&E's storage services.
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. Should PG&E establish that such a problem is occurring, we will consider taking all necessary and appropriate measures to correct the problem.