| Promoting Wholesale Competition Through Open Access Services by Public Utilities
Recovery of Stranded Costs by Public Utilities and Transmitting Utilities | Docket No. RM95-8-000 Docket No. RM94-7-001 |
In the NOPR, the Commission stated that all utilities use their own systems in two basic ways:
to provide themselves point-to- point transmission service that supports coordination sales, and to provide themselves network transmission service that supports the economic dispatch of their own generation units and purchased power resources (integrating their resources to meet their internal loads). [426/]
Accordingly, the Commission proposed two pro forma tariffs in Appendices B and C of the NOPR: one for point-to-point service and one for network service. Our goal was to encourage the development of competitive bulk power markets by ensuring that all participants would be able to secure transmission services on a non-discriminatory basis. We attempted in the NOPR pro forma tariffs to articulate the minimally acceptable terms and conditions of service for point-to-point and network transmission service that were required to ensure non-discriminatory transmission service. 427/ We explained that, for the most part, specific pricing provisions were omitted. We asked for comments on whether these tariffs provided a good basis for defining the minimum acceptable non-price terms and conditions of service. 428/
Subsequently, in a June 28, 1995 order, we encouraged public utilities to file open access transmission tariffs as soon as possible. 429/ Tariffs with terms and conditions of service substantively similar to the NOPR pro forma tariffs would become effective without a refund condition, assuming there were no other concerns, e.g., rate issues. We also indicated that these tariffs would be subject to revision based on the Final Rule.
The Commission received many comments on both the point-to-point and network tariffs. Many commenters suggested improvements to the proposed tariffs. Others took issue with how to reconcile various aspects of service under the two tariffs (e.g., cost allocation, service priority, customer rights and obligations). As discussed below, the Commission has attempted to address these concerns in developing tariff requirements for the Final Rule. Importantly, while the Commission has retained point-to-point transmission service and network transmission service as distinct services, the requirements for the two services are now in a single pro forma tariff. 430/ The Final Rule pro forma tariff eliminates many of the differences between the two NOPR pro forma tariffs, provides a unified set of definitions, and consolidates certain common requirements such as the obligation to provide ancillary services. The general terms and conditions of transmission service specified in the Final Rule pro forma tariff should be familiar to all utilities, particularly those that have voluntarily filed open access tariffs based on the NOPR pro forma tariffs.
The Commission believes that the modified, single pro forma tariff, in conjunction with the other requirements, is sufficient to remedy undue discrimination in the provision of transmission services. However, we note that in an accompanying notice of proposed rulemaking in Docket No. RM96-11-000, we are seeking comments on whether a different form of open access tariff -- one based solely on a capacity reservation system -- might better accommodate competitive changes occurring in the industry while ensuring that all wholesale transmission service is provided in a fair and non-discriminatory manner.
We address below the comments received on the NOPR tariff and the specific modifications we have made in the Final Rule pro forma tariff.
Utilities For Improved Transition argues that any generic imposition of detailed tariffs on the electric industry will stifle the evolution of the industry. Rather, it asserts, utilities that supply transmission service should be permitted to apply general principles of comparability in their company- specific tariffs, using terms and conditions of service based on their own particular circumstances and those of their customers.
Utility Working Group wants the final rule to allow utilities to depart from the pricing method implicitly contained in the NOPR pro forma tariffs. It argues that the final rule should recognize that some terms and conditions may not make sense in the context of innovative pricing proposals.
DOE thinks that it is proper to base the tariffs on a familiar and simple pricing method. However, DOE suggests that, in the future, the Commission carefully assess the workability of the contract path model in a competitive bulk power market. DOE suggests that spot or real-time pricing should be considered.
Numerous commenters contend that the NOPR pro forma tariffs are based upon the contract path, embedded cost methodology. According to EEI and other IOU commenters, conforming changes may be needed to various terms and conditions of the tariffs to implement pricing methodologies that are not based upon contract path. These commenters argue that any flow-based model would necessitate different non-price terms and conditions. The commenters generally recognize the technical difficulties of implementing a flow-based model. 431/ These commenters assert that the NOPR pro forma tariffs, as written, are not independent of pricing.
EGA criticizes the assumption underlying the contract path approach, i.e., that the capacities of individual transmission paths can be determined independently and made available to third parties. EGA notes that, in light of the competitive implications associated with transmission pricing, some utilities may propose other non-price terms and conditions suitable for other pricing methods, including power-flow-based tariffs. EGA expresses concern that the pro forma tariffs will be the only type of tariff allowed. EGA believes that the Commission should follow its transmission pricing policy guidelines and not impose a special burden on parties proposing tariffs that differ from the final rule pro forma tariffs, including non-price terms that support alternative pricing methods.
Some commenters also interpret the lack of reference to opportunity cost and incremental cost in the NOPR pro forma tariffs as a rejection of their use. 432/
We agree that non-price terms and conditions cannot be designed independent of pricing and cost recovery. As discussed in detail below, the Final Rule pro forma tariff is intended to initiate open access, with non-price terms and conditions based on the contract path model of power flows and embedded cost ratemaking. It is designed based on the practices and procedures currently used by virtually all public utilities and complements the large number of tariffs already filed with the Commission. The Final Rule pro forma tariff is not intended to signal a preference for contract path/embedded cost pricing for the future. We recognize that the industry, in response to changes in institutions, competitive pressure, and technological innovations, is evolving rapidly. For example, various forms of flow-based pricing are beginning to be considered in conjunction with electronic transmission information systems. We seek to encourage this process and will in the future entertain non- discriminatory tariff innovations to accommodate new pricing proposals. 433/
In response to various comments, we are revising certain non-price terms and conditions where suggested changes either improve the tariff services or reconcile tariff inconsistencies. The nature of these tariff revisions does not appear to have serious cost consequences. The mandated changes are generally compatible with the rate proposals already filed by many public utilities. As discussed in Section IV.H., those utilities will not be required to file corresponding rate changes due to our mandated tariff changes to non-price terms and conditions, although they will be permitted to do so.
The Final Rule pro forma tariff includes specific terms and conditions rather than general principles. By initially requiring a standardized tariff, 434/ we intend to foster broad access across multiple systems under standardized terms and conditions. However, in response to concerns raised by certain commenters, the tariff provides for certain deviations where it can be demonstrated that unique practices in a geographic region require modifications to the Final Rule pro forma tariff provisions. Accordingly, where applicable, the tariff permits the use of alternative non-price terms or conditions that are reasonable, generally accepted in the region, and consistently adhered to by the transmission provider.
Finally, we will allow utilities to propose a single cost allocation method for network and point-to-point transmission services. These principles, as well as other modifications and clarifications to the NOPR pro forma tariffs, are discussed in detail below.
Some commenters believe that load ratio cost allocation is appropriate for network service. 435/ Other commenters argue that load ratio cost allocation is inappropriate, but disagree on the alternative. They offer a variety of other cost allocation and pricing methods.
The most frequent comment is that network and point-to-point services should be priced on the same basis. Florida Power Corp wants network contract demand to be offered and priced on a 12 CP basis. 436/ ConEd and Duke argue that their systems are built and designed to meet a single peak; therefore, they contend that network service costs should be allocated with a load ratio calculation based on annual system peak rather than 12 CP. PSE&G claims that load ratio cost allocation works only if the customer has its own generation. Many commenters propose that "behind the meter" generation and load be eliminated from the network load ratio calculation. 437/
CINergy notes that the transmission provider's monthly load ratio calculation includes its long-term off-system firm service. It proposes that off-system sales be eliminated from the load ratio calculation to enable the transmission provider to offer discounts on long-term service. Alternatively, CINergy proposes that the revenues from these long-term off-system sales be shared with network customers based on their load ratio.
Atlantic City and Allegheny contend that cost allocation for network service should also reflect customers' relative energy use (i.e., not just customers' coincident demand). Consequently, these commenters propose that cost allocation consider the network customer's actual load factor. Allegheny also proposes adding a minimum revenue provision to the load ratio method to recognize cost responsibility for non-peak use. Allegheny further proposes to include an increasing return on equity as available transmission capacity decreases. EEI proposes that cost allocation be based on a customer's non-coincident peak demand.
Lower Colorado River Authority proposes using load flow studies to determine planned use during the system peak with MW- mile billing units. It believes that this pricing method should be used for all transmission service to ensure comparable transmission pricing. Oklahoma G&E wants cost allocation to be based on the impacted MW-mile method, or alternatively, to determine embedded cost by voltage level. Centerior proposes the use of actual transfer capability instead of contract path capability in determining cost responsibility.
Orange & Rockland recommends some form of a "poolco" approach using locational marginal cost pricing. DOE also recommends using location-specific spot pricing (a form of marginal cost) for operating and congestion costs.
Public Generating Pool believes that load ratio share pricing is unworkable in the Pacific Northwest, in part because generation is generally located outside of the control area directly served by parties in the Northwest, and in part because BPA, which does not have a typical service territory, dominates the regional transmission market. Seattle states that cost allocation based solely on demand is inappropriate for systems that consist predominantly of hydro generation. 438/
AEC & SMEPA and NRECA are concerned about pancaked rates for network service that is provided to load served by more than one network tariff. Other commenters advocate use of some form of regional pricing. 439/ American Wind proposes the use of a complex seasonal calculation, which appears to benefit wind energy. NY Com and Missouri-Kansas Industrials also express a preference for seasonal pricing models.
We conclude that the load ratio allocation method of pricing network service continues to be reasonable for purposes of initiating open access transmission. Network service permits a transmission customer to integrate and economically dispatch its resources to serve its load in a manner comparable to the way that the transmission provider uses the transmission system to integrate its generating resources to serve its native load. Because network service is load based, it is reasonable to allocate costs on the basis of load for purposes of pricing network service. This method is familiar to all utilities, is based on readily available data, and will quickly advance the industry on the path to non-discrimination. We are reaffirming the use of a twelve monthly coincident peak (12 CP) allocation method because we believe the majority of utilities plan their systems to meet their twelve monthly peaks. Utilities that plan their systems to meet an annual system peak (e.g., ConEd and Duke) are free to file another method if they demonstrate that it reflects their transmission system planning. Moreover, we recognize that alternative allocation proposals may have merit and welcome their submittal by utilities in future rate applications. They will be evaluated on a case-by-case basis and decided on their merits.
As to the concerns raised by AEC & SMEPA and NRECA about pancaked rates for network service provided to load served by more than one network service provider, we have stated that if a customer wishes to exclude a particular load at discrete points of delivery from its load ratio share of the allocated cost of the transmission provider's integrated system, it may do so. 440/ Customers that elect to do so, however, must seek alternative transmission service for any such load that has not been designated as network load for network service. This option is also available to customers with load served by "behind the meter" generation that seek to eliminate the load from their network load ratio calculation.
As noted, the most frequent comment is that the network and point-to-point services should be priced on a similar basis. This concern is addressed in the next section.
Commenters express concern that, if annual system peak capability is used to determine rates for point-to-point service and 12 CP is used to allocate costs for network service, point- to-point service may be underpriced relative to network service. 441/ Therefore, many commenters propose pricing both services on the same basis.
EEI argues that flexible point-to-point service provides a premium service at a discount price. Therefore, EEI would increase the price unless the Commission either (1) eliminates the flexibility or (2) allows network customers to make non-firm sales at no additional charge. It recommends use of 12 CP for pricing both network and point-to-point service, but would credit point-to-point revenues to the cost of service for network and native load to avoid over-collection from contract demand point- to-point users. Alternatively, EEI contends that point-to-point service could use annual system peak capability pricing with a ratchet, 442/ although EEI believes that 12 CP reflects the premium nature of long-term transmission. Under this alternative method, EEI notes that long-term non-flexible point-to-point service would use annual system peak pricing, while short-term service should be based on "up to" (ceiling) rates. In essence, EEI proposes a two-tier point-to-point service, with the first tier (flexible service) of equal priority in all respects to network service. 443/ Ohio Edison also claims that, as proposed, flexible point-to-point service is a more valuable service than network service because it would be priced lower than network service. To correct for this difference, Ohio Edison would impose a separate rate for point-to-point non-firm use.
According to NRECA, unless the same measure of demand is included in the calculation of network and point-to-point charges, actual revenue from these two firm services will be greater than the actual cost of service. FL Com believes that flexible point-to-point service allows a transmission customer to engage in network economy transactions without incurring a full network charge, thus gaining an advantage over the transmission provider. Atlantic City recommends that the Commission either (1) eliminate the flexibility of point-to-point service or (2) price such service on a 12 CP basis. It claims that the use of an annual system peak capability creates a higher value service at a lower cost than network service. Based on its 1994 system data, Atlantic City claims that there is a 33 percent difference in rates between network and point-to-point services. Atlantic City also opposes the requirement to offer point-to-point service on an hourly basis, claiming that, unlike the point-to-point service customer, native load and network service customers are responsible for system investment year-round. Atlantic City also argues that point-to-point customers should pay for all non-firm use, i.e., the Commission should eliminate the flexible nature of firm point-to-point service. PSE&G argues that point-to-point service should be used only for through-flow or out-flow transactions with all other transactions treated as network service. Thus, according to PSE&G, point-to-point service would not need flexibility.
If an annual system peak capability is used, Oklahoma G&E would redefine point-to-point service to eliminate the flexibility. FPL recommends either eliminating the flexibility to nominate secondary receipt and delivery points and receive non-firm service between them or pricing point-to-point service as premium service (i.e., at a higher price than network service). Florida Power Corp claims that flexibility should be associated with network service, not point-to-point service. It also argues that revenues from point-to-point service should be credited against total transmission costs. It would similarly exclude point-to-point demands from the derivation of the network rate. Utility Working Group claims that if flexible point-to- point service is retained, such service should be priced at a higher (unspecified) rate or the non-firm secondary use should be separately priced. It believes that all users should pay for non-firm use, or if there is no additional charge under the point-to-point tariff, network customers and the transmission provider should be treated equally. SMUD argues that a user who does not want flexibility should have an option to elect a lower- priced non-flexible point-to-point service.
We agree that pricing both services on a consistent basis may be appropriate. Consequently, we will allow a transmission provider to propose a formula rate that assigns costs consistently to firm point-to-point and network services. While not requiring the use of any particular rate methodology, we will no longer summarily reject a firm point-to-point transmission rate developed by using the average of the 12 monthly system peaks.
Our previous rationale for not using the average of the twelve-monthly peaks as a denominator in the development of non- customer specific transmission rates was enunciated in Southern Company Services, Inc., 61 FERC _ 61,339 (1992) (Southern). In Southern, the Commission was concerned that establishing a system-wide, non-customer specific transmission service rate that did not appropriately account for diversity 444/ among various transmission customers might result in the over-recovery of revenues for point-to-point service. Inherent in our ruling in Southern was the understanding that once a sufficient pattern of customer usage under the tariff was established, the company was free to file a customer-specific rate using the average of the 12 monthly system peaks for cost allocation. We still believe that it is appropriate for utilities to use a customer- specific allocated cost of service 445/ to account for diversity, but based on the changed circumstances since Southern (which we discuss below) we will now permit an alternative.
We also note that the circumstances in Southern are distinguishable from those now present in the industry. Southern proposed a rigid, inflexible firm point-to-point transmission service where the customer paid separately for each delivery and receipt point combination. The only flexibility permitted was to use alternative receipt and delivery points on a non-firm basis at no additional charge. As the name implies, the flexible nature of the point-to-point transmission service proposed in the NOPR is more akin to the service provided to native load and network service customers. Contrary to what was proposed in Southern, point-to-point service does not require separate charges for each firm service receipt and delivery point combination. Rather, customers pay on the basis of the higher of the total delivery points or total receipt point combination. Flexible point-to-point transmission customers continue to be able to access alternative receipt and delivery points on a non- firm basis without additional charges (as long as they remain within their capacity reservation). In addition, firm point-to- point customers can reassign and resell unused portions of their reserved firm capacity to third parties. With flexible firm and non-firm point-to-point transmission service, the transmission provider must make firm point-to-point transmission capacity available to the customer regardless of its load characteristics or use.
For these reasons, we will allow all firm transmission rates, including those for flexible point-to-point service, to be based on adjusted system monthly peak loads. The adjusted system monthly peak loads consist of the transmission provider's total monthly firm peak load minus the monthly coincident peaks associated with all firm point-to-point service customers plus the monthly contract demand reservations for all firm point-to- point service.
The flexibility and reassignment rights of this transmission service require the transmission provider to hold the firm contract capacity available regardless of the customer's own load characteristics or its actual use. In other words, a transmission provider's obligation to plan for, and its ability to use, a transmission customer's reserved capacity is clearly defined by that customer's contract reservation. For these reasons, it is appropriate to consider a firm reservation as the equivalent of a load for cost allocation and planning purposes.
In order to prevent over-recovery of costs for those who use this approach, we will require transmission providers to include firm point-to-point capacity reservations in the derivation of their load ratio calculations for billings under network service. In addition, revenue from non-firm services should continue to be reflected as a revenue credit in the derivation of firm transmission tariff rates. The combination of allocating costs to firm point-to-point service and the use of a revenue credit for non-firm service will satisfy the requirements of a conforming rate proposal enunciated in our Transmission Pricing Policy Statement. 446/
EEI and IOUs generally support the notion that transmission customers should pay some form of opportunity cost when transmission is constrained and request that the final rule clearly define redispatch and opportunity costs. These commenters generally agree that the final rule should codify these terms consistent with recent Commission orders addressing opportunity costs.
Duke requests that the final rule clarify that the transmission customer should pay all the opportunity costs associated with modified dispatch. Centerior argues that redispatch costs include consideration of parallel flows and scheduled deliveries, which, according to Centerior, cause redispatch costs to be incurred.
Florida Power Corp and NYSEG state that redispatch costs should be either rolled in or charged on an incremental basis, consistent with the Commission's "or" pricing policy. Florida Power Corp recommends that an opportunity cost recovery provision be added to the "Rates and Charges" sections of the tariffs. NYSEG recommends that the tariffs implement the Commission's recent ruling in Florida Power & Light Company, 66 FERC _ 61,227 (1994), allowing lost opportunity costs to be recalculated annually. NYSEG believes that: (1) redispatch costs should be collected for any period in which the transmission customer causes a constraint, including the period of time it takes to construct incremental facilities necessary to alleviate the constraint; (2) network customers should be responsible for any opportunity costs incurred as a result of their non-firm use of the system if such costs rise to a level above their load ratio share of system costs; and (3) point-to-point customers should be responsible for any opportunity costs incurred as a result of their non-firm use of the transmission provider's system up to their reserved firm entitlement. Ohio Edison believes that, given the unique nature of network service, it is inappropriate to require network service customers to incur redispatch costs in order to create additional capacity. PECO requests that the final rule clearly indicate (1) from whose perspective "least cost" redispatch is judged and (2) that the "least cost" redispatch obligation is subordinate to reliability.
Concerned that transmission providers could manipulate the calculation of redispatch charges to increase profits, NRECA proposes that transmission providers develop formal redispatch protocols that would be provided to all customers. NRECA argues that all information necessary to calculate redispatch costs should be made available on the RIN. Customers assessed redispatch charges should be provided with all the necessary information to evaluate such charges, including full audit rights. NRECA, Cajun, and PacifiCorp object to the inclusion of "lost opportunity" costs in redispatch charges. NRECA proposes that only actual non-firm sales or purchases should be included in the calculation of opportunity costs.
United Illuminating and Seattle state that all opportunity costs should be assessed to short-term and non-firm transmission service customers that cause the transmission provider to redispatch its generation to unload a constrained transmission line. According to United Illuminating, it is not appropriate to roll opportunity costs into the rates charged other transmission users because existing users do not have the choice to pay the opportunity costs or to allow their transaction to be curtailed.
UtiliCorp, on the other hand, states that all "out of rate" uneconomic dispatch costs should be rolled in and recovered from all users of the transmission system. UtiliCorp argues that directly assessing these costs to a particular customer would unfairly penalize a customer who could not gain access to a system until after the tariffs take effect.
CCEM argues that only lost opportunity costs associated with the loss of firm purchases or sales should be recoverable. CCEM also believes that the transmission provider should calculate the redispatch costs in advance and transmission customers should be able to opt out of redispatch if costs rise above a certain level.
We will retain redispatch provisions in the Final Rule pro forma tariff, but clarify that redispatch is required only if it can be achieved while maintaining reliable operation of the transmission system in accordance with prudent utility practice.
We find that the recovery of redispatch cost requires that: (1) a formal redispatch protocol must be developed and made available to all customers; and (2) all information necessary to calculate redispatch costs should be made available to the customer for audit.
As discussed in the Section IV.H., the Commission is according substantial flexibility to public utilities to propose appropriate pricing terms, including opportunity cost pricing, in their compliance tariff. However, as with any compliance filing, the rates proposed must meet the standards for conforming proposals in the Transmission Pricing Policy Statement.
In Northeast Utilities and Penelec, we fully explained our rationale for allowing utilities to charge opportunity costs. 447/ We concluded that a public utility is entitled to full compensation for all "legitimate" and "verifiable" costs it incurs to provide firm transmission service. 448/ We explained that where a utility can demonstrate that additional opportunity costs are incurred as a direct result of providing transmission service, our pricing principles would permit recovery of those costs. The Commission further explained in the Transmission Pricing Policy Statement that when transmission capacity is constrained and a utility does not expand capacity, we have allowed the utility to charge transmission customers the higher of embedded costs or legitimate and verifiable opportunity costs, but not the sum of the two (i.e., "or" pricing is permitted; "and" pricing is not). The opportunity costs are capped by incremental expansion costs. 449/
Transmission providers proposing to recover opportunity costs must adhere to the following requirements:
If the transmission provider proposes to separately collect redispatch costs on a direct assignment basis from a specific transmission customer, we will require that the transmission provider credit these revenues to the cost of fuel and purchased power expense included in its wholesale fuel adjustment clause.
ELCON argues that direct assignment of 100% of the costs of expanding a constrained transmission system to a particular customer is unfair. NY Energy Buyers believes that the costs of expanding the transmission system should be shared among all customers seeking transmission service. Alternatively, NY Energy Buyers states that if direct assignment of system expansions is adopted, such costs should be payable both by new wholesale customers and by new retail load. According to NY Energy Buyers, it would be preferable for the utility to treat all requesters during a given period as making one request for a large increment of capacity, with all requesters paying the same average incremental cost. New native load also should be considered to be a requester of transmission capacity and allocated an appropriate share of any expansion costs.
CA Energy Co believes that incremental pricing will discriminate against all later competitors by charging higher rates. It advocates rolled-in pricing with the requirement that all users requesting system expansion commit to service for a term that will cover their proportionate expansion cost assignments.
FPL proposes that costs associated with normal load growth and the repair and/or replacement of older facilities be rolled in with the other embedded transmission costs and shared on a load ratio basis. However, it believes that transmission expansions associated with the addition of a new resource should be separately assigned.
On the other hand, Orange & Rockland maintains that unless expansion costs are directly assigned, an unfair subsidization will occur. According to PECO, transmission customers should be assigned costs for system upgrades under both the network and point-to-point tariffs. Consumers Power claims that the network tariff is unclear about which facilities are directly assignable, and proposes that all costs that exceed the embedded average cost qualify for direct assignment.
SMUD requests that the final rule clarify that if a transmission customer invests in incremental facilities, it will be entitled to ownership-like rights to the capacity addition.
In order to avoid possible argument over the necessity and cost of system expansions for a particular transmission request, NIEP requests that the final rule require utilities to use a "least-cost" approach to transmission expansion that includes comparable transmission expansion practices for all wholesale customers.
According to Duke, the concern that the transmission provider's retail customers will retain an advantage by having expansion costs placed on third parties is misplaced. Duke argues that, under "or" pricing, the issue of who is responsible for expansion costs would still arise. It contends that the Commission will have to decide on a case-by-case basis whether expansion costs are incurred for the benefit of a specific party or are part of overall network costs. Duke generally supports the current "or" pricing policy.
Citing the Commission's Transmission Pricing Policy Statement, FL Com supports the flexibility of charging both embedded cost and incremental cost transmission rates, i.e., "and" pricing. It argues that, because of the dynamic and interconnected nature of the transmission system, tariff customers causing expansion costs should be held responsible for both the incremental cost of the addition and some portion of the existing transmission system needed to support the addition. FL Com states that the comparability standard is at odds with the Commission's non-conforming transmission pricing policy, particularly with respect to "and" pricing.
Under the Final Rule pro forma tariff, we will allow transmission providers to propose any method of collecting expansion costs that is consistent with our transmission pricing policy. We disagree with ELCON's assertion that directly assigning the costs for expanding a constrained transmission system is necessarily unfair. As we stated in Northeast Utilities, if the cost of expansion is directly attributable to a customer's request for transmission service and the expansion would not be undertaken "but for" that customer's request, then it is reasonable to assign the cost of expansion to that customer. If we were not to allow the direct assignment of expansion costs to the customer causing the expansion, then other customers would subsidize the new customer's use of the transmission system. We continue to believe that "or" pricing sends the proper price signal to customers and promotes efficiency. Under the tariff, any assignment of future expansion costs must meet the standards for conforming proposals in the Transmission Pricing Policy Statement. Recovering expansion cost based upon "and" pricing will not be allowed.
Any request to recover future expansion costs will require a separate section 205 filing. The Commission will evaluate, on a case-by-case basis, who is responsible for expansion costs in those filings and whether direct assignment of those costs is appropriate.
Most commenters agree that the Commission must clearly define when a network customer's transmission facilities warrant a credit from the transmission provider. Several commenters state that customers must bear the burden of demonstrating that their facilities are used by and useful to the transmission provider, provide direct benefits, and support the operation of the transmission system. 450/ EEI cautions against providing a credit for facilities that may be integrated with, but of no effective benefit to, the operation of the bulk power system.
The costs associated with customer-owned facilities that are used by the transmission provider should, in PECO's opinion, be recovered from the transmission provider under the customer's own transmission tariff.
FPL cautions that the position of certain parties that transmission facilities warrant a credit if they would have been included in the transmission provider's rates could produce absurd results. It claims that it could actually end up paying a network customer with substantial transmission investment for the right to provide that customer service. FPL contends that it will receive absolutely no service from its network customers because FPL would not need, nor could it use, any of the customers' transmission facilities to integrate FPL's loads and resources. FPL argues that crediting under the so called "rate base" test obligates the transmission provider to purchase a load-ratio share of the customer's transmission facilities. FPL states that, under network service, the transmission provider and the network customer will not create a single system.
AEP recommends that a network customer receive a credit if its transmission facilities meet the following criteria: (1) at points of interconnection, there must be a through-flow of power from the network customer's system to the transmission provider's system under normal operating conditions; and (2) the customer's facilities must: (a) increase the transfer capability of an interface on the transmission provider's system; (b) provide an alternative path for power flows during transmission facility outages, thus increasing the reliability or stability of the combined system; or (c) otherwise satisfy the transmission provider's planning criteria for the installation of network facilities.
WP&L argues for a broader standard and states that a transmission customer should be entitled to a credit if the transmission owner would have installed similar facilities to provide service for its own native load under similar circumstances. Florida Power Corp states that the credit for each facility should be determined on a case-by-case basis.
PacifiCorp argues that a utility may take advantage of the transmission credit and shift major transmission investment onto another transmitting utility and its transmission customers by simply becoming a network customer. PacifiCorp claims that such a situation may, for example, exist for BPA as a transmitting utility. According to PacifiCorp, preliminary studies indicate at least one potential network customer may be entitled to a transmission credit which would exceed that customer's charges for BPA's network integration service.
APPA, Blue Ridge, and Cajun maintain that a customer's facilities should be evaluated on a basis comparable to the facilities included in the rates of transmission providers in a region. APPA argues that a claim that the transmission customer's facilities do not benefit the transmission system must be weighed against the fact that some facilities included in the transmission provider's rate base may not directly benefit the transmission customer. Cajun advocates setting clear standards for the identification of customer-owned transmission facilities eligible for crediting and clear guidelines for determining the amount of the credit.
SMUD not only supports the credit under the network tariff, but also would extend the credit to facilities used to complete a transaction under the transmission provider's point-to-point tariff.
Because of the diverse concerns raised by the commenters, we are unable to resolve on the basis of this record the extent to which, or under what circumstances, cost credits related to customer-owned facilities would be appropriate under an open- access transmission tariff. We conclude that such credits are more appropriately addressed on a case-by-case basis, where individual claims for credits may be evaluated against a specific set of facts.
We stress that while certain facilities may warrant some form of cost credit, the mere fact that transmission customers may own transmission facilities is not a guaranteed entitlement to such a credit. The presumption of many commenters that a customer's subscription to transmission service somehow transforms the provider's and customer's systems into an expanded integrated whole to the mutual benefit of both is not a valid one. As we ruled in Florida Municipal Power Agency v. Florida Power & Light Company (FMPA), it must be demonstrated that a transmission customer's transmission facilities are integrated with the transmission system of the transmission provider. Specifically, we stated that:
The integration of facilities into the plans or operations of a transmitting utility is the proper test for cost recognition in such cases. The mere fact that a section 211 requestor has previously constructed facilities is not sufficient to establish a right to credits. [451/]
The fact that a transmission customer's facilities may be interconnected with a transmission provider's system does not prove that the two systems comprise an integrated whole such that the transmission provider is able to provide transmission service to itself or other transmission customers over those facilities - a key requirement of integration. 452/ We also note that consistent with our ruling in FMPA, if a customer wishes not to integrate certain loads and resources, and thereby exclude them from their load ratio share of the allocated cost of the integrated system, it may do so. Customers that elect to do so, however, should recognize that they may need to secure alternative transmission arrangements such as point-to-point transmission service on an as-available basis in order to utilize those resources for reserves.
Where disputes over credits for customer-owned transmission facilities arise, we encourage all parties to first pursue alternative means to resolve their differences rather than seek formal resolution at the Commission. In any event, the Commission anticipates that disputes over the appropriate level of transmission facility credits should not preclude transmission customers from initiating service under the tariff. Where the parties are unable to reach agreement on the appropriate credit for customer-owned transmission facilities, the parties may make an appropriate filing with the Commission.
Commenters generally support a ceiling rate for non-firm transmission service, capped at the firm rate. 453/ Others request clarification as to whether the point-to-point tariff rates are fixed or are ceiling rates. Central Illinois Public Service's major concern is that, if the rates are fixed, the tariffs may result in higher prices for capacity and energy than those currently allowed for bundled service.
NYSEG argues that unequal pricing is a natural phenomenon of the open marketplace and requests assurance that offering transmission service at prices below a cost-based ceiling rate will not expose a transmission provider to claims of undue discrimination.
AEC & SMEPA opposes using the firm rate as the cap for non- firm transmission service. It states that, given the substantially lower quality of non-firm service (with no obligation to plan for such service), no cost-of-service principle justifies charging rates for non-firm service as high as the rate for firm service.
EGA and NRECA state that any discounts from the maximum firm rate must be uniform, transparent, readily understood, and posted on a RIN. According to CCEM and NRECA, the transmitting utility must have nondiscriminatory discount practices and must contemporaneously offer discounts to transmission customers at the same time and on the same basis as discounts for internal sales operations or affiliates.
We believe that it is important to continue to allow pricing flexibility. In accordance with the Commission's current policies, the rate for non-firm point-to-point transmission service may reflect opportunity costs. Any provisions for opportunity cost pricing for non-firm service must meet the requirements already discussed. If a utility chooses to adopt opportunity cost pricing, the non-firm rate is effectively capped by the availability of firm service and is not subject to a separately-stated price cap. If a utility chooses not to adopt opportunity cost pricing, the non-firm rate is capped at the firm rate. We also wish to ensure that non-firm transmission service is priced in a nondiscriminatory fashion. Accordingly, if a transmission provider offers a rate discount to its affiliate, or if the transmission provider attributes a discounted rate to its own transactions, the same discounted rate must also be offered at the same time to non-affiliates on the same transmission path and on all unconstrained transmission paths. We will further require that any affiliate discounts from the maximum firm rate must be transparent, readily understandable, and posted on the transmission provider's OASIS in advance so that all eligible customers have an equal opportunity to purchase non-firm transmission at the discounted rate. 454/ In addition, discounts offered to non-affiliates must be on a basis that is not unduly discriminatory and must be reported on the OASIS within 24 hours of when available transmission capability (ATC) is adjusted in response to the transaction. As discussed in the RIN section, information, including the price for all non-firm transaction discounts, must be posted on the OASIS to ensure comparability.
The term "priority" is used in the comments in several senses. The intent of the comment depends on which kind of "priority" is intended. In general, there are comments about the order in which parties can obtain new service, which we call "reservation priority," and there are comments about the order in which parties lose service they already have, which we call "curtailment priority." Commenters may establish different reservation priorities for various services, such as network, off-system sales, firm, ability to reserve a portion of new transmission capacity to be constructed, and so on. Curtailment priorities also differ with the type of service. However, many commenters assert that certain parties should or should not have "priority" without distinguishing the kind of priority or type of service for which priority is intended.
Many IOUs, state commissions, and cooperatives strongly believe that native load should have priority to reserve transmission capacity under the tariffs.
EEI suggests that existing and future allocations of transmission capacity must be based on proper transmission pricing or, in its absence, priority of service. According to EEI, retail and existing wholesale requirements service should have the highest priority for use of transmission capacity, followed by long-term point-to-point service. Dayton P&L supports a continued preference for native load growth because native load customers have borne the majority of the costs of the transmission system. Detroit Edison, EEI, and Florida Power Corp claim that, because native load and network customers pay higher rates during all hours, such customers should have higher priority for service requests than others requesting transmission service. These commenters also claim that the transmission provider should be able to reserve firm capacity for native load and network service customers.
Similarly, NARUC wants wholesale and retail native load customers to be held harmless from functional unbundling of wholesale transmission services. Because these customers have borne the vast majority of the costs of the utility's transmission facilities, NARUC argues that priority of service, quality of service, and allocation of joint and common costs to native load customers should not be affected by the transition to an open access transmission regime.
PA Com does not share the Commission's concern that a transmission provider may discriminate against a third party transmission customer vis-a-vis native load. It finds nothing impermissible in this sort of discrimination, arguing that the interconnected system was financed by, designed for, and built to serve native load.
NRECA explains that most transmission customers that seek network service will already be receiving similar service (albeit in a bundled form) from their transmission providers. It argues that these customers should receive the same priority of service as the transmission provider's native load customers for as long as they continue to take network service, whether under a current bundled wholesale supply contract, a private transmission contract, or a network tariff. 455/
East Kentucky requests that the final rule clarify that member distribution cooperatives of G&Ts will have priority over third parties in the use of the G&T's existing transmission facilities. TVA comments that native load customers and emergency service to neighboring systems should have a higher service priority than transmission services sold to third parties (where an alternative power supply is available to the third party).
We reiterate that we are not requiring the transmission provider to unbundle transmission service to its retail native load nor are we requiring that bundled retail service be taken under the terms of the Final Rule pro forma tariff. However, the amount of transmission capacity available to wholesale and unbundled retail customers under the Final Rule pro forma tariff is clearly affected by the amount of transmission capacity that the transmission provider reserves for the use of its native load customers and the future load growth of those customers. The transmission provider may reserve in its calculation of ATC transmission capacity necessary to accommodate native load growth reasonably forecasted in its planning horizon. However, the transmission provider is obligated to provide transmission service to others under the Final Rule pro forma tariff out of capacity reserved for native load growth up to the time the capacity is actually needed for such future needs. Furthermore, as we explained previously, while existing wholesale customers do not have any ownership-like rights to the capacity they used during the term of their contract, they will have a right of first refusal to that capacity after the expiration of their contracts or when their contracts become subject to renewal or rollover. 456/
A number of commenters argue that all firm service should not be treated equally. These commenters argue that the price of the service should determine the priority that the service receives. A large number of IOUs and potential network customers (existing requirements customers) argue that in light of the pricing implicit in the NOPR, (i.e., 12 CP for network versus annual system peak for point-to-point) network service should have priority over point-to-point service (because, all other things being equal, the price for network service will be higher).
BG&E believes that a customer receiving service priority equal to native load and network customers should pay comparable rates. Thus, BG&E argues that either flexible firm point-to- point service should be priced the same as network service, or point-to-point service should have a lesser priority than native load and network service customers if point-to-point service is priced lower than network service.
DE Muni believes that native load and network customers must have priority access to interfaces (particularly where they are constrained) after system reliability concerns have been satisfied. The same argument is advanced by commenters concerning long-term service versus short-term service. Public Generating Pool argues that long-term service should always have priority over short-term service because long-term customers contribute more towards fixed-cost recovery than do short-term customers.
Cajun objects to having its service and service to its customers, which it characterizes as network service, receive the same priority as firm point-to-point service customers who take service for periods as short as one hour. Cajun points out that it, as well as other network and native load customers, have been paying and will be paying for the transmission facilities in place to serve their needs for many years. According to Cajun, the transient firm point-to-point customer should not have equal standing. Cajun suggests, however, that a long-term firm point- to-point customer taking service for ten years or more should have service priority equal to native load and network service customers. SC Public Service Authority argues that the availability of short-term firm service with a priority equal to long-term service would provide a means for short-term customers to obtain the advantages of long-term firm service at a much lower total cost. As a result, it argues that a few point-to-point customers would opt for long-term firm service, and the burden of the residual costs of the transmission system would fall on network customers.
EEI claims that priority for point-to-point service should be on a continuum of firmness, with reservation (as well as curtailment) priority based upon duration of service and specific negotiated terms. EEI proposes that the point-to-point tariff be modified to provide a first-tier category of flexible point-to- point transmission service that is comparable in priority, price, length, and terms of service to network service. EEI believes that this modification will resolve the problems that are associated with establishing priorities between network service and point-to-point service if the Commission retains different CP cost allocation methods for each service.
On the other hand, CCEM, a group of power marketers, supports the concept that all firm service should be treated equally, regardless of the term or the nature of service.
An essential element of non-discriminatory transmission access is the right of transmission customers to reserve and purchase transmission service that is of the same quality as that used by the transmission provider in serving its wholesale requirements customers and retail load. Thus, we reject the proposal of some commenters that transmission providers need not provide firm point-to-point service that is of the same "firmness" as the transmission provider's service to native load. However, the fact that both network service and point-to-point service are provided on an equally firm basis does not mean that both types of service must be priced or reserved in the same manner.
The comments about reservation priorities for firm services boil down to two concerns. First, due to the differences in pricing firm point-to-point service and network service implicit in the NOPR (i.e., twelve-monthly CP pricing for network versus annual system peak for point-to-point), some commenters believe that network service should have priority over point-to-point service. Second, some commenters maintain that according firm, short-term point-to-point service a priority equal to long-term service provides a means for short-term customers to avoid making a fair contribution to the long-term costs of the system.
With respect to the first concern, we have eliminated the differences in pricing by permitting utilities to adopt point-to- point reservations as the customer load. As discussed above, for purposes of the Final Rule pro forma tariff, utilities are free to propose a single cost allocation method for the two services.
The second area of concern arises because of the first-come first-served reservation priority in the NOPR point-to-point tariff. The Commission recognizes that the tariffs, as proposed in the NOPR, provide the opportunity for a customer to reserve certain valuable rights (e.g., the right to short-term firm service during peak periods) while avoiding in part the long-term costs of the system (perhaps by relying on non-firm service during lengthy off-peak periods when there is a substantially reduced chance of interruption). However, the Commission has a countervailing concern that the transmission provider should not be able to withhold valuable transmission capacity from potential customers if that capacity is not being used by those who are paying for the long-term costs of the system.
Accordingly, the Final Rule pro forma tariff provides a mechanism to address this concern while safeguarding the rights of potential customers to obtain access to unused capacity. The tariff provides that reservations for short-term firm point-to- point service (less than one year) will be conditional until one day before the commencement of daily service, one week before the commencement of weekly service, and one month before the commencement of monthly service. These conditional reservations may be displaced by competing requests for longer-term firm point-to-point service. For example, a reservation for daily firm point-to-point service could be displaced by a request for weekly firm point-to-point service during an overlapping period. Before the applicable reservation deadline, a holder of a conditional firm point-to-point reservation would have the right of first refusal to match any longer-term firm point-to-point reservation before being displaced. After the deadline, the reservation becomes unconditional, and the service would be entitled to the same priorities as any long-term point-to-point or network firm service. 457/
The Final Rule pro forma tariff does not propose point-to- point or network service with various degrees of firmness beyond the simple categories of firm and non-firm. When a customer requests firm transmission service, reservation priorities are established based first on availability, and in the event the system is constrained, based on duration of the underlying firm service request; customers may choose the "firmness" of service they want by electing to take non-firm service, or by reserving and paying for firm service. We have not included any degrees of firmness in the Final Rule pro forma tariff because having intermediate categories of firmness under point-to-point or network service would, we believe, unnecessarily complicate the priority system. However, utilities are free to propose and fully support different reservation priority provisions for firm service in subsequent rate filings as long as those provisions are not unduly discriminatory, fully comply with the principles of comparability, and are priced appropriately.
IOUs, state commissions, and potential network customers tend to support the service reservation priorities for non-firm service set forth in the NOPR pro forma tariffs (i.e., transmission service by network customers for economy purchases to serve network load has a higher priority than non-firm point- to-point service, which has a higher priority than a firm point- to-point customer using transmission service at secondary points of receipt and delivery). However, because network customers pay a higher rate than point-to-point customers, these commenters argue that network customers should be permitted to use their off-peak load ratio share of the transmission system to make off- system sales. Many commenters argue that point-to-point customers can use their secondary service for both purchases and sales; thus, they believe it is discriminatory to limit network customers to purchases at secondary points.
Commenters that are opposed to the service reservation priority scheme in the NOPR pro forma tariffs argue that transmission providers will discriminate against third party users in favor of their native load economy purchases. These commenters argue that all non-firm service should have equal priority.
Other commenters, such as CINergy, would base priority on the duration of service. CINergy claims that this method would eliminate what it claims is an advantage (over network) given in the NOPR to point-to-point service in making short-term purchases. TVA notes that it establishes priority for non-firm service based on duration of service requested, with customers in each service category receiving priorities based on the rate they wish to pay.
Some commenters believe that the transmission price should affect the priority of customers to obtain non-firm transmission capacity. 458/ However, other commenters argue that this seems to be precluded by the NOPR pro forma tariffs' service priority provisions.
Although PSE&G believes that the NOPR pro forma tariffs suggest a first-come, first-served allocation method for capacity in excess of that needed for firm transmission service, it proposes a fixed period of time for all potential users to submit bids for service (e.g., one week prior for monthly service), allowing the bid price to determine priority (i.e., the higher bid prices receive service priority over lower bid prices). According to PSE&G, customers could bid an "up to" rate subject to a price floor, with all revenues flowed back to firm service customers. TVA also advocates departing from the first-come, first-served approach for allocating some uses of the transmission system, claiming that price is an effective means to establish priority for non-firm and short-term firm services.
Utility Wind Interest Group requests that non-firm service used for transmitting renewable resources be given a higher priority than non-firm service used for transmitting conventional resources because renewable resources cannot store their fuel supply.
We continue to believe that network economy purchases should have a reservation priority over non-firm point-to-point and secondary point-to-point uses of the transmission system. Network transmission customers are obliged to pay all of the costs of the transmission system without regard to the resources from which energy is scheduled. Therefore, it is appropriate that the transmission associated with a network customer's economy purchases (i.e., transmission that is used to substitute one resource for another on an as-available basis) enjoys a higher priority than non-firm point-to-point transmission service.
Regarding the reservation priority for non-firm service under point-to-point service, we will adopt a reservation priority based upon duration of non-firm service, with price acting as a tie-breaker for competing service requests of an equal duration. If there is insufficient transmission capacity to accommodate all non-firm transmission requests, the reservation of longer duration should displace the shorter. For example, a reservation for a month of non-firm service will displace a reservation for a week of non-firm service. Also, a reservation for a week will displace a reservation for a day, which will displace a reservation for an hour of non-firm service. If a customer requests non-firm and later another customer requests longer-term non-firm service before either term of service begins, the first customer to request service has the right of first refusal to change its request to the longer term of service. A firm point-to-point customer's use of transmission service at secondary points of receipt and delivery will continue to have the lowest reservation priority.
A large number of IOUs that are control area operators argue for discretion to curtail the transaction that most effectively relieves the constraint, in lieu of mandatory pro-rata curtailments, which they argue are inappropriate and not cost effective.
Other commenters that do not support pro-rata curtailment argue that preference should be given to native load or existing customers because these customers have paid the majority of the costs of the transmission system. A large number of customers note that their existing contracts contain "enhanced" curtailment priorities (i.e., service to others will be curtailed before service to customers with such curtailment priority) due to the large capital outlays made by them in connection with their service. 459/
Public Generating Pool believes that the proposed curtailment provisions may not be flexible enough for transactions in the Northwest. It argues that hydro spill should be avoided, and suggests that transactions from federal and/or non-federal hydroelectric generation facilities should not be curtailed pro rata with other transactions that do not rely on such facilities. Public Generating Pool urges that regional agreements (e.g., regional transmission group agreements) that would achieve this goal should be given deference.
Other commenters support pro-rata curtailments for firm service. 460/ PSNM states that this has been its operating practice in the past, and PSNM expects to continue such an approach in the future.
Power marketer commenters generally support the pro-rata curtailment adding that a standardized curtailment priority applied nationally would provide greater open access and eliminate discriminatory curtailments.
Commenting on a related subject, EEI maintains that the network tariff provision for termination of service in the event a customer fails to curtail load 461/ may not be realistic for service to a Transmission Dependent Utility. EEI suggests that the Commission supplement this provision with a substantial penalty provision, coupled with an indemnification requirement.
It was not our intent in the NOPR to require all transactions to be curtailed on a pro-rata basis regardless of whether the transaction relieves a constraint. We intended to permit curtailments of transactions that substantially relieve a constraint. 462/ We intended and continue to believe that curtailment on a pro-rata basis is appropriate for curtailing the transactions that substantially relieve the constraint. In order to allay the concerns of the commenters addressing this issue, we are clarifying the curtailment provision of the tariff to explicitly allow the transmission provider discretion to curtail the services, whether firm or non-firm, that substantially relieve the constraint. Of course, any curtailment must be made on a non-discriminatory basis, including curtailment of the transmission provider's own use of the transmission system. Customers that believe the curtailment policy is administered unfairly may file a section 206 complaint at the Commission.
Concerning the request of certain Pacific Northwest commenters, we would consider granting deference to an alternative curtailment method to avoid hydro spill if such a regional practice is generally accepted and adhered to across the region, as discussed further in Section IV.K.
Finally, we agree with EEI's observation that terminating network service under the tariff to a transmission dependent utility that fails to curtail load as required may not be appropriate. As a result, we clarify that under network and point-to-point service, the transmission provider may propose a rate treatment (penalty provision) to apply in the event a customer fails to curtail load as required under the Final Rule pro forma tariff. Such proposals will be evaluated on a case-by- case basis on compliance.
A number of commenters seek clarification of the curtailment provision for non-firm service under the two tariffs. They note that economy purchases by the network customer are accorded a higher curtailment priority than non-firm service under the point-to-point tariff. However, under the point-to-point tariff there is no acknowledgement of this higher priority for network service. Curtailments for non-firm transmission service under the point-to-point tariff are simply based upon duration of service, without reference to a higher priority for network economy purchases.
A number of commenters, including Industrial Energy Applications, suggest that a price-based curtailment queue for non-firm transmission will facilitate economy energy deals in highly competitive wholesale power supply markets and allow the parties to directly address delivery risk through the pricing mechanism.
Blue Ridge argues that the final rule should provide equal curtailment priority for all types of non-firm transmission service. Utilities For Improved Transition argues that network customers should be able to transmit non-firm power imports under the network tariff with the same curtailment priority that is assigned to all other firm network uses of the transmission system.
A number of commenters note that the tariffs allow non-firm service to be interrupted only for emergency or reliability reasons or to provide firm service. These commenters contend that, under this requirement, curtailment of non-firm service is unlikely. 463/ As a result, they believe that non-firm service is elevated to firm service. To remedy this situation, these commenters argue that transmission providers should have the ability to curtail non-firm service for any economic reason.
We have clarified in the Final Rule pro forma tariff that a network customer's economy purchases have a higher curtailment priority than non-firm point-to-point transmission service.
A higher curtailment priority should be provided to network economy energy purchases for the reasons stated in AES Power, Inc.. 464/ In that case, we recognized that the network transmission customer has already "paid" for the transmission of its economy purchases (i.e., transmission that is used to substitute one resource for another on an as available basis) through its payment of a load ratio share of the system.
Many commenters oppose the point-to-point service provision allowing non-firm service to be interrupted only for emergency or reliability reasons or to provide firm service. Upon further consideration, we agree that this provision is too narrow. Accordingly, the Final Rule pro forma tariff is revised to allow the transmission provider to curtail non-firm service for reliability reasons or economic reasons (i.e., in order to accommodate (1) a request for firm transmission service, (2) a request for non-firm service of greater duration, (3) a request for non-firm transmission service of equal duration with a higher price, or (4) transmission service for economy purchases by network customers from non-designated resources.). However, all curtailments must continue to be made on a non-discriminatory basis including curtailments of the transmission provider's own non-firm uses of the transmission system under the tariff. A firm point-to-point customer's use of transmission service at secondary points of receipt and delivery will continue to have the lowest curtailment priority.
Generally, transmission providers argue that the tariffs give too much flexibility to customers, while transmission customers argue that even more flexibility is required. The arguments are generally tied to pricing rather than technical problems with providing any level of service.
A common transmission provider argument is that the proposed firm point-to-point tariff provides a premium service comparable to network service, but at a lower rate. It has been suggested that either the flexibility to use non-firm service at secondary points of receipt and/or delivery at no additional charge under the point-to-point tariff be eliminated or that point-to-point customers should pay a premium price for such flexibility. 465/ Transmission providers generally argue that flexible point-to-point service puts the transmission owner and the network customer at a competitive disadvantage. They assert that the point-to-point customer is able to use non-firm transmission to reach secondary receipt and delivery points for both sales and purchases, but the network customer may use only non-firm transmission to reach secondary points for purchases. Thus, they argue, the flexible point-to-point users can sell non-firm power with a small or even no transmission component (because the underlying transmission is effectively free). Electric Consumers Alliance and Cajun believe that the owner and network customer competing for that sale should not be charged for the identical transaction. Absent a change to the point-to-point tariff, a number of transmission providers and state commissions (including Midwest Commissions) argue that to provide balance to the tariffs, the network tariff should permit the network customers to have non-firm transmission to secondary receipt and delivery points at no additional charge for both purchases and sales within its load-ratio transmission entitlement. Utilities For Improved Transition refers to this proposed network tariff modification as "headroom."
CCEM opposes the headroom concept, arguing that "free" use of capacity will give transmission providers an unfair competitive advantage. CCEM also cites Order No. 636 in support of its position.
Conversely, a number of customer groups believe the point- to-point tariff should be made more flexible by broadly defining the concept of points of receipt and delivery. They argue that all points of connection between the transmitting utility and the purchasing utility should be treated as a single point of delivery (POD) or point of receipt (POR). 466/ In this manner, a customer would not have to pay for every point of receipt or point of delivery, but could select a contract demand level of service. The customer could then use the service at multiple points without incurring separate reservation charges for each point.
A number of commenters contend that the Commission should not force specific tariffs on public utilities in the Pacific Northwest due to their unique status. 467/ In particular, NWRTA recommends that the final rule recognize that the Pacific Northwest's integrated transmission system, including large components owned by non-public utilities, was constructed to support a unique region-wide hydroelectric-dependent generating system. NWRTA recommends that the final rule be sufficiently flexible to accommodate these unique characteristics without prejudicing the interests of users or providers of transmission services.
Similarly, Public Generating Pool states that the NOPR pro forma network tariff departs from the status quo arrangements in the Northwest and is generally unworkable because generation is usually remote from the control area serving the network load and because BPA, which does not have a typical service territory, dominates the regional transmission market. Public Generating Pool suggests that the Commission require, and the region develop, a "generation integration" transmission tariff that would offer network-type service to a source or sources of generation unbundled from the "network services" designed to integrate load. Similar contract demand network tariffs have already been proposed by some IOUs.
We will not allow network customers to make off-system sales within the load-ratio transmission entitlement at no additional charge. Commenters have raised no new arguments to persuade us to do so. The primary purpose of network service is to integrate resources to serve loads. Use of transmission by network customers for non-firm economy purchases, which are used to displace firm network resources, must be accorded a higher priority than non-firm point-to-point service and secondary point-to-point service under the tariff. Off-system sales transactions, which are sales other than those to serve a network customer's native load, must be made using point-to-point service. They can be made on either a firm or non-firm basis.
A large number of transmission providers support the "headroom" concept, arguing that without it the flexible point- to-point service puts them at a competitive disadvantage. This would be true if a utility serving load were required to use network service exclusively. However, we do not require any utility to take network service to integrate resources and loads. If any transmission user (including the public utility) prefers to take flexible point-to-point service, 468/ they are free to do so. Any point-to-point customer may take advantage of the secondary, non-firm flexibility provided under point-to-point service equally, on an as-available basis.
Commenters raise issues regarding the minimum term of one hour for firm point-to-point service. Their concerns center on price and priority. Transmission providers point out that their native load customers pay the fixed cost of the transmission system every hour of the year. They argue that comparability is not achieved by permitting others to have service for one hour with equal priority to native load and other long-term customers. Others worry that the one-hour minimum term will: (1) promote the selective use of the transmission system; (2) impair the ability of a utility to plan its system; and (3) adversely impact longer term transactions.
Tallahassee and KY Com are concerned that one-hour firm service may encourage speculative advance requests for service during the system peak day (Cajun refers to this as cream skimming). These commenters express concern that such requests could displace other valid transactions or constrain a corridor or interface to the detriment of network service or native load customers. Tallahassee proposes a one-day minimum term for firm service. 469/
East Kentucky is concerned that users of the transmission system could, under the Commission's proposed open-access rule, purchase short-term firm service during peak months in lieu of annual firm service to reduce expenses associated with the purchase of firm transmission service. By buying short-term firm service only during the peak months, an entity can significantly reduce its transmission expenses by purchasing non-firm service during off-peak months when the available transmission capacity far exceeds the demand on the transmission system. For this reason, some commenters request that short-term firm service be priced to generate revenues over the peak months equal to the charge for annual firm service.
Duke argues that, because all curtailments are equal, the addition of each one hour firm transaction will lower the reliability profile of native load customers and other customers with long-term commitments. It suggests that different classes of services be established that offer transmission customers the flexibility to obtain an intermediate level of transmission service (between native load firm and non-firm) for transactions of shorter duration.
On the other hand, some TDUs and power marketers support the one-hour minimum term. TAPS argues that transmission providers should not be permitted to restrict the availability of hourly, daily or weekly transmission service at reasonable prices, as some transmission providers have proposed in open access cases. Brazos supports a minimum duration of service equal to the minimum scheduling period of the transmission owner. Turning to the maximum term of service, Chugach objects to the imprecise requirement that transmission service be offered for a term equal to the life of a particular generation resource. Chugach, joined by VEPCO, suggests that the Commission require transmitting utilities to offer five-year terms (with longer contract terms by negotiated agreement).
Although BPA supports eliminating arbitrary term limitations and facilitating long-term resource commitments, it is concerned that the Commission's failure to specify a maximum term for firm transmission service (particularly where no specific resource is being wheeled) requires transmitting utilities to effectively sell off their transmission capacity to third parties. In BPA's view, such a requirement goes well beyond the intent of the Energy Policy Act.
PSE&G argues that the term limit for firm transmission service should be consistent with the transmission provider's planning horizon (e.g., for PSE&G, 10 years), which will ensure comparability of firm third party customers with native load. According to ConEd, failure to specify a maximum term for service creates uncertainty for planning purposes. PECO believes that utilities should have the right to limit the term of service to either: (1) the expected useful life of facilities used in providing service; or (2) the term of permits and land rights needed for those facilities.
We will adopt a one-day minimum term for firm point-to-point service. The one-day minimum term for firm point-to-point service, along with modifications to the procedures for requesting firm point-to-point service, will moot a number of reliability concerns and allegations about possible "cream- skimming." As discussed supra, firm service requests with longer durations of service will have bumping rights over shorter term firm service requests. Also, the one-day minimum will not disadvantage anyone because the transmission provider will be subject to the same one-day term for its firm point-to-point uses of the transmission system. Because of the longer-term nature of network service, it will be subject to a one-year minimum term.
We will not specify a maximum term for either point-to-point or network transmission service. However, we recognize the concerns raised by commenters that a commitment of uncertain duration makes planning difficult. Therefore, we will modify the tariff to require that an application for transmission service specify the length of service being requested. This will provide the transmission provider with the certainty it needs for planning and the transmission customer with the flexibility to request the service it needs.
The NOPR pro forma network tariff specifies that a customer may designate only those resources that the customer owns or has committed to purchase pursuant to an executed contract. Transmission providers argue that there is a need for some limitation on the resources that network customers can designate to serve their loads. Otherwise, they assert, a utility would be required to incur costs (planning, constructing, and operating its transmission system) that are out of proportion to the customer's load and its share of the utility's cost of service. However, EEI, VEPCO, and Utilities For Improved Transition believe that the Commission's proposal to use a purchase obligation standard is too narrow, inflexible, and susceptible to manipulation. These IOU commenters argue that it could include very short-term obligations and contingent obligations to purchase. EEI suggests that the Commission should establish a minimum term so that a customer could not designate resources for which it has only a one-month contract. The principal problem VEPCO sees is that purchase obligations may not be clear. According to VEPCO, a transmission customer may claim an obligation when it has no substantial payment obligation and thus no economic deterrent to designating that purchase obligation as a potential resource to serve its loads. It alleges that the result is that the transmitting utility can be forced to tie up transmission capacity for service from a resource that may have little probability of being used; consequently, less capacity will be available for other uses. VEPCO further argues that, since upgrade costs are typically rolled in, the customer may not have a strong incentive to minimize transmission construction. EEI argues for system-specific limits based on capacity needs to serve the network loads reliably. Alternatively, if the "own" or "purchase" provision is to be used, EEI contends that the customer should be required to have a significant and ongoing obligation to purchase power (e.g., minimum one-year contracts that impose obligations on a first-call basis).
These IOUs also recommend that the Commission not decide on a single way to limit network resources. They note that proposals based on percentage limits (e.g., 125%) subject to exceptions for reliability concerns may be a reasonable approach. According to these IOUs, the Commission should permit flexibility to develop not unduly discriminatory provisions until experience suggests which are the best ways to satisfy the objective. To prevent over-designating network resources, Missouri-Kansas Industrials suggest placing a limit of 200% of the subscriber's load.
Arkansas Cities supports limiting the definition of network resources to those that the customer owns or contracts for. It argues that this reasonably accommodates the planning process. Arkansas Cities argues that any type of percentage adder would unreasonably restrict the process.
ELCON states that virtually any issue regarding the nature of network service can be resolved by reference to the price of such service. According to ELCON, if a transmission customer seeks to incorporate unlimited (i.e., unspecified) generation sources into its network load, the customer should pay a higher rate than a network customer that can identify a need for service to/from specified generating units.
A related issue is how interface capacity should be allocated between network customers and the transmission provider. IOUs generally argue that interface capacity should be allocated based upon the load ratio of the customers. Tariff customers generally argue that there should be no restriction on the amount of interface capacity that they may designate.
We do not believe that a superior alternative has been suggested to our purchase obligation for limiting network resources. Accordingly, we will not change the limitation on the amount of resources a network customer may designate. A transmission provider taking network service to serve network load under the tariff also is required to designate its resources and is subject to the same limitations required of any other network customer.
Limiting the amount of resources to those that the customer owns or commits to purchase will protect a utility from having to incur costs that are out of proportion to the customer's load. The transmission provider's concern that the purchase limitation will result in excessive network resources is unfounded. A transmission customer, like a transmission provider, has an incentive not to oversubscribe its capacity requirements because the cost of excessive reserve margins will be prohibitive. Requiring a strict percentage limitation could distort the planning process by limiting the size of resource additions a transmission customer may undertake. Allowing discretionary exceptions to the percentage limit will inevitably lead to disputes and claims of discrimination.
With respect to the allocation of interface capacity under network service, we clarify that a customer is not limited to a load ratio percentage of available transmission capacity at every interface. A customer may designate a single interface or any combination of interface capacity to serve its entire load, provided that the designation does not exceed its total load.
Under the NOPR pro forma tariffs, the transmission provider and anyone who can file a section 211 request is eligible to request service.
In general, most commenters agree with the eligibility requirements. However, several IOUs argue that the tariffs should be modified specifically to preclude the use of the tariffs for retail wheeling. 470/
NIEP believes the eligibility provision should include all entities that not only generate power themselves, but also purchase power generated by others for resale, including municipalities, federal entities with rights to purchase, and other entities with load but no generation resources.
Power Marketing Association and others argue that the network tariff should be modified to specifically allow service to marketers.
PacifiCorp argues that independent owners of generation resources should not be allowed to acquire network integration service directly. It suggests that, if the eligible utility does not have a load in the control area, the service sought is to accommodate off-system sales, which is a point-to-point service.
As we previously explained, a non-discriminatory open access transmission tariff must be made available, at a minimum, to any entity that can request transmission services under section 211 and to foreign entities. 471/ Eligibility to take service is further discussed in Section IV.C.1.
Ohio Edison, Utilities For Improved Transition, LA DWP, and VEPCO believe that point-to-point transmission customers should not be allowed to terminate transmission service prior to the end of their contract term, especially in light of their reassignment rights. For network service, VEPCO, Florida Power Corp, Utilities For Improved Transition, and Duke believe that the notice of termination period should be at least five years, to coincide with the utility's construction horizon. In particular, VEPCO wants transmission customers terminating service prior to the end of the contract term to pay for network upgrades constructed for their benefit that would be stranded due to early termination of service.
CCEM supports a six-month notice of termination as appropriate for a term of service of one year or greater; any longer notice period would unduly limit a transmission customer's purchasing options.
NYSEG and EEI want the flexibility to negotiate a reasonable, mutually agreeable notice of termination period to recognize such things as the term of the contract and the amount of service at issue.
LEPA, VT DPS, and NorAm believe that written notice of termination should not be required for transactions of two years or less.
We will delete the notice of termination provision from the tariff. We believe that commenters have raised a number of valid concerns about including a the notice of termination provision. In particular, the notice of termination will have no effect on short-term service of less than two years. In addition, the two- year notice provision does not coincide with either a transmission provider's planning or construction horizon. Because we are eliminating the notice of termination provision from the tariff, transmission service will have to be reserved and paid for over the length of the contract term. Of course, by eliminating this tariff provision, we are not precluding parties from negotiating mutually agreeable terms for early termination on a case-specific basis. However, we note that point-to-point customers are able, under the reassignment provision, to resell unused transmission capacity.
In the NOPR, the Commission explained that it was requiring a reciprocity provision in the non-discriminatory open access transmission tariffs so that public utilities offering transmission access to others would be able to receive service from transmitting utilities that are not public utilities (e.g., municipal power authorities and federal power marketing administrations that receive service under a public utility's tariff).
The vast majority of the jurisdictional IOUs commenting on this issue favor a reciprocity requirement. In contrast, the non-jurisdictional transmission customers (primarily publicly- owned entities and cooperatives) generally oppose such a requirement. The few state commissions commenting on this issue generally support the stated goal of the reciprocity requirement, but question our legal authority to require it. 472/ The few IPP and power marketer commenters that address this issue do not object to reciprocity if it does not apply to non-transmission owners. 473/
Several commenters believe that all transmission-owning utilities, whether public or investor-owned, must be required to provide open access service for a truly competitive wholesale power market to be realized. 474/ Sierra states that specific legislation by Congress and/or state lawmakers may be necessary to ensure that currently non-public utilities comply with the Commission's open access requirements.
A number of commenters maintain that the Commission should enforce reciprocity by allowing public utilities to transmission service to non-public utility transmitting entities when reciprocal transmission service is not offered. 475/
Phelps Dodge and Otter Tail believe that non-public utility transmitting entities will continue their existing bundled service contracts indefinitely to avoid complying with the reciprocity requirement. Therefore, to promote transmission access through reciprocity, Phelps Dodge and Otter Tail suggest requiring the unbundling of existing contracts by a date certain to convert such contracts to transmission service agreements under the transmission provider s open access tariff.
A number of commenters argue that the Commission's only legal authority to impose a reciprocity requirement on non-public utilities is that provided by section 211 of the FPA. 476/ Large Public Power and others suggest that mandating reciprocity is not necessary because the stated goals of the reciprocity requirement can be met by voluntary transmission access and through section 211 filings.
Many commenters do not oppose reciprocity if it is modified to incorporate the protections present in sections 211 and 212 and the benefits available under sections 205 and 206. 477/
TDU Systems explains that section 211 contains a number of protections, e.g., transmitting utilities cannot be required to provide transmission service if such service impairs their ability to provide reliable service, disrupts existing contracts with entities seeking service, or is inconsistent with state law regarding retail marketing areas. It also notes that section 212 contains rate provisions that protect a non-public utility transmission provider from being forced to provide electric service at a non-compensatory rate. Seminole EC argues that, without section 205/206 rights, non-public utilities cannot adjust their tariffs or challenge tariff provisions that they believe should not apply to them.
Several commenters also suggest that, without sections 211, 212, and 205 rights and protections, reciprocity provisions allow the transmission provider to deny transmission based on its own determination of the transmission customer's attempt to comply with reciprocity, which SC Public Service Authority contends is letting the "fox guard the henhouse." TAPS states that in no event should the claimed lack of reciprocity constitute grounds for refusal to offer a service agreement, or unilateral denial, delay or termination of service. TAPS, and other cooperative, municipal, and public power commenters suggest that some procedure must be developed to bring reciprocity disputes before the Commission. Wisconsin Municipals argues that this provision should be modified, claiming that a customer's receipt of a revenue credit for transmission facilities it contributes to the transmission provider's system should satisfy the reciprocity requirement.
Rather than filing tariffs with the Commission, Dairyland suggests allowing cooperatives that are not public utilities to file a compliance transmission tariff with the Rural Utilities Service (RUS) as it relates to the issue of reciprocity, thereby affording non-jurisdictional cooperative utilities rights and privileges similar to those afforded jurisdictional utilities.
Several commenters argue that reciprocity should apply to both the seller and purchaser engaged in a transaction under an open access tariff to ensure that: (1) transmission customers cannot avoid their reciprocity obligation by requesting service through an agent that owns no transmission facilities; (2) a generator cannot take transmission service in order to sell power to a non-jurisdictional entity, thereby allowing the non- jurisdictional entity to escape the reciprocity provision, and (3) a buyer cannot take service in order to purchase power from a non-jurisdictional entity, thereby allowing the entity to escape the reciprocity requirement. 478/
Entergy also is concerned that reciprocity can be evaded through the use of power marketers. Therefore, Entergy proposes that, if the transmission customer is neither the producer, transmitter, nor distributor of the power and energy to be transmitted, but instead acts as a marketer, the marketer must designate an electric utility that either produces, transmits, or distributes such power and energy as being subject to the requirement to provide comparable service.
CCEM and NIEP support the reciprocity provision because they apply only to transmission owners. CCEM and NIEP contend that non-transmission-owning customers should not be required to procure transmission capacity or hire a proxy solely to meet a reciprocity requirement.
In contrast, CA Energy Co insists that the reciprocity provisions of the proposed tariffs must be amended to clarify that IPPs can obtain access even if the IPPs own no transmission assets. CA Energy Co argues that the Commission must exempt IPPs from the reciprocity requirement if IPPs are to be assured equal access and thus remain effective competitors.
Publicly-owned entities argue that they differ from IOUs and cannot provide completely reciprocal services. 479/ LPPC identifies a number of differences between publicly-owned utilities and IOUs, such as: the publicly-owned utilities' use of tax-exempt debt, which could be jeopardized if they are required to make their transmission systems available for private use; restrictions on the rate-setting methods publicly-owned utilities can use; and statutory restrictions on the services publicly-owned utilities can offer. 480/ LPPC asks that the reciprocity provision be dropped or changed to recognize these differences. 481/ It argues that the purposes of the NOPR are met by transmission tariffs voluntarily offered by its members that generally meet the standard of open access.
NE Public Power District notes that to the extent that the Commission requires cost-based rates, the Commission must recognize that publicly-owned utilities do not establish rates in the same manner as IOUs; for example, NE Public Power District does not include depreciation or return on equity as costs in its rates, nor does it pay federal income taxes. It suggests that the Commission should not apply a one-size-fits-all approach to pricing transmission service, should consider the special circumstances of publicly-owned utilities in exercising its authority under section 212, and should give publicly-owned utilities the opportunity for an evidentiary hearing before requiring them to adopt rate-setting conventions that are appropriate for public utilities. 482/
CAMU asserts that the tax-exempt financing of government bodies may be jeopardized due to limitations on the private use of facilities that are financed through tax exempt bonds. 483/ It suggests that a solution may be to impute the cost of capital based on the average cost of all area utilities. Wisconsin Municipals says that the Commission should seek an opinion from the IRS regarding whether reciprocal use would jeopardize tax-exempt status; if it is determined it would, the owner of the transmission facilities should be allowed to recover any increased costs associated with the loss of tax-exempt status. 484/
DE Muni is concerned that a utility may "impose" the open access tariffs on a non-public utility customer such as a municipal system and then demand reciprocal access to that customer's transmission facilities to serve the municipal's retail customers.
San Francisco argues that there is no legal authority in the FPA or case law to impose the open access requirement on non- public utility entities. Moreover, San Francisco is concerned that the reciprocity requirement may impair its ability to deliver its own power pursuant to the requirements of the Raker Act.
Salt River opposes the reciprocity provision because it could "administratively vest discriminatory market power in FERC jurisdictional public utilities." Salt River further argues that "duly adopted open access transmission tariffs or rate schedules of publicly-owned utilities should be presumed to satisfy FERC's reciprocity requirement, and the legislative action of the publicly-owned utility's ratemaking body should be given deference in a dispute brought before FERC relating to the tariff or rate schedule."
Public Generating Pool argues that a non-public utility transmission customer should not have to provide the same service a public utility provides. It argues that a publicly-owned entity may lack the resources to provide the high level of service a public utility can provide.
Tallahassee seeks clarification that reciprocity does not mean that investor-owned utilities can require municipal utilities to offer services that are identical to those offered by the investor-owned utilities. It argues that it is not practical to require small utilities to provide all of the services bigger utilities provide and that legal obligations imposed on municipal utilities may interfere with their ability to provide certain types of open access provisions. Tallahassee concludes that reciprocity should be equated with comparability (the transmission user must offer service that is comparable to the service it offers to itself).
TANC asks for clarification and suggests various changes to the reciprocity provision. It asks whether the reciprocity requirement will apply to it, since it is part owner of a transmission facility (the California Oregon Transmission Project (COTP)) but has contractually dedicated its entitlement to use of this facility to its members. It argues that if the requirement does apply, its obligation should be limited to the member's share of TANC's entitlement. TANC also asks whether when it receives transmission service on behalf of a member, that member's non-COTP transmission facilities must be made available to the transmission provider. If that is the case, TANC asks what voltage level of facilities must TANC and its members make available? TANC believes that if a TANC member independently requests transmission service from a utility, that member would be obligated to make reciprocal service available to the utility on the share of the COTP that member "controls" through TANC's entitlement. TANC argues that neither TANC and its members nor TANC and its COTP co-owners should be treated as "affiliates" under the proposed reciprocity provision. It argues that the comparable service tariff it must provide as a member of the Western Regional Transmission Association should satisfy the reciprocity requirement.
TANC also asks for clarification as to how the reciprocity provision would be administered. A non-public utility cannot file a tariff with the Commission, so presumably it and the public utility from which it wants transmission service would negotiate; if, however, the public utility does not agree that reciprocal service is being offered, it will deny access to its transmission facilities, and the non-public utility would have to come to the Commission to resolve the dispute. SC Public Service Authority expresses a similar concern. It argues that the reciprocity provision will prevent non-public utilities from obtaining comparable access. The public utility from which the non-public utility wants access will be able to delay access by claiming that the reciprocity provision is not satisfied. Even the possibility of such a delay may discourage customers from contracting with non-public utilities. SC Public Service Authority suggests that this problem can be fixed by allowing non-public utilities to file comparable access tariffs with the Commission.
NE Public Power District asserts that while government-owned utilities are subject to limited regulation under sections 211- 213 of the FPA, "that limited grant of jurisdiction cannot be transmuted into amenability of state- and municipally owned utilities to the sort of detailed regulation that the NOPR would impose through requiring insertion of so-called 'reciprocity' clauses in the transmission tariffs of jurisdictional public utilities, by inviting the filing of 'class' _ 211 applications, or by making adherence to the rules emerging from the NOPR proceeding an automatic requirement for utilities that are subject to a _ 211 application."
NE Public Power District explains that it has pending before the Commission a proceeding in which it has taken the position that it is not subject to the Commission's jurisdiction. (citing Docket No. TX95-3-000). 485/ NE Public Power District also argues that it would be unconstitutional under the Tenth Amendment and the Guarantee Clause of the United States Constitution for the Commission to assert jurisdiction. It further argues that the proposed regulations would constitute an unfunded Federal mandate within the meaning of the Unfunded Mandates Reform Act of 1995 and that the Commission has not followed the requirements of that Act.
NE Public Power District explains that under Nebraska law it is prohibited from granting or conveying to any private entity any interest or control of any of its property or facilities, and section 211 does not authorize the Commission to order wheeling for an end-user or to replace a contractual wholesale sale. Thus, it argues that the Commission does not have authority to use mandatory reciprocity clauses to obtain compliance with a policy it has no right to impose directly. (citing Sunray and AGD). NE Public Power District also questions whether the Commission may lawfully declare exclusive-use provisions invalid under the Sierra-Mobile doctrine without conducting a proceeding under section 206 with regard to each specific facility and making the necessary findings.
Salt River responds to complaints that public power entities have a competitive advantage, due to subsidies and preferences, over investor-owned utilities:
This Commission is not the appropriate forum and this proceeding is not the appropriate proceeding to consider the investor-owned utilities' "level playing field" complaint as it relates to public power, and the Commission should reject any suggestion that it do so. [486/]
Cleveland urges the Commission not to address in the NOPR proceeding either congressional policy as reflected in the tax laws or the propriety of other long-standing federal statutes in considering complaints that publicly-owned entities receive subsidies from the government that IOUs do not. It points to three tax breaks available to IOUs: (1) investment tax credits; (2) deferred taxes resulting from different book and tax depreciation; and (3) use of tax-exempt financing in certain circumstances.
NRECA/APPA argues that the Commission should not, as requested by EEI, address alleged "undue" subsidies received by consumer-owned utilities and delve into such subsidy issues as municipal financing policy, rural electrification and development policies, and the merits of privatizing the federal power marketing administration. NRECA/APPA alleges that these are complex issues that are within the domain of other federal agencies.
NRECA explains that under Dairyland Power Cooperative, 487/ the Commission does not have jurisdiction over cooperatives that have REA/RUS loans. 488/ NRECA further explains that rural electric cooperatives are exempt from federal taxation only if 85 percent of their revenues are derived from their members and open access could jeopardize their tax relief. 489/ RUS notes that while the Energy Policy Act expanded the Commission's authority to order transmission access, it did not amend the Rural Electrification Act (RE Act) so as to curtail the plenary powers of RUS to carry out a program of rural electrification.
Citing various cases, Brazos says that the Commission must be mindful of the purposes of the RE Act and, if available transmission on Brazos is taken for use by third parties, "a question remains as to the capacity of the remaining portions of the system to function with 'decent service and at decent rates.'" 490/
Various rural electric cooperatives state that the Commission must recognize that consumer-owned electric utilities are very different from investor-owned utilities. 491/ Mor- Gran-Sou EC is concerned that the final rule will have a detrimental impact on rural areas, just as it believes deregulation of the banking industry, airline industry and telecommunications industry has had.
Many cooperatives request that the term "affiliates" be defined: (1) to apply only to corporate "affiliates" over which the transmission customer exercises legal control; and (2) to exclude the distribution cooperative members of a generation and transmission (G&T) cooperative. 492/ Seminole EC explains that a G&T is a cooperative formed by a group of distribution cooperatives; therefore, a G&T has no legal powers to require action by its member cooperatives. In fact, according to Seminole EC, the distribution cooperatives govern the G&T.
Similarly, TDU Systems notes that the term "affiliates" could be construed to apply to a joint action agency and its municipal and cooperative members. TDU Systems point out that a joint action agency, itself a creature of statute, may not have the power to require its members to provide transmission service.
AEC & SMEPA contends that including the transmission customer's affiliates in the reciprocity obligation is broader than the obligation of the transmission provider, which does not include transmission service by the provider's affiliates. AEC & SMEPA suggests that either: (1) the transmission provider's affiliates should be included in the basic obligation to provide transmission service; or (2) the reciprocity provision should delete the reference to affiliates of the transmission customer.
NRECA comments that it is unclear whether "facilities owned or controlled by the transmission customer" include transmission contracts. NRECA believes that transmission contracts cannot be included in this definition, at least as applied to "transmitting utilities" under sections 211 and 212.
Seminole EC questions whether the requirement to offer "open access" service requires reciprocal service to be provided solely to the transmission provider or an open access tariff available to any and all qualified applicants. Seminole EC and NRECA request that the Commission adopt the former interpretation in the final rule.
In contrast, Tucson Power and Phelps Dodge believe that, if a non-public utility transmitting entity chooses to take service under any open access tariff, such access should be conditioned on its own agreement to provide comparable service to all eligible customers under an open access tariff.
Tucson Power believes that, without such access to all eligible customers, reciprocity will fail to achieve true "comparability." Tucson Power explains that reciprocal transmission service would appear to be limited by the terms of the specific original request for transmission. For example, Tucson Power fears that a non-jurisdictional entity requesting 25 MW of point-to-point firm service could argue that its reciprocal transmission obligation is limited to the same 25 MW of point-to- point firm service for an equivalent duration. Tucson Power argues that such a limitation on providing reciprocal service would prove useless. Further, Tucson Power believes that reciprocity should be interpreted to require a non-public utility entity to expand or upgrade facilities to meet the transmission requests of all eligible entities and should contain the same pricing provisions as applied in this proceeding for jurisdictional utilities.
Seminole EC questions whether the reciprocity requirement to provide "comparable" service to the transmission provider simply means offering the same kind of service to the transmission provider that the transmission customer receives (i.e., network, firm point-to-point, or non-firm).
NRECA claims that the reciprocity requirement should not be construed to impose on non-public utilities an unreasonable obligation to build. Seminole EC adds that an unreasonable obligation to build could effectively preclude requests for tariff service; the transmission customer could be better off litigating a section 211 request rather than accepting the obligation to undertake a massive construction program.
We conclude that it is appropriate to require a reciprocity provision in the Final Rule pro forma tariff. This provision would be applicable to all customers, including non-public utility entities such as municipally-owned entities and RUS cooperatives, that own, control or operate interstate transmission facilities and that take service under the open access tariff, and any affiliates of the customer that own, control or operate interstate transmission facilities. Any public utility that offers non-discriminatory open access transmission for the benefit of customers should be able to obtain the same non-discriminatory access in return.
In the NOPR, we explained that the reciprocity provision would "requir[e] any user or agent of the user of the tariff that owns and/or controls transmission facilities to provide non- discriminatory access to the tariff provider." 493/ We wish to clarify that, in stating that a user must provide non- discriminatory access to the tariff provider, we intend that reciprocal service be limited to the transmission provider.
However, in situations in which a non-public utility is a member of an RTG or a power pool, it also would have to provide service to the other members of the RTG or power pool. We do not believe it is appropriate to expand the reciprocity condition beyond these situations at this time because, as discussed further below, the IRS currently is evaluating its tax-exempt financing regulations in light of competitive changes in the industry.
We are aware that many non-public utilities are very willing to offer reciprocal access, and that some are willing to provide access to all eligible customers through an open access tariff. However, they are fearful that a public utility may deny service based simply on a claim that the open access tariff offered by a non-public utility is not satisfactory. To assist these non- public utilities, we have developed a voluntary safe harbor procedure that should alleviate these concerns. Under this procedure, non-public utilities would be allowed to submit to the Commission a transmission tariff and a request for declaratory order that the tariff meets the Commission's comparability (non- discrimination) standards. We would post these requests on the Commission Issuance Posting System (CIPS) and would provide them with an NJ (non-jurisdictional) docket designation. If we find that a tariff contains terms and conditions that substantially conform or are superior to those in the Final Rule pro forma tariff, we would deem it an acceptable reciprocity tariff and would require public utilities to provide open access service to that particular non-public utility. 494/ In order to find that a non-public utility's tariff is consistent with our comparability standards, we would need sufficient information to conclude that the non-public utility's rate is comparable to the rate it charges others. In addition, once we find that a tariff is an acceptable reciprocity tariff, an applicant in a section 211 case against a non-public utility would have the burden of proof to show why service to the applicant under the same terms as the reciprocity tariff is not sufficient and why a section 211 order should be granted.
The safe harbor procedures that we have outlined above would be purely voluntary for non-public utilities. The procedures are intended to provide non-public utilities an opportunity to confirm that they are willing to provide comparable transmission service. If, however, a non-public utility chooses not to seek a Commission determination that its tariff meets the Commission's comparability standards, a public utility could refuse to provide open access transmission service only if such denial is based on a good faith assertion that the non-public utility has not met the Commission's reciprocity requirements.
In addition to the safe harbor procedures, we note that a non-public utility that is a member of an RTG can meet our comparability standards through the RTG, and can provide an open access tariff that meets our comparability standards by filing a tariff with the administrator of the RTG. 495/ Similarly, a non-public utility that is a member of a power pool could meet our comparability standard if the power pool adopts a joint pool- wide open access tariff.
Some commenters have challenged the Commission's jurisdiction to require any non-public utility that takes jurisdictional service to provide reciprocal non-discriminatory transmission services and to unbundle its rates. We are not requiring non-public utilities to provide transmission access. Instead, we are conditioning the use of open access services on an agreement to offer open access services in return. Non-public utilities can choose not to take service under public utility open access tariffs and can instead seek voluntary service from the public utility on a bilateral basis.
In response to arguments raised by publicly-owned utilities and cooperatives, we are not prepared to revise or eliminate the reciprocity condition. Our reason is simple and compelling. We are undertaking this Rule and imposing significant responsibilities on public utilities to ensure the Nation's transmission grid is open and available to customers seeking access to the increasingly competitive commodity market for electricity. While we do not have the authority to require non- public utilities to make their systems generally available, we do have the ability, and the obligation, to ensure that open access transmission is as widely available as possible and that this Rule does not result in a competitive disadvantage to public utilities. Non-public utilities, whether they are selling power from their own generation facilities or reselling purchased power, have the ability to foreclose their customers' access to alternative power sources, and to take advantage of new markets in the traditional service territories of other utilities. While we do not take issue with the rights these non-public utilities may have under other laws, we will not permit them open access to jurisdictional transmission without offering comparable service in return. We believe the reciprocity requirement strikes an appropriate balance by limiting its application to circumstances in which the non-public utility seeks to take advantage of open access on a public utility's system. However, we recognize that Congress has determined that certain entities in the bulk power market can utilize tax-exempt financing by issuing bonds that do not constitute "private activity bonds" 496/ or by financing facilities with "local furnishing" bonds. 497/ In both circumstances, Congress has entrusted the Internal Revenue Service (IRS) with the responsibility for implementation and for determining what uses of the facilities are consistent with maintaining tax-exempt status for bonds used to finance such facilities. It is not our purpose to disturb Congress's and the IRS's determinations with respect to tax-exempt financing.
We are encouraged that the IRS is presently reconsidering its private activity bond regulations in light of, among other things, the changing circumstances in the electric industry, including this proceeding. 498/ We are hopeful that the IRS in its rulemaking will, to the maximum extent possible, remove regulatory impediments that limit the ability of industry participants to provide reciprocal open access service. Until that occurs, however, we believe we must ensure that the reciprocity requirement will not be used to defeat tax-exempt financing authorized by the Congress. Therefore, we clarify that reciprocal service will not be required if providing such service would jeopardize the tax-exempt status of the transmission customer's (or its corporate affiliates') bonds used to finance such transmission facilities. 499/ If a non-public utility has sought a declaratory order on a voluntarily-filed tariff, we request that it identify the services, if any, that it cannot provide without jeopardizing the tax-exempt status of its financing. 500/
We believe, given the fact that the IRS is currently examining these issues, that our policy in this regard is appropriate for the time being. After the IRS acts, we will reexamine our policy to ensure that the reciprocity requirement is applied broadly to achieve open access without jeopardizing tax-exempt financing.
With respect to local furnishing bonds, which are available to a handful of public utilities, we note that Congress, in section 1919 of the Energy Policy Act, amended section 142(f) of the Internal Revenue Code to provide that a facility shall not be treated as failing to meet the local furnishing requirement by reason of transmission services ordered by the Commission under section 211 of the FPA if "the portion of the cost of the facility financed with tax-exempt bonds is not greater than the portion of the cost of the facility which is allocable to the local furnishing of electric energy." 501/ San Diego G&E has included in its existing transmission tariff a provision that provides that, if it appears that the provision of transmission service would jeopardize the tax-exempt status of any local furnishing bonds used to finance its facilities, San Diego G&E will not contest the issuance of an order under section 211 of the FPA requiring the provision of such service, and will, within 10 days of receiving a written request by the applicant, file with the Commission a written waiver of its rights to a request for service under section 213(a) of the FPA and to the issuance of a proposed order under section 212(c). 502/ We believe such a provision is necessary and appropriate so that any local furnishing bonds that may exist do not interfere with the effective operation of an open access transmission regime. Accordingly, we will require any public utility that is subject to the Open Access Rule that has financed transmission facilities with local furnishing bonds to include in its tariff a similar provision. 503/
In addition, in response to arguments raised by cooperatives and joint action agencies, we agree to limit the reciprocity requirement to corporate affiliates. If a G&T cooperative seeks open access transmission service from the transmission provider, then only the G&T cooperative, and not its member distribution cooperatives, would be required to offer transmission service.
However, if