# Preventing Undue Discrimination and Preference in Transmission Service > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3AE8-144 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** January 16, 2008 - **Citation:** 73 FR 2984 ## Text DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 37 [Docket Nos. RM05-17-001, 002 and RM05-25-001, 002; Order No. 890-A] Preventing Undue Discrimination and Preference in Transmission Service Issued December 28, 2007. AGENCY: Federal Energy Regulatory Commission, DOE. ACTION: Order on rehearing and clarification. SUMMARY: The Federal Energy Regulatory Commission affirms its basic determinations in Order No. 890, granting rehearing and clarification regarding certain revisions to its regulations and the pro forma open-access transmission tariff, or OATT, adopted in Order Nos. 888 and 889 to ensure that transmission services are provided on a basis that is just, reasonable, and not unduly discriminatory. The reforms affirmed in this order are designed to: (1) Strengthen the pro forma OATT to ensure that it achieves its original purpose of remedying undue discrimination; (2) provide greater specificity to reduce opportunities for undue discrimination and facilitate the Commission's enforcement; and (3) increase transparency in the rules applicable to planning and use of the transmission system. DATES: Effective Date: This rule will become effective March 17, 2008. FOR FURTHER INFORMATION CONTACT: W. Mason Emnett (Legal Information), Office of the General Counsel—Energy Markets, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6540. Daniel Hedberg (Technical Information), Office of Energy Market Regulation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6243. Tony Ingram (Technical Information), Office of Energy Market Regulation, 888 First Street, NE., Washington, DC 20426, (202) 502-8938. SUPPLEMENTARY INFORMATION: Table of Contents I. Introduction II. Need for and Applicability of Order No. 888 A. The Need for Reform B. Core Elements of Order No. 888 That Are Retained C. Scope and Applicability of Order No. 890 III. Reforms of the OATT A. Consistency and Transparency of ATC Calculations B. Coordinated, Open, and Transparent Planning C. Transmission Pricing 1. Energy and Generation Imbalances 2. Credits for Network Customers 3. Capacity Reassignment 4. “Operational” Penalties 5. “Higher of” Pricing Policy 6. Other Ancillary Services D. Non-Rate Terms and Conditions 1. Modifications to Long-Term Firm Point-to-Point Service 2. Rollover Rights 3. Modification of Receipt or Delivery Points 4. Acquisition of Transmission Service 5. Designation of Network Resources 6. Clarifications Related to Network Service 7. Transmission Curtailments 8. Standardization of Rules and Practices 9. OATT Definitions E. Enforcement IV. Information Collection Statement V. Document Availability VI. Effective Date and Congressional Notification Regulatory Text Appendix A: Petitioner Acronyms Appendix B: Post-Technical Conference Commenter Acronyms Appendix C: Pro Forma Open Access Transmission Tariff Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff. I. Introduction 1. On February 16, 2007, the Commission issued Order No. 890, 1 addressing and remedying opportunities for undue discrimination under the pro forma Open Access Transmission Tariff (OATT) adopted in Order No. 888. 2 The pro forma OATT was intended to foster greater competition in wholesale power markets by reducing barriers to entry in the provision of transmission service. In the ten years since Order No. 888, however, flaws in the pro forma OATT undermined its ability to realize the core objective of remedying undue discrimination. The Commission acted in Order No. 890 to correct these flaws by reforming the terms and conditions of the pro forma OATT in several critical areas, including the calculation of available transfer capability (ATC), the planning of transmission facilities, and the conditions of services offered by each transmission provider. 1 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 FR 12,266 (March 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007) (Order No. 890). 2 Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996), order on reh'g , Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g , Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000) ( TAPS v. FERC ), aff'd sub nom. New York v. FERC , 535 U.S. 1 (2002). 2. Many have expressed support of the Commission's reforms. Greater specificity regarding the transmission provider's obligations under its OATT will reduce opportunities for the exercise of undue discrimination, make undue discrimination easier to detect, and facilitate the Commission's enforcement of the tariff. Greater transparency in the rules applicable to the planning and use of the transmission system will help both transmission providers and customers comply with applicable tariff requirements. Although we grant rehearing and clarification below to address certain implementation issues raised by petitioners, we leave in place the fundamental reforms adopted in Order No. 890. 3. At the outset, we note that work is well underway to develop consistent practices governing the calculation of ATC, in coordination with the North American Electric Reliability Corporation (NERC) and the North American Energy Standards Board (NAESB). Eliminating the broad discretion that transmission providers currently have in calculating ATC will increase nondiscriminatory access to the grid and ensure that customers are treated fairly in seeking alternative power supplies. We commend transmission providers for the substantial resources they have dedicated to this process and NERC and NAESB for their leadership in guiding the standardization effort. 4. We also commend transmission providers for the substantial resources dedicated to the development of transmission planning processes in response to Order No. 890. Transmission providers and stakeholders recently submitted tariff proposals that will govern transmission planning under the pro forma OATT. Transmission planning is critical because it is the means by which customers consider and access new sources of energy and have an opportunity to explore the feasibility of non-transmission alternatives. It is therefore vital for each transmission provider to open its transmission planning process to customers, coordinate with customers regarding future system plans, and share necessary planning information with customers. 5. In addition, transmission providers have implemented new service options for long-term firm point-to-point customers and adopted modifications to other services. Instead of denying a long-term request for point-to-point service because as little as one hour of service is unavailable, transmission providers must now consider their ability to offer a modified form of planning redispatch or a new conditional firm option to accommodate the request. This increases opportunities to efficiently utilize transmission by eliminating artificial barriers to use of the grid. Charges for energy and generation imbalances also have been standardized, including relaxed penalties for intermittent resources. This standardization reduces the potential for undue discrimination, increases transparency, and reduces confusion in the industry that resulted from the prior lack of consistency. 6. Taken together, these and other reforms adopted in Order No. 890 will better enable the pro forma OATT to achieve the core object of remedying undue discrimination in the provision of transmission service. The Commission therefore rejects requests to eliminate, or substantially modify, the various reforms adopted in Order No. 890. 3 We address each of the arguments made by petitioners in turn. We also address comments received in response to the technical conference held by Commission staff on July 30, 2007, regarding certain issues related to the designation and termination of network resources, in section III.D.5. 4 3 A list of petitioners filing requests for rehearing and/or clarification is provided in Appendix A. The requests for rehearing filed by American Transmission, Bonneville, EPSA, Pacific Northwest Parties, and REPIO are deficient because they fail to include a Statement of Issues section separate from the arguments made, as required by Rule 713 of the Commission's Rules of Practice and Procedure. See 18 CFR 385.713(c)(2). Consistent with Rule 713, we deem these petitioners to have waived the particular issues for which they seek rehearing. We also reject TranServ's request for rehearing for having been filed late, in violation of section 313(a) of the Federal Power Act (FPA). See 16 U.S.C. 8351(a). The Commission does consider, however, these petitioners' requests for clarification, to the extent they are not in fact requests for rehearing. We also address the merits of each request for rehearing to demonstrate that, had they been considered, our decision would be unchanged. 4 A list of parties filing comments in response to the July 30, 2007 technical conference is provided in Appendix B. II. Need for and Applicability of Order No. 888 A. The Need for Reform 7. As the Commission noted in Order No. 888, it is in the economic self-interest of transmission monopolists to deny transmission to competitors or to offer transmission on a basis that is inferior to that which they provide themselves. 5 The Commission sought to remedy that potential for discrimination through adoption of the pro forma OATT in Order No. 888. Despite the many accomplishments of Order No. 888, the Commission determined in Order No. 890 that the existing pro forma OATT continued to allow transmission providers substantial discretion in implementing some of its basic requirements. This discretion, in turn, created substantial opportunities for undue discrimination. Order No. 890 reformed the pro forma OATT to limit opportunities for undue discrimination and promote efficient use of the grid. 5 Order No. 888 at 31,682. 8. In Order No. 890, the Commission rejected arguments that it was relying on unsubstantiated allegations of discriminatory conduct to justify its reforms. Although certain commenters did allege discriminatory conduct in response to the Notice of Proposed Rulemaking (NOPR) initiating this proceeding, 6 the Commission made clear that it was not making specific factual findings of discrimination and that such specific findings were not required in order for it to promulgate a generic rule to eliminate undue discrimination. 7 The Commission explained that it had ample grounds to act as necessary to limit opportunities for undue discrimination that continue to exist under the pro forma OATT. 6 Preventing Undue Discrimination and Preference in Transmission Service, Notice of Proposed Rulemaking, 71 FR 32,636 (Jun. 6, 2006), FERC Stats. & Regs. ¶ 32,603 (2006) (NOPR). 7 See Order No. 890 at P 41 (citing Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom., New York v. FERC, 535 U.S. 1 (2002); National Fuel Gas Supply Corp v. FERC, 468 F.3d 831 (D.C. Cir. 2006)). Requests for Rehearing and Clarification 9. Many petitioners agree with the Commission on rehearing that reforms to the pro forma OATT are needed because there continues to be both the opportunity and incentive for transmission providers to engage in undue discrimination. 8 Two petitioners, however, seek rehearing of that finding as sufficient justification for adopting the reforms set forth in Order No. 890. 8 See e.g., Constellation, MISO, NRECA, Powerex, PSEG, and TAPS. 10. E.ON U.S. argues that the Commission has not presented any actual evidence of discrimination or opportunities for undue discrimination. Without actual evidence of discrimination, E.ON U.S. argues that the Commission lacks reasoned support for its finding that the reforms adopted in Order No. 890 are necessary to remedy undue discrimination. E.ON U.S. states a particular concern for the cost of implementing these reforms. E.ON U.S. contends that, absent evidence of unduly discriminatory behavior, the burdensome nature of compliance with Order No. 890 outweighs the benefits of its reforms. 11. Southern expresses similar concern that Order No. 890 lacks actual findings of discrimination. Southern claims that the theoretical claims of discrimination relied upon by the Commission are attenuated and inconsistent with statements discouraging commenters from making sweeping generalizations regarding undue discrimination. Rather than predicating Order No. 890 on the Commission's authority to prevent undue discrimination, Southern suggests that the Commission clarify that it is promulgating these reforms pursuant to its authority to ensure just and reasonable rates and not to prevent undue discrimination. 12. Southern also argues that the Commission failed to acknowledge other legal requirements and processes adopted after issuance of Order No. 888 that mitigate a transmission provider's incentives to discriminate, such as the Standards of Conduct, enforcement audits, new civil penalty authority, and mandatory reliability standards. Southern contends that transmission providers have a pecuniary incentive to grant, rather than deny, customer requests since doing so provides additional OATT revenues. Southern argues that the Commission appears to equate discretion with opportunities for discrimination, yet in certain circumstances expressly acknowledges that the transmission provider retains discretion in certain activities. Commission Determination 13. The Commission concluded in Order No. 890 that reforms to the pro forma OATT were necessary to address remaining opportunities for undue discrimination by transmission providers. Despite the efforts of Order No. 888 and our subsequent reforms, including those cited by Southern, opportunities for undue discrimination continued to exist. Under section 206 of the FPA, the Commission has a continuing obligation to “determine whether any rule, regulation, practice or contract affecting rates for such transmission or sale for resale is unduly discriminatory or preferential, and must prevent those contracts and practices that do no meet this standard.” 9 The Commission's finding that continuing opportunities to discriminate exist therefore supports our action under FPA section 206 to adopt changes to the pro forma OATT. Upon review of the extensive record of this proceeding, including the support of a vast majority of commenters, the Commission remains convinced that the particular reforms adopted in Order No. 890 are appropriate to satisfy our obligation to remedy undue discrimination. 9 Order No. 888 at 31,669. 14. We reject E.ON U.S.' arguments that, without actual evidence of undue discrimination, Order No. 890 lacks reasoned support. As the Commission explained in Order No. 890, the courts have made clear that the Commission need not make specific factual findings of discrimination in order to promulgate a generic rule to eliminate undue discrimination. In Associated Gas Distributors v. FERC , the D.C. Circuit Court explained that the promulgation of generic rate criteria involves the determination of policy goals and the selection of the means to achieve them. 10 The court concluded that, just as courts do not insist on empirical data for every proposition upon which the selection depends, “[a]gencies do not need to conduct experiments in order to rely on the prediction that an unsupported stone will fall.” 11 The Commission exercised this authority in Order No. 890, discussing with particularity the concerns motivating each of the reforms adopted. As it did in Order No. 888, the Commission properly acted to limit continuing opportunities for undue discrimination, not to remedy actual instances of undue discrimination. 10 824 F.2d 981 (D.C. Cir. 1987). 11 Id . at 1008. 15. We acknowledge, as argued by Southern, that it is appropriate for transmission providers to retain discretion in some areas and that such discretion does not necessarily equate to discrimination. It is also true that some OATT revenues may increase as requests for service are granted (such as for point-to-point requests), rather than denied. This is not always or even predominantly the case, however, given that rates for network service are based on load-ratio shares and revenues do not increase with designations of network resources unless new facilities are constructed. Moreover, there are competing incentives for a transmission provider to deny or restrict service to customers in certain circumstances and allowing broad discretion in such areas is no longer appropriate. The Commission identified these areas in Order No. 890, including the calculation of ATC, planning for transmission needs, and the provision of certain transmission services, and acted to remedy potential discrimination in each area. Notwithstanding the other legal requirements and processes cited by Southern, the Commission concluded in Order No. 890 that the reforms adopted were necessary based on a decade of experience administering the pro forma OATT. While the Standards of Conduct, audit procedures, and enhanced authority under the Energy Policy Act of 2005 (EPAct 2005) 12 have aided the Commission in fulfilling its obligations under the FPA, the reforms adopted in Order No. 890 are also necessary to reduce opportunities for the exercise of undue discrimination, make undue discrimination easier to detect, and facilitate the Commission's enforcement of the open access requirements. 12 Pub. L. No. 109-58, 119 Stat. 594 (to be codified in scattered titles of the U.S.C.). 16. We appreciate that a significant amount of resources must be dedicated to implementation of the reforms adopted in Order No. 890 by transmission providers. We believe the burden of implementing these reforms is fully justified by the need to eliminate remaining opportunities for undue discrimination in the administration and implementation of open access requirements under the pro forma OATT. We note, moreover, that these reforms will benefit transmission providers seeking to comply with our regulations in good faith by providing more clarity regarding the requirements of the pro forma OATT previously left open to interpretation, thereby decreasing the possibility of disputes with transmission customers and enforcement actions by the Commission. The ability of transmission customers to misuse the tariffs to their own advantage, particularly in the scheduling process, has similarly been addressed. Taken together, we conclude that the benefits of our reforms outweigh the associated costs of implementation. B. Core Elements of Order No. 888 That Are Retained 17. Although Order No. 890 introduced many important reforms, the Commission also retained many core elements from Order No. 888. As noted in the NOPR, many provisions of Order No. 888 enjoy broad support from many sectors of the industry and the Commission did not intend in this proceeding to pursue the same level of industry restructuring undertaken there. Rather, the Commission intended Order No. 890 to strengthen the pro forma OATT while retaining the fundamental structure articulated in Order No. 888. 18. The Commission thus retained the existing boundaries between wholesale and retail service drawn in Order No. 888. The Commission also retained the native load priority established in Order No. 888. The Commission stated that this priority continues to strike the appropriate balance between the transmission provider's need to meet its native load obligations and the needs of other entities to obtain service from the transmission provider to meet their own obligations. Order No. 890 also did not alter the types of services required under Order No. 888, i.e. , network service and point-to-point service. Finally, the Commission retained the functional unbundling requirement promulgated in Order No. 888. Requests for Rehearing and Clarification 19. South Carolina E&G objects to the Commission's decision to retain the native load priority established in Order No. 888, arguing that FPA section 217 requires further protection for native load service. South Carolina E&G states that the native load priority adopted under Order No. 888 was implemented so that all customers, native load and non-native load, would be entitled to equivalent, nondiscriminatory service. 13 South Carolina E&G argues that FPA section 217(k) now entitles load-serving entities (LSEs) to use their transmission systems to meet their state-law imposed native load service obligations and that this entitlement can no longer be deemed discriminatory under the FPA. To the extent an OATT provision compromising native load service is grounded in a finding of undue discrimination, South Carolina E&G argues that it must yield to the need to meet native load service obligations. 13 Citing Louisville Gas & Elec. Co. , 114 FERC ¶ 61,282 at P 125 (2006). 20. Joined by South Carolina Regulatory Staff, South Carolina E&G objects in particular to the Commission's decision to retain equal curtailment priority for all firm service. 14 These petitioners argue that requiring transmission providers to curtail service to network and point-to-point customers on a basis comparable to the curtailment of service to native load customers unfairly exalts non-native customers at the expense of the native load that financed the transmission system. They also contend the Commission's decision is inconsistent with Northern States Power Co . v. FERC , 15 which they argue prohibits mandating comparable curtailment priority among native load and non-native load services in the face of a state commission edict requiring a transmission provider to give its native load top curtailment priority. In their view, this precedent must be read broadly in light of enactment of FPA section 217(k), which they contend peremptorily counters any argument that priority for native load would be discriminatory. 14 South Carolina E&G and South Carolina Regulatory Staff also argue that reforms related to planning redispatch and conditional firm, rollover rights, and capacity reassignment are in violation of FPA section 217. We address those arguments in sections III.D.1, III.D.2, and III.C.3 respectively. 15 176 F.3d 1090 (8th Cir. 1999). 21. E.ON LSE similarly argues that FPA section 217 categorically protects an LSE's use of firm transmission service to the extent that such transmission service is required to meet the LSE's service obligation. E.ON LSE asks the Commission to allow LSEs to deviate from the requirements of Order No. 890 in circumstances where, in the LSE's good faith judgment, compliance would adversely affect the provision of firm transmission service to native load protected by FPA section 217. 22. TDU Systems request clarification or rehearing to confirm that there is no preference under the reformed pro forma OATT for a public utility transmission provider's native load over the service obligations of other LSEs that use their transmission system. TDU Systems argue that section 217(a) of the FPA does not distinguish between the service obligations of transmission providers and the service obligations of their load serving customers and, therefore, neither should the pro forma OATT. Commission Determination 23. The Commission affirms the decision to retain the native load protections embodied in Order No. 888, as enhanced by the reforms adopted in Order No. 890. In Order No. 888, the Commission gave public utilities the right to reserve existing transmission capacity needed for native load growth reasonably forecasted within the utility's current planning horizon. 16 The Commission also allowed transmission providers to restrict rollover rights based on reasonably forecasted need at the time the contract is executed. 17 Contrary to petitioner's assertions, the native load protections affirmed in Order No. 890 satisfy the requirements of FPA section 217. Section 217 applies not only to distribution utilities providing service to end-users, but also to electric utilities with long-term contracts to provide service to a distribution utility. 18 Congress placed each of these types of customers on equal footing, regardless of their status as a network or firm point-to-point customer under the pro forma OATT or a transmission provider serving its native load. We therefore disagree with petitioners that section 217 requires the Commission to give top curtailment priority solely to network customers or the transmission provider serving native load. 16 See Order No. 888 at 31,394. 17 See id . at 31,745. 18 See EPAct 2005 sec. 1233(a)(3) (to be codified at section 217(a)(3) of the FPA, 16 U.S.C. 824q(a)(3)). Petitioners' reliance on Northern States Power Co . v. FERC , 176 F.3d 1090 (8th Cir. 1999), is therefore misplaced. As the Commission has explained, the court upheld our authority to require pro rata curtailment of both network/native load and firm point-to-point service except in the limited circumstance when it would require the shedding of bundled retail load. Indeed, FPA section 217 could be read to grant electric utilities with long-term contracts to provide service to a distribution utility equal curtailment priority with other LSEs even in that limited situation, although we decline to address that argument here as it has not been raised on rehearing. 24. We decline to allow LSEs to deviate from the requirements of the pro forma OATT as they believe necessary to serve their native load, as suggested by E.ON LSE. Section 217 is intended to facilitate the ability of all utilities using firm transmission to meet their long-term service obligations, which the statute defines broadly to include not only service to end-users, but also distribution utilities serving end-users. 19 The requirements of the pro forma OATT and the reforms adopted in Order No. 890 appropriately balance the needs of these various classes of transmission customers, including the transmission provider's native load, LSE customers serving network load, and other firm users of the system. This is entirely consistent with, if not expressly required by, FPA section 217. 19 See EPAct 2005 sec 1233(a) (to be codified at section 217(a) of the FPA, 16 U.S.C. 824q(a)). C. Scope and Applicability of Order No. 890 25. The reforms adopted in Order No. 890 apply to all transmission providers, including Commission-approved regional transmission organizations (RTOs) and independent system operators (ISOs), and non-public utility transmission providers with reciprocity obligations. The particular process for implementing certain of the reforms adopted in Order No. 890 varied depending on the type of transmission provider at issue. 26. For those transmission providers that have not been approved as ISOs or RTOs, and whose facilities are not under the control or within the footprint of an ISO or RTO, Order No. 890 established a two-tiered compliance process for adopting the non-rate terms and conditions of the revised pro forma OATT. These transmission providers were directed to submit FPA section 206 compliance filings that contain the revised non-rate terms and conditions of the revised pro forma OATT within 60 days after publication of the order in the Federal Register . 20 Any of these transmission providers that wished to retain a previously-approved variation from the Order No. 888 pro forma OATT that was substantively affected by a reform adopted in Order No. 890 were directed to submit, within 30 days after publication of Order No. 890 in the Federal Register , a request under FPA section 205 to retain those previously-approved variations, provided they continued to be consistent with or superior to the revised pro forma OATT adopted in Order No. 890. 20 The Commission subsequently extended by 60 days the date on which the reforms adopted in Order No. 890 would have otherwise been effective. See Preventing Undue Discrimination and Preference in Transmission Service , 119 FERC ¶ 61,037 (2007) (April 11 Order). 27. ISO and RTO transmission providers were directed to submit FPA section 206 compliance filings, within 210 days after the publication of Order No. 890 in the Federal Register , that contain the non-rate terms and conditions set forth in Order No. 890 or that demonstrate that their existing tariff provisions are consistent with or superior to the revised provisions of the pro forma OATT. Transmission-owning members of ISOs and RTOs, and non-ISO/RTO transmission providers within the footprint of an ISO or RTO, were similarly directed to make any necessary tariff filings within 210 days of its publication in the Federal Register . 28. With regard to non-public utility transmission providers, the Commission retained the reciprocity language of the Order No. 888 pro forma OATT with a few modifications. First, the Commission updated the language to contain references to ISOs and RTOs, requiring transmission customers that are members of, or that take service from, an ISO/RTO to make comparable service available to other members of the ISO/RTO. As proposed in the NOPR, the Commission did not adopt a generic rule to implement FPA section 211A, which allows the Commission to require an unregulated transmitting utility to provide transmission services at rates that are comparable to those it charges itself and under non-rate terms and conditions that are comparable to those it applies to itself, and are not unduly discriminatory or preferential. The Commission instead explained that it would follow a case-by-case approach to implementing FPA section 211A. Requests for Rehearing and Clarification 29. Few petitioners question the applicability of Order No. 890, although some are concerned with the timing of the compliance actions required by the Commission. Southern asks the Commission to grant rehearing and extend the initial compliance deadlines by 60 days and to remain open to further requests for extension if the deadlines set forth in Order No. 890 cannot be met. MidAmerican asks the Commission to extend the effective date for the revisions to the pro forma OATT to the first day of the month following the effective date of these reforms. MidAmerican contends that it will be burdensome for transmission providers and confusing to transmission customers to implement the reforms adopted in Order No. 890 in the middle of a billing cycle. 30. TDU Systems express concern with the burden of reviewing section 205 filings by transmission providers seeking a determination from the Commission that a previously-approved variation from Order No. 888 continues to be consistent with or superior to the revised pro forma OATT. TDU Systems contend that reviewing and evaluating these filings will be a large and time-consuming process. TDU Systems ask the Commission to allow transmission customers 45 days to perform their own evaluation and comment upon these filings, while retaining a 90-day deadline for the Commission to process the filings. Alternatively, TDU Systems request rehearing of the Commission's decision not to stagger the due dates for the various compliance filings required in Order No. 890. 31. Although they recognize that Order No. 890 preserves existing waivers of the obligations to file an OATT, Unitil and Alcoa seek explicit confirmation that their waivers of the obligation to maintain an Open Access Same-Time Information System (OASIS) site are still valid. Unitil notes that the Commission has found that it does not operate or control an interstate transmission grid. 21 In addition, Unitil states that it voluntarily offers relevant information to ISO-NE for posting on its OASIS Web site. Similarly, Alcoa notes that the Commission has granted waiver of OASIS requirements to its Long Sault division, which owns five transmission lines in northern New York connecting Alcoa to its electric energy suppliers. 22 Thus, Unitil and Alcoa seek confirmation that the Commission did not intend the OASIS requirements outlined in Order No. 890 to apply to their operations. 21 Citing Northern States Power Co. , 76 FERC ¶ 61,250 at 62,297 (2002). 22 Citing Alcoa Power Generating, Inc. (Long Sault Division) , 116 FERC ¶ 61,257 (2006). 32. NRECA requests clarification, or in the alternative rehearing, that the Commission did not intend in Order No. 890 to extend reciprocity obligations beyond transmission owning members of an ISO or RTO. NRECA contends that the Commission's modification to the pro forma OATT creates ambiguity by imposing the reciprocity obligation for all “members” of an ISO or RTO. NRECA points out that some members of ISOs and RTOs do not own transmission, such as transmission dependent utilities, state regulatory authorities and eligible end-use customers. NRECA argues that expanding the reciprocity obligation to require non-public utility transmission providers to provide service to non-transmission owning members of an ISO or RTO would contradict Commission precedent 23 and be unsupported by the record in this proceeding. 23 Citing American Transmission Co. LLC , 95 FERC ¶ 61,387 (2001). 33. WSPP requests that the Commission establish a date by which it must submit a compliance filing containing the non-rate terms and conditions of the revised pro forma OATT. WSPP states that it is neither a transmission provider nor an RTO/ISO and, instead, only has a limited open access transmission tariff on file with the Commission. WSPP states that this tariff only applies to its transmission-owning members that do not otherwise have an OATT. Commission Determination 34. In the April 11 Order, the Commission granted requests by EEI and others to extend by 60 days the date by which transmissions providers outside of ISO/RTO regions would have to submit compliance filings containing the non-rate terms and conditions of the revised pro forma OATT. 24 Southern's request for rehearing on this point is therefore moot. Similarly, we reject as unnecessary TDU Systems' request to allow transmission customers additional time to evaluate and comment upon compliance filings. These filings have already been made, comments have been filed, and in many cases orders addressing the filings have been issued. 24 April 11 Order at P 20. 35. The Commission also determined in the April 11 Order that it would be reasonable for a transmission provider to request that the imbalance-related provisions in Schedule 4 and Schedule 9 of the pro forma OATT be made effective on the first day of the billing cycle following the effectiveness of the underlying imbalance-related reforms. 25 MidAmerican does not explain or otherwise justify the need to delay the effectiveness of any other reforms until the following billing cycle. We therefore reject as moot MidAmerican's request to extend the effective date of the imbalance-related reforms adopted in Order No. 890 until the following billing cycle and reject as unsupported its request to extend the effective date of all other reforms adopted in Order No. 890. 25 Id. at P 22. 36. The Commission made clear in Order No. 890 that the reforms therein were not intended to disturb any existing waivers of the obligation to file an OATT or otherwise offer open access transmission service. 26 The criteria for waiver of Order No. 890, moreover, remains unchanged from that used to evaluate the requests for waiver under Order Nos. 888 and 889. Revocation of any waivers will continued to be considered on a case-by-case basis in response to concerns raised by interested parties. We clarify that this applies equally to existing waivers of Order No. 889 and requirements to maintain an OASIS site. 26 See Order No. 890 at P 135, n.105. 37. We grant rehearing, in response to NRECA, to revise section 6 of the pro forma OATT to require a customer that is a member of or that takes service from an RTO or ISO to provide comparable service, to the extent it owns transmission facilities, only to the transmission-owning members of the RTO or ISO. The Commission has expressed concern in the past that failure to grant reciprocity to transmission-owning members of an RTO or ISO would cause those members to lose the right to reciprocity solely as a result of participating in the RTO or ISO. 27 We did not intend to expand that obligation in Order No. 890 to other members of an RTO or ISO when revising the language of section 6 of the pro forma OATT to refer to RTOs and ISOs. 27 See American Transmission Company LLC , 93 FERC ¶ 61,267 at 61,858-59 (2000), reh'g denied , 95 FERC ¶ 61,387 at 62,446 (2001). 38. Below the Commission adopts various other revisions to the pro forma OATT in response to requests for rehearing and clarification. These revisions do not disturb the fundamental nature of the reforms adopted in Order No. 890 and, thus, we do not anticipate any difficulty in their implementation or disruption in on-going compliance efforts. We direct transmission providers that have not been approved as RTOs or ISOs, and whose facilities are not in the footprint of an RTO or ISO, to submit an FPA section 206 filing that contains the revised non-rate terms and conditions of the pro forma OATT stated in Appendix C within 60 days of publication of this order in the Federal Register . We direct RTO and ISO transmission providers, transmission providers whose facilities are in the footprint of an RTO or ISO, and WSPP to submit an FPA section 206 filing that contains the revised non-rate terms and conditions of the pro forma OATT as stated within Appendix C within 90 days of publication of this order in the Federal Register . III. Reforms of the OATT A. Consistency and Transparency of ATC Calculations 39. In Order No. 890, the Commission concluded that the lack of consistency and transparency in the methodology for calculating ATC creates the potential for undue discrimination in the provision of open access transmission service. To remedy this lack of consistency and transparency, the Commission directed public utilities, working through the NERC reliability standards and NAESB business practices development processes, to produce workable solutions to implement the ATC-related reforms adopted by the Commission. A number of petitioners seek rehearing and/or clarification regarding the Commission's ATC-related rulings, which we address below. 1. Consistency a. Necessary Degree of Consistency 40. The Commission required industry-wide consistency of all ATC components 28 and certain definitions, data inputs, data exchange, and modeling assumptions in order to reduce the potential for undue discrimination in the provision of transmission service. Although the Commission concluded that the number of industry-wide ATC calculation formulas should be few in number, it did not require that a single ATC calculation methodology be applied by all transmission providers. The Commission found that it is not the methodologies for calculating ATC that create the opportunity for undue discrimination, rather the variability in the calculation of the components of ATC and the lack of a detailed description of the ATC calculation methodology and underlying assumptions used by the transmission provider. 28 The ATC components are total transfer capability (TTC), existing transmission commitments (ETC), capacity benefit margin (CBM), and transmission reserve margin (TRM). 41. The Commission noted that NERC was then in the process of developing standards for three ATC calculation methodologies: contract or rated path ATC, network ATC, and network Available Flowgate Capacity (AFC). The Commission concluded that, if all of the ATC components and certain data inputs and assumptions are consistent, the use of the three ATC calculation methodologies included in reliability standards being developed would be acceptable. With regard to network AFC, the Commission specifically directed public utilities, working through NERC, to develop an AFC definition and requirements used to identify a particular set of transmission facilities as a flowgate. However, the Commission reminded transmission providers that our regulations require the posting of ATC values associated with a particular path, not AFC values associated with a flowgate. The Commission therefore directed public utilities, working through NERC, to develop in the MOD-001 standard a rule to convert AFC into ATC values to be posted by transmission providers that currently use the flowgate methodology. 42. The Commission also required further clarification regarding the calculation algorithms for firm and non-firm ATC. The Commission directed public utilities, working through NERC, to modify related ATC standards by implementing the following principles: (1) For firm ATC calculations, the transmission provider shall account only for firm commitments; and (2) for non-firm ATC calculations, the transmission provider shall account for both firm and non-firm commitments, postbacks of redirected services, unscheduled service, and counterflows. Requests for Rehearing and Clarification 43. Southern requests that the Commission clarify that consistency in ATC methodologies and CBM and TRM calculations must not take precedence over reliability and that some transmission provider discretion is necessary. Southern states that, in several places, Order No. 890 discusses minimizing transmission provider discretion in order to achieve consistency. 29 Southern contends that totally eliminating this discretion would not allow transmission providers to address unique system conditions in ATC, CBM, and TRM calculations, which would impact system reliability. Southern claims that eliminating transmission provider discretion also would lead to more conservative modeling, which would likely result in understated amounts of ATC and an inefficient use of the system. 30 To the extent making the treatment of certain ATC parameters or CBM or TRM calculations consistent would affect reliability, Southern asks that transparency in the treatment of those parameters and calculations be required, but that strict consistency not be enforced. 29 Citing Order No. 890 at P 207. 30 Southern suggests that one example of when a transmission provider should have discretion is when modeling long-term firm transmission service reservation from a combustion turbine generating facility. Southern argues that, by its nature, such a generating facility normally will not often run in off-peak times. During those times, or when there is an impending outage of a generating facility, Southern argues that the transmission provider should have the discretion to reflect the operating characteristics of the generating facility by not including transmission service from the facility in its model. 44. MidAmerican requests clarification that AFC quantities do not need to be converted into control area-to-control area path ATC quantities and that the Commission is not eliminating the coordination of individual transmission provider service with seams agreements and/or regional tariff service on flowgates. MidAmerican asks the Commission to confirm that it is merely intending to require NERC to define a flowgate ATC quantity which is equal to or related to the flowgate AFC. MidAmerican contends that transmission customers, operators, and owners will not benefit from the conversion of flowgate AFCs into control area-to-control area path ATCs, the elimination of AFC as a useful transmission commodity, or the elimination of the coordination of individual provider and regional transmission service over flowgates. To the extent the Commission feels there is a comparability benefit for the conversion of AFC to ATC, MidAmerican requests clarification that providing transmission customers with a mechanism on OASIS to query/assess the effective ATC on a specific transmission path over a specific time is sufficient for compliance with the transmission provider's ATC posting obligation. 45. E.ON U.S. requests clarification of the requirement that AFC calculations be converted into ATC for purposes of posting. E.ON U.S. states that some RTOs, such as MISO and others, utilize AFC and do not calculate or post ATC for their systems. Due to interactions with these RTOs, E.ON U.S. now calculates AFC as well. E.ON requests that the Commission clarify that if RTOs and their member utilities are granted waivers of the requirement to calculate and post ATC, in favor of AFC, all transmission owning utilities in the region should be able to request a waiver on the same basis. E.ON claims that allowing all transmission-owning utilities within a region to calculate AFC (instead of ATC) will result in greater accuracy and consistency within the industry. 46. Although it does not challenge the Commission's decision not to require a single, industry-wide ATC calculation method, TDU Systems claims that the Commission fails to address the situation where transmission providers on a single interface choose different ATC calculation methods. TDU Systems argue that transmission providers must be required to provide consistent ATC values on either side of an interface. TDU Systems therefore request that adjacent transmission providers be required to coordinate to provide consistent ATC values across their common interfaces. 47. NorthWestern requests that the Commission clarify that the consistency requirements of Order No. 890 do not prohibit utilities from reducing transfer capability for the purchase of reliability services. According to NorthWestern, some transmission providers may have to acquire various generation-based services, such as load following and regulation service, in the marketplace in order to meet reliability criteria. NorthWestern argues that some means should be allowed for retaining transmission at no cost for such deliveries, even though they do not meet the strict definition of CBM, since they are made for reliability reasons and no single user of the system would otherwise reimburse the transmission provider for the associated costs. 48. EPSA and Williams request clarification that ATC and AFC calculations should be determined and posted in real-time, not just as planning information, and that the transmission provider be required to post results of its system utilization for ETC. Williams contends that this would augment the transparency deemed critical to a coherent and uniform calculation of ATC by enabling interested stakeholders and the Commission to verify the ATC calculations performed by transmission providers. Commission Determination 49. The Commission affirms the decision in Order No. 890 to require consistency of all ATC components and certain definitions, data inputs, data exchange and modeling assumptions. We continue to believe such consistency is necessary to reduce the potential for undue discrimination in the provision of transmission service. 50. We disagree with Southern that increasing consistency with respect to the determination of ATC is contrary to reliability. Use of the NERC reliability standards process will, as a matter of course, guard against any unintended reduction in reliability. Nevertheless, we agree that reliability standards cannot address every unique system difference or differences in risk assumptions when modeling expected flows, which necessitates leaving room for limited discretion on the part of the transmission provider. We believe that the ATC requirements in Order No. 890 allow sufficient flexibility so that utilities, working through NERC/NAESB, can develop ATC standards that continue to provide reliability and are compatible with all other mandatory reliability standards or business practices, yet provide discretion where appropriate. If a transmission provider is faced with unique system conditions or modeling assumptions related to firm transmission service reservations 31 that are not addressed in the ATC-related NERC reliability standards, it must make them transparent through its Attachment C filing and the OASIS posting requirements regarding ATC calculation and modeling approach, studies, models and assumptions and implement them consistently for all transmission customers. 31 Transmission providers use different assumptions related to the percentage of firm reservations that are actually scheduled and flow. 51. We deny MidAmerican's request for clarification that AFC values do not need to be converted into ATC postings of control area-to-control area path quantities. As the Commission explained in Order No. 890, our regulations require the posting of ATC values associated with a particular path, not AFC values associated with a flowgate. 32 The Commission did not amend that requirement in Order No. 890 and MidAmerican fails to justify doing so now. To the extent MidAmerican or its customers find it beneficial also to post AFC, MidAmerican is free to post both ATC and AFC values. In response to E.ON U.S., however, we clarify that transmission-owning utilities in an RTO region can request waiver of the requirement to convert AFC calculations into ATC for posting purposes in the event the RTO has been granted such a waiver. 32 See Order No. 890 at P 211. ATC values must be posted for control area to control area interconnections, paths for which service is denied, curtailed or interrupted for more than 24 hours in the past 12 months, and paths for which a customer requests to have ATC or TTC posted. See 18 CFR 37.6(b)(1)(i). 52. In response to TDU Systems, we clarify that adjacent transmission providers must coordinate and exchange data and assumptions to achieve consistent ATC values on either side of a single interface. This is applicable to any neighboring transmission providers no matter whether they use the same or different ATC methodologies. We note, however, that the anticipated consistency is for available capability in the same direction across an interface. 53. We clarify in response to NorthWestern that TRM may be used to accommodate the procurement of ancillary services used to provide service under the pro forma OATT. We deny as premature EPSA's and Williams' requests for clarification regarding the real-time determination and posting of ATC and AFC values, as well as posting of utilization of transmission provider's own system ETC. In Order No. 890, the Commission required an exchange of the data both for short and long-term ATC/AFC calculation that will increase the accuracy of ATC calculations. 33 The Commission also required that ATC be recalculated by all transmission providers on a consistent time interval, and in a manner that closely reflects the actual topology of the system, load forecast, interchange schedules, transmission reservations, facility ratings, and other necessary data, and that NERC/NAESB revise the related reliability standard and business practices accordingly. 34 EPSA and William should address their concerns through the NERC and NAESB processes implementing these requirements. 33 See Order No. 890 at P 310. 34 See id . at P 301. b. Process To Achieve Consistency 54. The Commission directed public utilities, working through NERC and NAESB, to modify the ATC-related reliability standards and business practices in accordance with specific direction provided in Order No. 890. The Commission concluded that the NERC reliability standards development process and the NAESB business standards development process are the appropriate forums for developing consistency in ATC calculations. To that end, public utilities were directed, working through NERC, to modify the ATC-related reliability standards within 270 days after the publication of Order No. 890 in the Federal Register , i.e. , December 10, 2007. Public utilities were also directed, working through NAESB, to develop business practices that complement NERC's new reliability standards within 360 days after the publication of Order No. 890 in the Federal Register , i.e. , March 10, 2008. 35 35 The Commission has since extended these compliance deadlines to May 9, 2008, and August 7, 2008, respectively. See Preventing Undue Discrimination and Preference in Transmission Service, Notice of Extension of Time, Docket Nos. RM05-17-000, et al. (Dec. 6, 2007). Requests for Rehearing and Clarification 55. Several petitioners contend that the Commission's direction to public utilities, working through NERC, to modify standards to meet specific ATC requirements is tantamount to dictating reliability standards in violation of FPA section 215. 36 These petitioners assert that system reliability will be best maintained if NERC, having been certified by the Commission as the ERO, is afforded discretion in creating the necessary reliability standards in the first instance prior to submission to the Commission for approval consistent with section 215. 37 EEI and Southern suggest that the Commission give guidance and direction to NERC on how standards should be developed, but not be overly prescriptive. E.ON LSE argues that the Commission should require, or at least permit, NERC to consolidate its ATC development process with its ongoing reliability standards process to develop policies, but should refrain from rewriting any standards developed through that consolidated process. 36 E.g., EEI, E.ON LSE, and Southern. 37 Citing 16 U.S.C. 824o(d)(2) (requiring the Commission to “give due weight to the technical expertise of the [ERO]” on reliability matters). Commission Determination 56. The Commission affirms the decision in Order No. 890 to rely on the NERC reliability standards development process, and the NAESB business practices development process, to achieve a more coherent and uniform determination of ATC. We disagree that this conflicts with the Commission's obligations under section 215 of the FPA. In Order No. 693, the Commission exercised its authority under FPA section 215 to direct the ERO to modify the existing modeling, data, and analysis (MOD) standards related to ATC calculation, providing guidance consistent with our requirements in Order No. 890. The Commission clarified that, where Order No. 693 identified a concern and offered a specific approach to address the concern, the Commission would consider an equivalent alternative approach provided that the ERO demonstrated that the alternative would address the Commission's underlying concern or goal as efficiently and effectively as the Commission's proposal. 38 We believe this provides the appropriate flexibility for NERC, while ensuring that the Commission act to remedy the potential for undue discrimination in the calculation of ATC. 38 See Mandatory Reliability Standards for the Bulk Power System, Order No. 693, 72 FR 16,416 (Apr. 4, 2007), FERC Stats. & Regs. ¶ 31,242 (2007) (Order No. 693), order on reh'g, 120 FERC ¶ 61,053 (2007) (Order No. 693-A). Pending completion of the NERC/NAESB standardization process, each transmission provider must perform its ATC-related calculations in accordance with the methodology set forth in Attachment C to its OATT, as revised to comply with Order No. 890. c. Applicability to ISOs, RTOs, and Non-Public Utility Transmission Providers 57. The Commission did not require ISO and RTO transmission providers to “rejustify” existing provisions in their OATTs that are not affected in a substantive manner by the revisions to the pro forma OATT in the Final Rule. However, the Commission did require all transmission providers, including an ISO or RTO, to demonstrate that variations from the tariff modifications required in Order No. 890 continue to satisfy the consistent with or superior to standard. With respect to the application of the ATC requirements of Order No. 890, the Commission noted that ISOs and RTOs would be required to comply with reliability standards developed under FPA section 215. Requests for Rehearing and Clarification 58. Because Order No. 890 did not exempt ISOs/RTOs from the new ATC standards or curtailment information posting requirements, NYISO asks the Commission to clarify that NERC and NAESB must develop ATC standards and curtailment information posting rules that accommodate ISOs/RTOs. NYISO anticipates that ATC calculations will continue to be of limited significance within its control area, but acknowledges that it does calculate ATC at its external interfaces and also uses ATC to determine the availability of non-firm transmission service, i.e. , service for customers that do not wish to be exposed to congestion charges. NYISO states that it, therefore, has an interest and intends to participate in the NERC and NAESB processes developing new ATC standards and curtailment information posting requirements. 59. NYISO contends, however, that stakeholders from traditional systems will have a greater interest in the development of those rules and, as a result, that the NERC and NAESB processes may produce rules that primarily reflect the needs of traditional systems and do not accommodate ISOs/RTOs that are based upon locational marginal pricing of transmission. NYISO argues that Order No. 890 requires NERC and NAESB to develop standards that suit both traditional systems as well as the ISOs/RTOs that cover more than half of the load in the United States. NYISO requests that the Commission expressly state its expectation that the NERC and NAESB processes will produce standards that fulfill Order No. 890's objectives of transparency and inter-regional consistency, yet that are sufficiently flexible to work for ISO/RTO regions. Commission Determination 60. Order No. 890 requires NERC and NAESB to develop a single set of ATC-related standards that will apply to all transmission providers, including RTOs and ISOs. We understand that the NERC ATC standard drafting team includes representatives from various industry sectors, including RTOs/ISOs, and we encourage NYISO to participate in the standard development process to provide NERC an opportunity to address its concerns. To the extent NYISO feels its concerns are not addressed in this process, it should bring the issue to the Commission's attention on review of the resulting reliability standards. d. ATC Components 61. In Order No. 890, the Commission adopted certain requirements regarding the components of ATC ( i.e. , TTC/TFC, ETC, CBM and TRM) necessary to achieve consistency and, in turn, limit the potential for undue discrimination in the calculation of ATC. Petitioners request rehearing and clarification of the Commission's determinations related to ETC, CBM and TRM, which we address in turn. (1) ETC 62. The Commission adopted the NOPR proposal and directed public utilities, working through NERC and NAESB, to develop a consistent approach for determining the amount of transfer capability a transmission provider may set aside for its native load and other committed uses. The Commission determined that ETC should be defined to include committed uses of the transmission system, including (1) native load commitments (including network service), (2) grandfathered transmission rights, (3) appropriate point-to-point reservations, 39 (4) rollover rights associated with long-term firm service, and (5) other uses identified through the NERC process. The Commission determined that ETC should not be used to set aside transfer capability for any type of planning or contingency reserve, which are to be addressed through CBM and TRM. 40 In addition, for short-term ATC calculations, all reserved but unused transfer capability (non-scheduled) must be released as non-firm ATC. 39 The Commission explained that the reference to “appropriate point-to-point reservations” meant that reservations accounted for under ETC depend on the firmness and duration of the reservation. The Commission stated that the specific characteristics should be developed in the reliability standard. 40 TRM also includes such things as loop flow and parallel path flow. 63. The Commission also found that inclusion of all requests for transmission service in ETC would likely overstate usage of the system and understate ATC. The Commission therefore found that reservations that have the same point of receipt (POR) (generator) but different point of delivery (POD) (load), for the same time frame, should not be modeled in the ETC calculation simultaneously if their combined reserved transmission capacity exceeds the generator's nameplate capacity at the POR. The Commission directed public utilities, working through NERC, to develop requirements in MOD-001 that lay out clear instructions on how these reservations should be modeled. The Commission also concluded that some elements of ETC are candidates for business practices instead of reliability standards and directed public utilities, working through NAESB, to develop business practices necessary for full implementation of the MOD-001 reliability standard. Requests for Rehearing and Clarification 64. TDU Systems contend that, although the Commission defined the ETC component of ATC to include committed uses of the transmission system, it did not clearly identify how requests for transmission service are to be treated. TDU Systems question whether the Commission's use of the term “committed requests” is the same as “confirmed requests” for service. In order to provide greater clarity, certainty and transparency to the ATC calculation process, TDU Systems ask the Commission to clarify that “committed requests” means the same thing as “confirmed requests,” as this term is generally understood throughout the industry. 65. TranServ requests clarification that the Commission's statement that all reserved but unused transfer capability (non-scheduled) shall be released as non-firm ATC was limited to the release of unscheduled firm transmission capability and not intended to require transmission providers to release unscheduled non-firm capability for additional non-firm sales. 41 41 Citing Order No. 890 at 244, 389. Commission Determination 66. The Commission clarifies in response to TDU Systems' request that the reference to “committed requests” in Order No. 890 was intended to refer to confirmed transmission service requests. Once a service request has been approved by the transmission provider and confirmed by the transmission customer, it should be taken into account when determining ETC. 67. We also agree with TranServ that the Commission's reference to releasing unused (non-scheduled) transfer capability as non-firm ATC applies to unscheduled firm transmission capability, since all unused non-firm capacity is deemed available to any entity meeting the scheduling requirements. This does not alter the requirement that the transmission provider offer all available capacity, firm or non-firm, as applicable, consistent with our longstanding open access principles. (2) CBM 68. The Commission directed public utilities, working through NERC and NAESB, to develop clear standards and business practices for how the CBM value is determined, allocated across transmission paths and flowgates, and used. To ensure that CBM is used for its intended purpose, the Commission provided that CBM shall only be used to allow an LSE to meet its generation reliability criteria. The Commission rejected requests to allow CBM to be used to meet reserve-sharing needs, explaining that TRM is the appropriate category for that purpose. Public utilities were directed to work with NAESB to develop an OASIS mechanism that will allow for auditing of CBM usage. 69. The Commission clarified that each LSE within a transmission provider's control area has the right to request the transmission provider to set aside transfer capability as CBM for the LSE to meet its historical, state, RTO, or regional generation reliability criteria requirement such as reserve margin, loss of load probability, the loss of largest units, etc. It also determined that LSEs should be permitted to call for the use of CBM, pursuant to conditions established in the reliability standards development process. Public utilities were directed to work through NERC to modify the CBM-related standards to specify the generation deficiency conditions during which an LSE will be allowed to use the transfer capability reserved as CBM. The Commission also directed public utilities, working through NERC, to develop clear requirements for allocating CBM to paths and flowgates and concluded that transmission capacity set aside as CBM shall be zero in non-firm ATC calculations. 70. Finally, the Commission required the transmission provider to design their transmission charges so that the class of customers not benefiting from the CBM set-aside, i.e. , point-to-point customers, do not pay a transmission charge that includes the cost of the CBM set-aside. Transmission providers were permitted to submit redesigned transmission charges that reflect the CBM set-aside through a limited issue FPA section 205 rate filing. The Commission noted that these filings may be limited to the rate design change only, i.e. , they would not require the submission of cost of service data or a revision to the transmission provider's revenue requirement. Requests for Rehearing and Clarification 71. Duke requests that the Commission clarify that utilities that do not reserve CBM for themselves do not need to make it available to others. Although the Commission required transmission providers to make CBM available to LSEs that request it, Duke argues that the Commission has no authority under FPA section 206 to require transmission providers to do so when they do not use CBM themselves since there is no potential for undue discrimination. 72. With regard to the calculation of CBM, Southern argues that requiring a consistent calculation methodology would be harmful to LSEs because reserve needs vary from area to area. Southern contends that LSEs should be allowed the flexibility to establish CBM on a per-interface basis so that CBM use will be commensurate with expected system conditions, topography, and available capacity markets. Southern states, for example, that small LSEs typically have fewer internal resources than larger LSEs and therefore need more CBM. Southern contends that a consistent methodology could result in higher infrastructure cost, place system reliability at risk, and ultimately remove the economic benefit associated with CBM. 73. Southern also argues that development of a “one-size-fits all” methodology for the calculation of CBM would be impossible due to varying regional and state mandates governing generation adequacy issues. Southern contends that such a mandate, if applied to a transmission provider's native load customers that are under varying regional and state resource adequacy requirements, would amount to a regulation of reserve adequacy which is outside of the Commission's jurisdiction. Southern adds that this would implicate (and may violate) the reliability provisions of FPA section 215 and the native load protections of FPA section 217. 74. TDU Systems request that the Commission clarify, or grant rehearing, that if a transmission provider does not accommodate reserve-sharing arrangements for its load-serving transmission customers as TRM, then it must allow access to the CBM set-aside for reserve-sharing purposes. TDU Systems are concerned that some transmission providers do not use TRM set-asides, but rather use a CBM-approach to reserving capacity across interfaces for reserve-sharing arrangements. In such cases, TDU Systems state that LSEs needing access to interface capacity to accommodate reserve-sharing arrangements may not be able to obtain that capacity if the Commission limits such usage to TRM. TDU Systems contend that transmission providers set aside interface capacity to serve their retail native load in the case of both generation emergencies and economic transactions and that comparability demands the same for the reserve-sharing arrangements for LSEs. 75. With regard to cost recovery of the CBM set-aside, Southern argues that CBM is a component of network service that is already paid for by network customers and native load through their bearing a load-ratio share responsibility for the costs of the transmission system. Southern contends that CBM is used as a network reservation of resources used to service network and/or native load under certain conditions. Southern argues that a network customer's cost responsibility is based upon its load, not its designation of network resources and, therefore, the network customer is already bearing CBM-related costs through its load ratio share responsibility. 76. As a result, Southern concludes that point-to-point customers are not paying for CBM capacity and, instead, are paying their appropriate share of the total transmission system cost based upon their reservations of capacity. Southern states that Commission policy requires network customers and native load to bear the costs of both the capacity they use and any capacity that is not reserved by point-to-point customers. 42 Southern argues that the Commission's finding in Order No. 890 that point-to-point customers are inappropriately bearing the costs of CBM represents an unexplained departure from Order No. 888-A. 42 Citing Order No. 888-A at P 30,220. 77. Southern also contends that this ruling will result in an inconsistency within the pro forma OATT, requiring incremental cost responsibility for network customers to utilize one particular type of external resource or off-system purchase, i.e. , the utilization of CBM. Southern argues that this conflicts with the structure of network service under the pro forma OATT, which allows the network customer to utilize the interfaces for both external designated network resources and off-system opportunity purchases without additional charge. Southern also contends that requiring network customers to pay for CBM on the same basis as firm point-to-point service disadvantages the use of CBM since interface capacity could only be used on an emergency basis and therefore is not considered firm service for the purpose of designating off-system system resources. 78. Southern goes on to assert that the Commission's premise that point-to-point customers are not benefiting from CBM is incorrect. Southern notes that under normal conditions the transfer capability reserved as CBM is made available for non-firm use by other customers. Southern notes also that long-term point-to-point customers benefit from the non-firm point-to-point use of that transfer capability because associated revenues are included as revenue credits in the numerator of the OATT rate calculations to reduce charges to long-term firm point-to-point customers. 79. If the Commission does not reverse its decision in Order No. 890 regarding the redesign of transmission charges, Southern seeks clarification regarding how the CBM set-aside should be treated for ratemaking purposes since it does not represent additional load. Southern notes that the potential for long-term customers to receive a rate benefit from the non-firm point-to-point use of the set-aside raises the potential for them receiving a double credit. Southern also suggests that the Commission defer the new rate design filing until after NERC has adopted ATC standards under MOD-001. 80. EEI and Idaho Power raise similar concerns, asking the Commission to clarify that, when the transmission provider modifies its rate design for point-to-point transmission service, it also may propose a rate design modification to ensure that it recovers from network and native load customers any reduction in revenues resulting from the change in the rates for point-to-point service. Duke contends that allocating costs of the CBM set-aside through a downward revision to point-to-point rates would have the effect of allocating costs to native load and network customers for a service that is not taken. EEI and Idaho Power argue that the Commission should allow transmission providers to modify their rates for other services in order to prevent under-recovery of their costs of service or inappropriately shifting costs to native load customers. EEI also requests the Commission to clarify that the rate design change may take into consideration the fact that transmission providers credit against the cost of service revenues received from short-term and non-firm transmission service provided using capacity that is set aside for CBM to ensure that long-term firm point-to-point customers do not receive a double credit for the use of CBM capacity. 81. EEI requests further clarification regarding how a transmission provider should modify unit charges that are established by settlement. EEI argues that transmission providers should not be required to make an entirely new cost-of-service filing and, instead, should be permitted to reduce its rates for firm point-to-point service by the ratio of its current transmission load and reservations without the CBM set-aside to its transmission load and reservations plus the CBM set-aside. Commission Determination 82. The Commission clarifies in response to Duke that utilities do not need to make CBM available to LSEs on their system if the utilities do not reserve for themselves CBM or its equivalent. Comparability only requires transmission providers to make CBM available when they set aside for themselves transfer capability to meet generation reliability criteria. 43 In order to provide transparency and consistency regarding the use of CBM, public utilities, working through NERC, must develop clear standards for how CBM is determined, allocated across transmission paths, and used. 44 43 We note that Duke states, in its Attachment C compliance filing, that it has set CBM on all of its interfaces to zero because it uses short-term line ratings (where available), which yields an operating margin that may be used for unexpected conditions or inaccuracies in data. See Compliance filing of Duke Energy Carolinas, Docket No. OA07-82-000 (Sep. 10, 2007); Open Access Transmission Tariff of Duke Energy Carolinas, LLC, FERC Electric Tariff Fifth Rev. Vol. No. 4, Original Sheet 170H. The Commission will address the merits of that practice in Docket No. OA07-82-000. 44 Order No. 890 at P 256, 259. 83. The Commission did not mandate a particular methodology for allocating CBM over transmission paths and flowgates in Order No. 890. We therefore reject Southern's argument that development of a consistent methodology for calculating CBM would be harmful to LSEs because reserve needs vary from area to area. While we expect the NERC and NAESB process to produce a consistent and transparent process for setting aside and allocating CBM based on LSE requests, we decline to prescribe a specific method for how CBM should be obtained or allocated or otherwise determine the amount of capacity that the transmission provider has to set aside in response to requests from multiple LSEs. 84. We disagree that a consistent CBM methodology that allows LSEs access to historically used resources would impair reliability, conflict with the rights of native load under FPA section 217, or otherwise implicate varying regional and state mandates governing adequacy issues. In any event, it is premature to consider these questions since NERC and NAESB have yet to complete their work on the reliability standards and business practices. We also disagree with Southern that a consistent CBM methodology will remove the economic benefit associated with CBM. Rather, a consistent methodology for determining how the CBM value is determined, allocated, and used will remove excess discretion that transmission providers previously had and allow all LSEs to have the benefits associated with CBM. 85. Regarding TDU Systems' request to use CBM for reserve-sharing arrangements, we reiterate that TRM is the appropriate category for reserve-sharing arrangements and that CBM is to meet verifiable generation reliability criteria in times of emergency generation deficiencies. 45 As the Commission explained in Order No. 890, TRM may be used for other transmission-related uncertainties as well. 46 Because the transmission provider may set aside transfer capability for TRM to operate the system reliably, we reject TDU Systems' request to use CBM for reserve-sharing purposes. 45 See id. at P 264. 46 See id. at P 273. 86. With regard to cost recovery of the CBM set-aside, we affirm the decision in Order No. 890 to require transmission providers to design their transmission charges to ensure that the class of customers not benefiting from the CBM set-aside, i.e. , point-to-point customers, do not pay a transmission charge that includes the cost of the CBM set-aside. Only network customers and the transmission provider on behalf of its native load may request that transmission capacity be set aside as CBM and, therefore, only those users of the system should bear its costs. We disagree with Southern that, because CBM is used by network customers, all the costs associated with CBM are already borne by network customers through their load ratio share responsibility. As Southern acknowledges, the rates for point-to-point service are also calculated based on a share of total transmission system cost. If the costs associated with CBM are not excluded from the universe of costs allocated to all point-to-point customers, then every point-to-point customer will end up paying a portion of those costs. The Commission's rate design ruling is therefore consistent with, not contrary to, the Commission's directive in Order No. 888-A for network customers and native load to bear the cost of capacity not used by point-to-point customers. 47 47 See Order No. 888-A at 30,220. 87. We acknowledge, as Southern claims, that point-to-point customers do reap some indirect benefits from the CBM set-aside in that related capacity that is not used is made available on a non-firm basis and that, in turn, can generate revenues that are credited to the transmission cost of service to the benefit of point-to-point customers. We do not believe this justifies charging all point-to-point customers for the cost of the CBM set-aside. These costs should instead be allocated to the entities that have the exclusive right to request the set-aside in the first instance. We agree that, in certain circumstances, this may necessitate modification of other rate design elements to ensure that costs are appropriately allocated and that the transmission provider fully recovers any reduction in revenues resulting from the change in the rates for firm point-to-point service. Nothing in Order No. 890 precludes transmission providers from proposing modification of rates for other services (such as network service) as necessary to recover CBM-related costs previously paid by point-to-point customers. Similarly, we expect that transmission providers would address in their rate design filings any possibility for particular customers to receive an inappropriate credit for non-firm use of capacity set aside for CBM. 88. We disagree that requiring transmission providers to design their rates to properly allocate CBM-related costs conflicts with the nature of network service or disadvantages network customers using CBM. Under the pro forma OATT, transfer capability is made available for network resource designations and firm point-to-point reservations on a non-discriminatory basis. It is therefore appropriate to design rates so that network customers and point-to-point customers pay rates based on the service available to each. 89. We decline to defer the filing of CBM-related rate design proposals until completion of the NERC/NAESB standardization process. To the extent a transmission provider's rates currently collect the costs associated with the CBM set-aside from point-to-point customers, those rates must be redesigned in accordance with Order No. 890. We acknowledge, however, that the on-going NERC and NAESB standardization processes may result in CBM being set aside and used differently in the future. To the extent such changes implicate the allocation of costs among those that are eligible to request or use the set-aside, the transmission provider should file with the Commission any necessary rate changes to ensure that CBM costs continue to be allocated appropriately. 90. Finally, we decline to address here what changes may be necessary to a particular rate settlement in order to ensure that costs associated with the CBM set-aside are allocated properly. All proposals to allocate CBM costs will be considered on a case-by-case basis, whether they involve rates stated in a settlement or otherwise. (3) TRM 91. The Commission required public utilities, working through NERC, to complete the ongoing process of modifying TRM-related reliability standards (MOD-008 and MOD-009). To guide NERC and NAESB in the process of drafting TRM-related standards and business practices, the Commission explained that transmission providers may set aside TRM for (1) load forecast and load distribution error, (2) variations in facility loadings, (3) uncertainty in transmission system topology, (4) loop flow impact, (5) variations in generation dispatch, (6) automatic sharing of reserves, and (7) other uncertainties as identified through the NERC reliability standards development process. To the extent capability is needed for transmission of shared reserves, the Commission stated that it must be included in TRM, although the Commission did not mandate the use of reserve sharing groups. 92. Each transmission provider was required to calculate, and allocate on the paths and flowgates, the aggregate TRM value for all LSEs within its area. Public utilities also were directed, working through NERC, to establish an appropriate maximum TRM. The Commission expressed support for NERC's plan to revise existing reliability standards for TRM to require clear documentation of the TRM calculation, to ensure full transparency. In addition, the Commission required each transmission provider to make available all underlying documentation, including work papers and load flow base cases, used to determine TRM, to any transmission customer and LSE within its control area, subject to a confidentiality agreement, 48 if necessary. Because load, facility loadings, and other uncertainties constantly deviate, the Commission did not require that TRM set-aside capacity be sold on a non-firm basis. The Commission explained that any request for regional difference from the applicable TRM reliability standards must take place through the NERC reliability standards development process. 48 The confidentiality agreement may appropriately restrict the sharing of sensitive information with customer personnel that are involved only in transmission functions, as opposed to merchant functions. Requests for Rehearing and Clarification 93. Duke asks the Commission to clarify that it intended NERC to develop a methodology to calculate a maximum TRM number, not to put an actual number in the reliability standard, arguing that requiring an actual number would overstep the bounds of FPA section 215. Southern argues that NERC must be allowed flexibility to develop appropriate TRM methodologies so that the use of TRM will be commensurate with expected system conditions, topography, and available capacity markets. Southern contends that setting a maximum amount of TRM would overlook the physical realities of the differing system configurations that constitute the electrical system. Southern argues, in particular, that the percentage ratings reduction proposed would be poorly suited as a reliability margin since individual line flows can change by very large percentages for single contingency events. Commission Determination 94. The Commission clarifies that NERC was not directed to identify an actual number or a particular methodology to include in the TRM standards, MOD-008-0 and MOD-009-0. The Commission's intent was to require NERC and NAESB to include consistent criteria and guidelines in the calculation and uses of TRM by transmission providers. 49 Likewise, in response to Southern's concern regarding flexibility to use something other than the ratings reduction method discussed in Order No. 890, we clarify that the ratings reduction method is only an example of a simple method that could be used. 50 Our intent is not to prohibit a transmission provider from using a more sophisticated method, so long as it is consistent with the reliability standards developed by NERC. 49 See Order No. 890 at P 273. 50 See id. at P 275. e. Modeling, Assumptions and Input Data 95. The Commission directed public utilities, working through NERC, to modify the reliability standards MOD-010 through MOD-025 51 to incorporate a requirement for the periodic review and modification of models for (1) load flow base cases with contingency, subsystem, and monitoring files, (2) short circuit data, and (3) transient and dynamic stability simulation data, in order to ensure that these models are up to date. The Commission stated that the models should be updated and benchmarked to actual events. 51 The MOD-010 through MOD-025 reliability standards establish data requirements, reporting procedures, and system model development and validation for use in the reliability analysis of the interconnected transmission systems. 96. The Commission also required transmission providers to use consistent data and assumptions underlying operational planning for short-term ATC and expansion planning for long-term ATC calculation, to the maximum extent practicable. The Commission explained that such data and assumptions include, for example, (1) load levels, (2) generation dispatch, (3) transmission and generation facilities maintenance schedules, (4) contingency outages, (5) topology, (6) transmission reservations, (7) assumptions regarding transmission and generation facilities additions and retirements, and (8) counterflows. The Commission directed public utilities, working through NERC, to modify ATC standards to achieve this consistency. Requests for Rehearing and Clarification 97. Entergy requests that the Commission acknowledge that the benchmarking of ATC calculations to real-time ATC values is only one piece of information to be used to evaluate ATC practices. Entergy agrees that such updating and benchmarking can provide information related to ATC/AFC calculations, but states that differences between the models used to calculate ATC/AFC and actual events in fact are going to occur. Entergy contends that the purpose of the ATC/AFC models is not to forecast actual operating conditions, but instead to reflect the physical transmission rights that have been previously granted and to determine if additional physical rights may be granted. 52 Entergy argues that benchmarking may be helpful when evaluating ATC, but it will not tell the whole story. 52 Entergy asserts that actual conditions will and should deviate from ATC/AFC models for numerous reasons. Entergy states that transmission operators are constantly monitoring their systems and taking actions to ensure that system constraints are mitigated well before real-time, including modifications to transmission outage plans, generator outage plans, and daily unit commitment plans. Entergy contends that those actions could, for example, make a flowgate that months ahead of time was predicted to be loaded at 100 percent to be loaded less than 50 percent in real-time. Entergy also notes that many transmission customers only use all of their transmission rights a small percentage of the time and, in any event, actual operating ATC will not perfectly match posted ATC since, for example, the level of mandatory purchases from qualifying facility (QF) can affect real-time ATC. 98. TDU Systems request that the Commission explicitly state that assumptions regarding loop flows must be consistent for ATC calculation and planning purposes, within the respective timeframe. TDU Systems argue that consistency in modeling the effects of those loop flows is necessary to ensure that neighboring transmission systems have accurately calculated ATC not only on their own systems but also on their interfaces with other systems. TDU Systems also ask that the Commission clarify that the assumptions and data to be used in ATC modeling must include the native load service obligations of LSEs as well as the transmission provider's native load. Commission Determination 99. The Commission clarifies in response to Entergy that the models used by the transmission provider to calculate ATC, and not actual ATC values, must be benchmarked. The Commission is concerned with the level of accuracy of the models and, therefore, directed in Order No. 890 that the models be updated and benchmarked to actual events. If models are not sufficiently accurate, then ATC/AFC calculations will not generate correct results, undermining the benefits of increased consistency and transparency of ATC calculations. With regard to discrepancies between actual and modeled ATC values, the Commission directed the ERO in Order No. 693 to modify MOD-014-0 through the reliability standards development process to require that actual system events be simulated and, if the model output is not within the accuracy required, the model shall be modified to achieve the necessary accuracy. 100. We agree with TDU Systems that assumptions regarding loop flows in calculating ATC must be consistent with those used for planning purposes within the respective timeframes. We also agree that loop flow impact in ATC calculation should not be restricted to the transmission provider's control area. Loop flows that occur in the power system must be included in the load flow models that simulate power system conditions. Loop flows affecting ATC calculation should be taken into account consistently by using the same models and assumptions as used for the planning of the system. With regard to modeling LSE uses of the system, we clarify that each transmission provider must include the native load service obligations of LSEs as well as the transmission provider's own load in modeling assumptions and data used for ATC calculation. f. ATC Calculation Frequency 101. The Commission directed public utilities, working through NERC and NAESB, to revise reliability standard MOD-001 to require ATC to be recalculated by all transmission providers on a consistent time interval and in a manner that closely reflects the actual topology of the system, e.g. , generation and transmission outages, load forecast, interchange schedules, transmission reservations, facility ratings, and other necessary data. The Commission stated that this process must also consider whether ATC should be calculated more frequently for constrained facilities. Requests for Rehearing and Clarification 102. Powerex asks the Commission to clarify that transmission providers are required to update their ATC calculations when they receive new data otherwise required to be posted under the requirements of Order No. 890, such as updated load forecasts. Powerex argues that the standards adopted through the NERC and NAESB processes should serve only as minimum or “no less frequent than” requirements. In Powerex's view, the specification of consistent intervals for ATC calculations should not prohibit or deter transmission providers from calculating and posting ATC on a more frequent basis as new data becomes available, particularly in light of the Commission's goal in Order No. 890 to make the ATC calculation process more transparent to customers. 103. Southern asks the Commission to clarify that ATC, not TTC, must be recalculated at consistent time intervals. Although the Commission referenced ATC in Order No. 890, Southern contends that the associated data and assumptions mentioned by the Commission (generation and transmission outages, load forecast, interchange schedules, transmission reservations, facility ratings, and other necessary data) relate to TTC. Southern argues that ATC is the appropriate reference because it can be calculated automatically with relative ease and frequency. In comparison, Southern states that TTC requires much more complex power flow analyses and should not be driven by changes in parameters without expert review. Southern contends that the calculation frequency requirements established by the Commission would result in constantly changing values if applied to TTC, with little time, if any, for the necessary review. Commission Determination 104. The Commission agrees with Powerex that the standards adopted through the NERC and NAESB processes should serve as minimum or “no less frequent than” requirements to recalculate ATC. Transmission providers also must update their ATC calculation when they receive substantial and material changes in data, such as updated load forecasts, changes in topology and dispatch patterns, which may be more frequent than the NERC and NAESB standards would otherwise require. In the absence of substantial and material changes in data, transmission providers are not required to update ATC on a more frequent basis than the minimum frequency that the NERC and NAESB standards require, once implemented. The Commission will consider the adequacy of the time frame for ATC updates on review of these standards. 105. In response to Southern, we reiterate that Order No. 890 directed revisions to reliability standard MOD-001 to require that ATC, not TTC, be recalculated at consistent time intervals. 53 However, system topology or other changes such as transmission outages, load forecast, interchange schedules, transmission reservations, or facility ratings, and other necessary data that affect ATC may of course impact one or more of the components of ATC, including TTC. While we agree with Southern that TTC requires more involved power flow analyses, the transmission provider should consider whether any changes in system topology, contingency outages, or other factors are substantial enough to merit recalculation of TTC. 53 See Order No. 890 at P 301. 2. Transparency 106. In Order No. 890, the Commission adopted a number of requirements in order to improve the transparency of ATC calculations. Some of these reforms applied to the pro forma OATT, including a requirement that each transmission provider include in Attachment C to its OATT more descriptive information concerning its ATC/AFC calculation methodology. Other reforms applied to information posted on OASIS, including data related to the calculation of ATC and TTC, changes in the ATC/TTC values, disclosure of Critical Energy Infrastructure Information (CEII), and the posting of additional ATC-related data. Petitioners have requested rehearing and clarification of certain of these requirements, which we address in turn. a. OATT Transparency—Attachment C 107. To increase transparency regarding ATC calculations, the Commission directed each transmission provider to set forth its ATC calculation methodology in Attachment C to its OATT. The Commission required that each transmission provider's Attachment C must, at a minimum: (1) Clearly identify which of the NERC-approved methodologies it employs ( e.g. , contract path, network ATC, or network AFC); (2) provide a detailed description of the specific mathematical algorithm the transmission provider uses to calculate firm and non-firm ATC for the scheduling horizon (same day and real-time), operating horizon (day ahead and pre-schedule), and planning horizon (beyond the operating horizon); (3) include a process flow diagram that describes the various steps that it takes in performing the ATC calculation; (4) set forth a definition of each ATC component ( i.e. , TTC, ETC, TRM, and CBM) and a detailed explanation of how each one is derived in both the operating and planning horizons; and (5) document their processes for coordinating ATC calculations with their neighboring systems. 108. The Commission concluded that Attachment C must provide an accurate documentation of processes and procedures related to the calculation of ATC, not the actual mathematical algorithms, which instead should be posted on their Web site with the link noted in the Attachment C. The Commission noted that a transmission provider may require a confidentiality agreement for CEII materials, consistent with our CEII requirements, or may otherwise protect the confidentiality of proprietary customer information. The Commission also required transmission providers to file a revised Attachment C to incorporate any changes in NERC's revised reliability standards and NAESB's business practices related to ATC calculations, as requested by the Commission in Order No. 890, within 60 days of completion of the NERC and NAESB processes. Requests for Rehearing and Clarification 109. MidAmerican objects to the Commission's decision to require a process flow diagram to be included in Attachment C, suggesting instead that each transmission provider post this information on its Web site as an alternative. MidAmerican contends that process flow diagrams demand large amounts of computer capacity and that management of and electronic transmittal of its OATT would become difficult if process flow diagrams were required for other elaborate and important tasks throughout the tariff, such as the transmission service request procedure or the generation interconnection procedure. MidAmerican argues that providing a web link on OASIS would achieve the Commission's transparency objective and expeditiously provide those that wish to navigate through a process diagram a direct access to the document. At a minimum, MidAmerican asks that the Commission accept an internet posting of the diagram with the web address published in Attachment C. 110. Southern requests clarification as to whether the Commission intends for transmission providers to make two filings of ATC methodologies ( i.e. , one when the Order No. 890 becomes effective and another when the NERC and NAESB processes are completed) or just one filing of such methodologies ( i.e. , a single filing when the NERC and NAESB processes are completed). Southern argues that only one filing should be required, to be made within 60 days after the NERC and NAESB processes are completed. Southern contends that requiring a premature filing before those processes are complete would waste transmission providers' resources in preparing those filings and the Commission's resources in reviewing them. Commission Determination 111. The Commission denies MidAmerican's request to permit a transmission provider to post on its Web site a process flow diagram and provide a web address in Attachment C, instead of providing the process flow diagram as a part of the Attachment C. A link to a Web site is not the equivalent of inclusion in the transmission provider's OATT, leaving the Commission unable to enforce use of the process flow diagram and the public with potentially more limited notice of any changes to the process flow diagram. The transparency and enforceability benefits of including the flow diagram in the tariff outweigh any potential filing burden. Therefore, we affirm our determination in Order No. 890 that a process flow diagram must be filed with OATT Attachment C, and that any change of the processes or data information identified by the process flow diagram must trigger an update of the process flow diagram and the filing of the revised OATT, Attachment C. 112. In response to Southern, Order No. 890 specifically required transmission providers to submit an intermediate filing within 180 days after the publication of the order in the Federal Register in order to provide transparency of the transmission provider's existing ATC calculation methodologies. In compliance with that requirement, a number of transmission providers, including Southern, submitted Attachment C compliance filings on September 11, 2007. The immediate transparency benefits of these filings will be supplemented by a revised filing following completion of the NERC and NAESB standardization processes. We do not believe the intermediate filing represented an undue burden to the transmission providers, as it was no more than a documentation of existing practices. b. OASIS (1) ATC/TTC Posting Requirements 113. The Commission concluded that transmission providers must continue to comply with existing ATC-related posting requirements, as supplemented by Order No. 890. To that end, the Commission stated that it would maintain a requirement for transmission providers to make available, upon request, all data used to calculate ATC and TTC for any constrained paths and any system planning studies or specific network impact studies performed for customers. Transmission providers were also directed to continue to post a list of such studies on OASIS. The Commission required the additional posting of, at a minimum, a list of all system impact studies, facilities studies, and studies performed for the transmission provider's own network resources and affiliated transmission customers, with those studies to be made available upon request. The Commission noted that appropriate procedures to accommodate CEII concerns should be developed to ensure eligible entities with a legitimate interest in transmission study data can receive access to it. The Commission required that the studies be made available for five years, consistent with data retention requirements pertaining to denial of service requests. Requests for Rehearing and Clarification 114. MidAmerican requests clarification with regard to the interaction of the data availability obligation under Order No. 890 and the Commission's Standards of Conduct with respect to information requests made by affiliated transmission customers. In order to provide comparable transmission service, MidAmerican argues that data must be available in all circumstances. If the Commission does not clarify that this is the case, MidAmerican requests rehearing of this provision so that comparable information can be made available at all times. Commission Determination 115. The Commission clarifies that all data used to calculate ATC and TTC for any constrained paths and any system planning studies or specific network impact studies performed for customers are to be made available on request, regardless of whether the customer is non-affiliated or affiliated with the transmission provider. To the extent the requesting party is an affiliate, the Standards of Conduct would require that data provided to the affiliate be simultaneously posted on the transmission provider's OASIS or Web site, as applicable. 54 54 See 18 CFR 358.5. (2) ATC/TTC Narrative Explanation 116. The Commission retained existing posting requirements for unconstrained paths and amended its regulations relating to data posted for constrained paths. Specifically, the Commission required transmission providers to post a narrative when a monthly or yearly ATC value changes as a result of a 10 percent change in TTC on constrained paths. Posted information must include both the (1) specific events which gave rise to the change and (2) the new values for ATC on that path (as opposed to all points on the network). The Commission also required the posting of a narrative with regard to monthly or yearly ATC values when ATC remains unchanged at a value of zero for a period of six months or longer. Requests for Rehearing and Clarification 117. E.ON U.S. argues that the posting of a narrative explanation for changes in ATC resulting from changes in TTC is unduly burdensome and, in any event, would not provide transmission customers with any meaningful information. E.ON U.S. contends that, using the new process for calculating TTC, a transmission provider would have to calculate the value for each horizon model and compare it to values in the previous hour in order to implement the posting requirement. Where those values change by more than 10 percent, E.ON U.S. states that the transmission provider will have to examine individually each changed parameter to assess its contribution to the change. E.ON U.S. contends that, for its system, the list of parameters to be evaluated would include generation dispatch, system configuration, loads, and net interchanges of which there can be dozens or even hundreds per hour. E.ON U.S. argues that this would take 24 engineers to monitor the E.ON U.S. system alone, costing millions of dollars per year. 118. Southern requests that the Commission clarify that the required narratives do not need to list each and every circumstance or occurrence that impacts TTC values from the previous month or year, stating that such a list would likely be voluminous because of the many conditions that affect TTC. Southern instead suggests that transmission providers list the primary reasons for the change in TTC to the extent they are known. Southern contends, for example, that an appropriate reason for such changes would be a new updated monthly model, arguing that it would not be practical to determine how much TTC may change from each outage, service commitment or other parameter change incorporated in an updated model. 119. Southern also requests that the Commission clarify where the transmission provider should post these narrative explanations and in what form. Southern proposes that this information be posted on OASIS via a template and data element that is to be defined by a NAESB standard, incorporated into a revised Standards and Communications Protocol document, and subsequently adopted by the Commission. 120. TDU Systems argue that the Commission has set too high of a threshold for reporting changes in ATC/TTC, arguing that the triggering requirement should be a 10 percent decrease in ATC, rather than a 10 percent change in TTC. TDU Systems contend that TTC is a large enough number that using a decrease of 10 percent in TTC as a trigger for requiring a narrative explanation to be posted will result in very few narrative explanations posted, thereby defeating the purpose of the requirement. 121. PJM seeks clarification of the posting requirement as applied to transmission providers using an AFC calculation method. PJM states that TTC is an output from, not an input to, its AFC/TTC calculations and therefore the literal terms of the regulations do not make sense as applied to PJM. PJM proposes to post a narrative explanation for the reason for daily changes in ATC or TTC values as a result of changes in AFC inputs ( i.e. , transmission outages, generator outages, load forecast, and model updates) in the event the resultant ATC or TTC value changes by 10 percent or more, requesting that the Commission confirm that this approach would appropriately adapt the Order No. 890 posting requirement to a system such as PJM that uses an AFC methodology. Alternatively, if the Commission does not wish to address PJM's manner of implementation of this revised regulation in the context of rehearing/clarification of Order No. 890, PJM asks that the Commission allow PJM, and other similarly situated transmission providers, to address this issue in their Order No. 890 tariff compliance filings. In that event, PJM asks that the Commission clarify only that such transmission providers may continue their existing practices until the Commission acts on their compliance filings. 122. TDU Systems also argue that the six-month trigger for posting an explanation for zero ATC values is unsupported, asking instead that transmission providers be required to post a narrative explanation of zero ATC values any time those values remain at zero for a period that affects access in a practical way, e.g. , a day for daily service, two business days for weekly service, five business days for monthly or yearly service. TDU Systems contend that a transmission system where ATC values remain at zero for any length of time raises serious concerns as to the adequacy of the system and the need for significant upgrades, and simply posting a zero value for ATC does not provide market participants with an understanding of what is happening on the system. Commission Determination 123. The Commission affirms the decision in Order No. 890 to require transmission providers to post a brief, but specific, narrative explanation of the reason for a change in monthly or yearly ATC values on a constrained path as a result of a change in TTC of 10 percent or more. As the Commission explained, this will limit the number of ATC changes for which a narrative will be required. 55 55 See Order No. 890 at P 369. 124. We believe that E.ON U.S. overestimates the burden of complying with this requirement. Since TTC standardization is ongoing, it is impossible to identify with precision the steps that will need to be taken to comply with the posting requirement. The appropriate forum to raise concerns regarding the burden of particular TTC calculation requirements is in the NAESB standards development process. In any event, we would expect that the posting of narratives for changes in monthly and yearly ATC values as a result of a 10 percent change in TTC will be triggered mainly by topology changes resulting from transmission lines and generator in-service status, as well as new facilities additions, that are reported on OASIS. 125. We clarify in response to Southern that transmission providers do not need to list each and every circumstance or occurrence that impacts TTC values from the previous month or year and, instead, may list the primary events that give rise to the update. Again, we expect that TTC changes will generally result from topology changes and, therefore, the primary reasons for an update would be changes in schedules of transmission or generation additions, prolonged outages, or changes in maintenance schedules causing a TTC change of 10 percent. We agree with Southern that the transmission provider should post these narrative explanations on OASIS via a template and data element that is to be defined by NAESB. We direct transmission providers, working through NAESB, to develop the OASIS functionality necessary for such postings. Pending completion of this work by NAESB, we direct transmission providers to post these narrative explanations as comments on OASIS. 126. We deny TDU Systems' request to change the triggering requirement to a 10 percent decrease in ATC. In Order No. 890, the Commission relaxed the ATC narrative reporting requirements proposed in the NOPR due to concerns that the posting of those narratives would become burdensome. We believe the Commission struck the right balance by requiring the posting of narratives only when there is a change in TTC of 10 percent or more and disagree that more limited postings defeats the purpose of the posting obligation. 127. In response to PJM, we reiterate that all transmission providers must comply with this posting requirement. Transmission providers using an AFC calculation method that does not base changes in ATC on changes in TTC may comply with this requirement by posting narrative explanations of the reasons for changes in AFC values as a result of changes in AFC inputs that cause ATC or TTC to change by 10 percent or more. We direct each transmission provider that employs the AFC calculation methodology to provide a statement in the compliance filing required in section II.C describing how the narrative is derived for ATC/TTC postings or, if such information was provided in a prior compliance filing, a reference to that filing. 128. We also deny TDU Systems' request to require transmission providers to post a narrative explanation any time ATC values remain at zero for a day for daily service, two business days for weekly service, five business days for monthly or yearly service. The Commission concludes that a six-month trigger for monthly or yearly ATC values more appropriately balances the benefits of increased transparency for the Commission and customers against the burden on transmission providers to make such postings. If the frequency of these postings proves inadequate, the Commission can revisit this requirement in a future order. (3) CEII 129. The Commission acknowledged in Order No. 890 that certain data and studies required to be made public may contain CEII and that the Commission has a responsibility to protect that information. In order to provide transparency and avoid undue delays in providing information to those with a legitimate need for it, the Commission required that transmission providers establish a standard disclosure procedure for CEII required to be disclosed in Order No. 890. The Commission stated that transmission providers will be responsible for identifying CEII and facilitating access to it for appropriate entities and the Commission will be available to resolve disputes if they arise. 130. With regard to procedures to access CEII, the Commission noted that transmission customers already have digital certificates or passwords to access publicly restricted transmission information on OASIS. The Commission suggested that transmission providers could set up an additional login requirement for users to view CEII sections of the OASIS, requiring users to acknowledge that they will be viewing CEII and to sign a nondisclosure agreement at the time the customer obtains access to that portion of the OASIS. The Commission explained that only information that meets the criteria for CEII, as defined in section 388.113 of the Commission's regulations, 56 should be posted in this section of the OASIS. 56 18 CFR 388.113. Requests for Rehearing and Clarification 131. E.ON U.S. contends that the Commission should not allow posting of CEII on OASIS, arguing that information is designated as CEII because it relates to the integral operations of the nation-wide power grid and that, with access to this information, a terrorist or other bad actor could inflict real, substantial harm on the power grid. E.ON U.S. states that posting CEII on a transmission provider's OASIS, a Web site that is openly connected to the internet, will impair the transmission provider's ability to adequately protect this information, even with password protection. E.ON U.S. suggests there are other ways of providing transmission customers with such CEII, such as individual meetings upon request. 132. New York Transmission Owners request that transmission providers be authorized to determine, on a case-by-case basis, the specific level and amount of CEII that a requesting customer may obtain. New York Transmission Owners argue that a terrorist seeking to harm our country's energy infrastructure will not likely be concerned with having to sign a confidentiality agreement or obtain multiple passwords. Commission Determination 133. We agree with E.ON U.S. that posting CEII on OASIS may not provide adequate protection of CEII and that transmission providers may therefore develop other standard disclosure procedures to provide relevant CEII to transmission customers on a timely basis. The Commission did not require CEII postings on OASIS in Order No. 890 and, instead, discussed use of OASIS as one potential disclosure mechanism. 57 The Commission required transmission providers to establish a standard procedure for disclosing relevant CEII on a timely basis, but did not specify a particular disclosure mechanism. 57 See Order No. 890 at P 404. 134. Similarly, transmission providers may determine on a case-by-case basis the specific level of CEII a customer may obtain, provided that the information is made available to appropriate recipients on a timely basis. If a transmission provider chooses to post CEII on a protected section of its OASIS, the transmission provider can and should verify the identity of transmission customers who access that information as it would for any confidential information. (4) Additional Data Posting 135. The Commission also required transmission providers to post on OASIS metrics related to the provision of transmission service under the OATT. Specifically, non-ISO/RTO transmission providers were directed to post (1) the number of affiliate versus non-affiliate requests for transmission service that have been rejected and (2) the number of affiliate versus non-affiliate requests for transmission service that have been made. This posting must detail the length of service request ( e.g. , short-term or long-term) and the type of service requested ( e.g. , firm point-to-point, non-firm point-to-point or network service). The Commission stated that the affiliate posting requirements do not apply to ISOs and RTOs since they do not have any affiliates. 136. The Commission also required transmission providers to post their underlying load forecast assumptions for all ATC calculations and to post, on a daily basis, their actual daily peak load for the prior day and load forecasts and actual daily peak load for both system-wide load (including native load) and native load. ISOs and RTOs are required to post this load data for the entire ISO/RTO footprint and for each LSE or control area footprint within the ISO/RTO. Requests for Rehearing and Clarification 137. E.ON LSE requests clarification whether the requirement in section 37.6(e)(2) of the Commission's regulations to post information regarding denials of service applies to denials of requests. Washington IOUs request clarification on the requirement to post information regarding transmission service requests from affiliates, stating that it is not clear what the Commission means by “requests for transmission service.” They suggest that the reference could be to requests for transmission service by affiliated merchant or trading entities or requests for transmission service by the transmission provider's merchant function, including requests to designate or undesignate network resources and requests to procure secondary network service to serve native load. 138. TDU Systems request that the Commission reconsider its decision to exempt RTOs and ISOs from the requirement to post data regarding their processing of transmission service requests. Although RTOs and ISOs have no generation affiliates, TDU Systems argue that requiring RTOs and ISOs to post information as to the number of requests made and rejected would make the acquisition of transmission services more transparent, serve as a signal for potential congestion problems on the system that should be studied through the planning process, and alert market participants to the emergence of market power in local submarkets. 139. Constellation requests that the Commission clarify that the requirement to post underlying load forecast assumptions includes a complete list of modeling assumptions, protocols and automation modifications, including what the adjustments are and how they are applied. Constellation states that it requested that such information be required in its NOPR comments, but that it is unclear whether the requirement in Order No. 890 is broad enough to reflect that request. 140. E.ON LSE requests that the Commission grant rehearing to permit utilities to decli [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3AE8-144. Public record. Not legal advice.