05-3040. Reporting Requirement for Changes in Status for Public Utilities With Market-Based Rate Authority

Issued February 10, 2005.

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Final rule.

SUMMARY:

In this Final Rule, the Federal Energy Regulatory Commission (Commission) is amending its regulations to establish a reporting obligation for changes in status that apply to public utilities authorized to make wholesale power sales in interstate commerce at market-based rates. The Commission is amending its regulations to establish guidelines concerning the types of events that trigger this reporting obligation and modifying the market-based rate authority of current market-based rate sellers to ensure that all such events are timely reported to the Commission by eliminating the option to delay reporting of such events until submission of a market-based rate seller's updated market power analysis. This reporting requirement will be incorporated into the market-based rate tariff of each entity that is currently authorized to make sales at market-based rates, as well as that of all future applicants.

DATES:

Effective Date: This Final Rule will become effective on March 21, 2005.

FOR FURTHER INFORMATION CONTACT:

Brandon Johnson, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone]

Michelle Barnaby, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone]

SUPPLEMENTARY INFORMATION:

Table of Contents / Paragraph

Introduction—1

Background—7

Discussion—11

General Issues—11

 Comments—11

 Commission Conclusion—15

 Triggering Events—18

 Triggering Events Generally—19

 Comments—19

 Commission Conclusion—25

 Exemptions—28

 Comments—28

 Commission Conclusion—34

 Control/Ownership—42

 Comments—42

 Commission Conclusion—47

 Affiliation—49

 Comments—49

 Commission Conclusion—51

Inputs to Electric Power Production—52

 Comments—53

 Commission Conclusion—58

Materiality Threshold—60

 Comments—61

 Commission Conclusion—68

Transmission Outages—71

 Comments—72

 Commission Conclusion—75

Other Reportable Arrangements—76

 Comments—77

 Commission Conclusion—82

Form and Content of Reports—84

 Comments—85

 Commission Conclusion—93

Inclusion of Reporting Requirement in Market-based Rate Tariffs—96

 Comments—97

 Commission Conclusion—98

Reporting Period/Timing—99

 Comments—100

 Commission Conclusion—105

Other Procedural Issues—108

Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell, Joseph T. Kelliher, and Suedeen G. Kelly.

Introduction

1. On October 6, 2004, the Commission issued a Notice of Proposed Rulemaking (NOPR) that proposed to standardize and clarify market-based rate sellers' reporting requirement for changes in status. The Commission proposed to impose uniform standards on all market-based rate sellers by eliminating the option to delay reporting changes in status until submission of the triennial review, or to file a triennial review in lieu of reporting changes in status as they occur. Acting pursuant to section 206 of the FPA, the Commission proposed to amend its regulations and to modify the market-based rate authority of current market-based rate sellers to include the requirement to timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority. The Commission proposed that this reporting requirement be incorporated into the market-based rate tariff of each entity that is currently authorized to make sales at market-based rates, as well as that of all future applicants. The Commission proposed that notice of such changes in status be filed no later than 30 days after the change in status occurs.

2. As discussed more fully below, in this Final Rule, the Commission, among other things: Imposes uniform standards on all market-based rate sellers by eliminating the option to delay reporting changes in status until submission of the triennial review or to file a triennial review in lieu of reporting changes in status as they occur; specifically refers to “control” of generation or transmission facilities as a trigger which could result in the obligation to make a change in status filing; provides guidance as to the “characteristics” the Commission relies on in evaluating whether to grant market-based rate authority; provides guidance as to the form, content, and timing of a change in status filing; and incorporates into all market-based rate tariffs the standards discussed herein.

3. In doing so, the Commission has adopted many of the recommendations suggested by commenters. In this regard, the Commission clarifies that a change in status filing is one of the tools the Commission uses to ensure that wholesale electric rates remain just and reasonable. In particular, a change in status filing informs the Commission of changes that may occur from time to time that relate to the four-part analysis (generation market power, transmission market power, other barriers to entry, and affiliate abuse and reciprocal dealing) the Commission relies on for granting market-based rate authority. At the same time, however, the Commission finds that some of the recommendations made by commenters are more appropriately addressed in the market-based rate rulemaking proceeding that the Commission has initiated in Docket No. RM04-7-000.

4. As discussed below, the Commission finds that a number of issues regarding the Commission's analysis under the four-part test (e.g., what constitutes control of an asset, how to treat long-term contracts, how to evaluate whether an applicant has transmission market power) are more appropriately addressed in the market-based rate rulemaking, in which numerous technical conferences have been held and comments filed. It is in that proceeding that the Commission will examine the recommendations of commenters and address the adequacy of the current four-part analysis, including whether and how it should be modified to assure that electric market-based rates are just and reasonable under the FPA.

5. With respect to change in status filings, in this Final Rule applicants are reminded that the baseline determination of whether a filing is required is whether the change in status in question would have been reportable in an initial application for market-based rate authority under the Commission's four-part analysis, as it may change from time to time. To the extent that the change in status in question would have been reportable in an initial request for market-based rate authority, a change in status filing is required. For example, if an applicant acquires additional uncommitted capacity, a change in status filing is required.

6. The Commission provides this guidance to enable applicants to better determine when they must report a change in status. The electric industry is a dynamic industry and no bright-line standard is possible to encompass all relevant factors and possibilities that may occur. The Commission believes that sufficient guidance has been provided in this Final Rule and reminds applicants that they have the right to make a change in status filing under section 205 of the Commission's regulations at any time. With this safeguard, the Commission is certain that applicants have the means to fully comply with the change in status requirement and with the standards adopted herein can do so efficiently and with no additional burden.

Background

7. As the Commission explained in the NOPR, it has a statutory duty under the FPA to ensure that rates charged by public utilities authorized to make wholesale sales in interstate commerce at market-based rates are just and reasonable.^{[1] -[2]} The Commission uses a four-part test to determine whether to grant market-based rate authority. That test examines whether the applicant or its affiliates possess the potential to exercise market power by considering generation market power, transmission market power, barriers to entry, and the potential for affiliate abuse or reciprocal dealing. Sellers authorized to make sales at market-based rates are then required to file electric quarterly reports containing a summary of the contractual terms and conditions in every effective service agreement for market-based power sales and transaction information for their market-based rate sales during the most recent calendar quarter.^[3]

8. The Commission has also required that market-based rate sellers report any changes in status that would reflect a departure from the characteristics the Commission relied upon in its existing grant of market-based rate authority. When the Commission first granted market-based rate authorizations, it required traditional utilities that satisfied the Commission's initial market power review to file an updated market power analysis every three years to allow the Commission to monitor competitive conditions and to determine whether the applicants still satisfied our market power concerns.^[4] Power marketers, on the other hand, were required to promptly notify the Commission of changes in status.^[5] Subsequently, the Commission has allowed market-based-rate sellers to choose between promptly reporting changes in status, filing a three-year update in lieu of reporting changes in status as they occurred,^[6] or reporting such changes in conjunction with the updated market analysis.^[7] The Commission reserved the right to require such an analysis at any time and, in the NOPR, proposed to continue to reserve this right.

9. To carry out its statutory duty under the FPA to ensure that market-based rates are just and reasonable, the Commission must rely on market-based rate sellers to provide accurate, up-to-date information regarding any relevant changes in status, such as ownership or control of generation or transmission facilities and affiliate relationships. In contrast to when the Commission first began to authorize market-based rate sales, as markets have expanded and developed, both the number and types of market-based rate sellers have increased (e.g., independent power producers, power marketers, affiliated generators) and the complexity of wholesale markets has increased. Furthermore, market structure is rapidly evolving due to restructuring, corporate realignments and new types of contractual and subcontracting arrangements, in which utilities increasingly grant other firms control over managing various aspects of their business such as power marketing. In light of these structural changes, the Commission has concluded that more timely reporting of changes in status is necessary.

10. Therefore, the Commission proposed in the NOPR to eliminate the option to delay reporting changes in status until the next triennial review, or to file a triennial review in lieu of promptly reporting changes in status, and to standardize the change in status reporting requirement. Accordingly, the proposed regulations would require that, as a condition of obtaining and retaining market-based rate authority, all sellers will be required to timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority.

Discussion

General Issues

Comments

11. With only a few exceptions, the commenters support the Commission's proposal to standardize market-based rate sellers' reporting requirement. Nearly all of the comments received urge the Commission to more clearly define market-based rate sellers' reporting obligation and to do so in a manner that does not impose an excessive reporting burden.

12. Mayflower LP (Mayflower) argues that the Commission's entire approach of attempting to develop market power tests is misguided because the variables involved are too complex to describe effectively in a regulation. Mayflower contends that the Commission should instead prioritize its resources to mitigating the obvious cases of market power, in particular by utilizing section 205(f) of the FPA ^[8] to end market power abuses through fuel adjustment clauses, which allow utilities to pass through the costs of operating dirty and inefficient gas and boiler generation, while cleaner, cheaper-to-run combined cycle generation sits idle.^[9]

13. Tractebel North America, Inc. (Tractebel), citing the Commission's recent order disclaiming jurisdiction under section 203 for a generation-only facility in Perryville Energy Partners,^[10] argues that the review of transactions in the context of market-based rate authority is an inadequate substitute for Commission review of a public utility's acquisition of an asset under section 203. Accordingly, in cases where the Commission lacks jurisdiction under section 203, Tractebel urges the Commission to review acquisitions of generation not only in the context of a notice of change in status, but also in related filings, such as any rate filing for transmission interconnection service over assets that will continue to be owned by the seller and filings related to exempt wholesale generator (EWG) status.^[11]

14. Finally, Pacific Gas & Electric Company (PG&E) argues that the reporting requirement proposed in the NOPR should apply to energy marketers but not to investor-owned utilities that are serving native load customers and are members of an independent system operator (ISO) or regional transmission organization (RTO). According to PG&E, there are legitimate differences between energy marketers (who, as net sellers, engage in electric trades for profit and can influence the market relatively rapidly) and traditional utilities such as PG&E (who are net buyers and do not speculate).^[12]

Commission Conclusion

15. We decline to adopt Mayflower's proposal to address alleged market power abuses through fuel adjustment clauses because it goes beyond the scope of the instant rulemaking. Section 205(f) requires the Commission to review practices under public utility automatic adjustment clauses to ensure efficient use of resources under such clauses. If a party believes that this is not being done, the Commission encourages the filing of a complaint to remedy the matter. Proposals such as Mayflower's, which urge the Commission to adopt a new approach toward the mitigation of market power, are more appropriately addressed in the generic rulemaking in Docket No. RM04-7-000.

16. In response to Tractebel's comments, the acquisition of a generating facility by a utility with market-based rate authority such as occurred in Perryville is an event that would trigger the filing of a change in status report consistent with this rule. Whether it would trigger other jurisdictional filings such as a rate filing for transmission interconnection service or filing related to EWG status, as Tractebel suggests, would depend on the facts of the particular case. As the Commission stated in the Perryville case, the Commission will consider the effect of the addition of the Perryville capacity as part of the Commission's review of Entergy's updated market power analysis in Docket No. ER91-569-023, et al.^[13]

17. We will also reject PG&E's suggestion to exempt investor-owned utilities such as PG&E from the reporting requirement. Adopting PG&E's proposal could result in allowing large vertical utilities to increase their market share or otherwise obtain market power without notifying the Commission of changed circumstances. Under PG&E's proposal, a vertical utility could have changed circumstances that would result in that utility no longer satisfying one or more prongs of the four-part test that the Commission uses to determine whether to grant market-based rate authorization. With no notification to the Commission in that regard such a proposal provides little or no protection to customers in the market between review periods, (i.e., triennial review). To the extent that PG&E assumes an RTO's mitigation warrants an exemption, we have rejected such an exemption in the previous orders.^[14]

Triggering Events

18. With respect to the types of events that should trigger the reporting obligation, the Commission proposed in the NOPR that, as an initial matter, the following events would qualify as changes in status: (1) Ownership or control of generation or transmission facilities or inputs to electric power production; or (2) affiliation with any entity not disclosed in the filing that owns or controls generation or transmission facilities or inputs to electric power production or affiliation with any entity that has a franchised service area.^[15] The Commission noted that, although the change in status provision has not specifically referenced “control” of assets, the Commission has historically taken into account all of the assets that a market-based rate seller controls in our four-part test for granting market-based rate authority. In order to eliminate any market uncertainty, the Commission proposed that the regulations specifically reference “control” as well as ownership as a factor relied upon by the Commission. As we noted in the NOPR, the Commission's early orders granting market-based rate authority acknowledged that sellers may exercise market power through contractual arrangements granting them control of generation or transmission facilities just as effectively as they could through ownership.^[16] Similarly, the Commission's guidelines for the assessment of mergers and its generation market power analysis for market-based rate authority provide that, for the purposes of the market power analysis, the capacity associated with contracts that confer operational control of a given facility to an entity other than the owner must be assigned to the entity exercising control over that facility, rather than to the entity that is the legal owner of the facility.^[17] In addition, with respect to notifications of changes in status, the Commission has found that an entity controls the facilities of another when it controls the decision-making authority over sales of electric energy, including discretion as to how, when and to whom it could sell power generated by these facilities.^[18]

Triggering Events Generally

Comments

19. Several commenters assert that the definitions of triggering events are vague or unclear and request that the Commission clarify these elements of the proposed regulations.^[19] Some commenters request that the Commission clarify these terms by issuing a supplemental NOPR offering a detailed description of the specific information it needs ^[20] or by setting forth clear “rules of the road” to provide market-based rate sellers guidance as to whether they are in compliance with the Commission's requirements.^[21] Cinergy Services, Inc. (Cinergy) urges the Commission to limit the scope of the present rulemaking to reviewing reporting requirements for changes in status relevant to the Commission's current four-part analysis for market-based rate authority and to defer consideration of new issues or modifications to the current market-based rate tests for the parallel rulemaking in Docket No. RM04-7-000.^[22]

20. Commenters were divided as to whether the Commission should include an illustrative list of triggering events. Calpine Corporation (Calpine) and Transmission Access Policy Study Group (TAPS) argue that the Commission should adopt bright-line standards for what constitutes a reportable event and suggest specific events that should trigger the reporting requirement, which are discussed further below.^[23] National Rural Electric Cooperatives Association (NRECA) argues that the Commission should clearly define when the reporting obligation is triggered because failure to comply could potentially result in retroactive refunds pursuant to the Ninth Circuit's decision in California ex rel. Lockyer v. FERC  ^[24] and/or suspension or revocation of market-based rate authority.^[25]

21. On the other hand, the Bank Power Marketers and Industrial Energy Users—Ohio and PJM Industrial Customers Coalition (IEU—Ohio/PJMICC) argue that the Commission should not rely on a laundry list of transaction types ^[26] or an illustrative list of reporting triggers.^[27]

22. American Public Power Association (APPA) comments that the reporting requirement should provide for the reporting of changes that “could affect the public utility's eligibility for [market-based rate] authority,” based on current standards for authorization of market-based rates, rather than requiring reporting of only those events that “would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority.” ^[28]

23. EEI, supported by Pacificorp, argues that the reporting obligation should extend only to changes in circumstances within the applicant's control. According to EEI, an applicant should not be required to report a change of circumstances based on an action taken by a competitor (such as a decision to retire a generation unit or take transmission capacity out of service) or natural events (such as a high hydro-year, higher wind generation or load disruptions due to adverse weather conditions) that might change the result of the interim screens.^[29]

24. Finally, commenters suggest the following additional triggering events: The acquisition of Financial Transmission Right (FTR) positions into constrained load pockets that exceed a seller's load obligations in the load pocket,^[30] any changes in ISO or RTO status for the relevant market; or any changes in state regulations relative to load-serving obligations in the relevant market; ^[31] changes in market definition, e.g., due to transmission outages or the change in size of a load pocket, provided that such changes are confirmed by the independent and published judgment of an ISO or RTO overseeing local market power issues pursuant to a Commission tariff.^[32]

Commission Conclusion

25. After careful consideration of the comments, the Commission rejects commenters' proposals to clarify the reporting requirement by including an illustrative list of triggering events or to otherwise expand the list of triggering events beyond those contained in the NOPR. We reject this suggestion, first, because we believe that the definition of triggering events contained in the Commission regulations adopted here, offers market-based rate sellers sufficient notice of and guidance concerning the scope of their reporting requirement. The reporting requirement we adopt herein ensures that the Commission retains the discretion and flexibility to protect customers in light of future, unforeseen changes in wholesale electricity markets that may allow market-based rate sellers to exercise market power. Consequently, the Commission does not believe that commenters have provided sufficient support for their contention that the inclusion of an illustrative list would in fact increase regulatory certainty.

26. In response to the request of Cinergy, we clarify that the reporting requirement is limited to reviewing changes in status relevant to the Commission's current four-part analysis for market-based rate authority and that the Commission will not consider any new tests or modifications of its current four-part test in this docket. APPA has argued that the Commission should change its existing reporting requirement—which obligates market-based rate sellers to report changes that “would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority”—to require reporting of changes that “could affect the public utility's eligibility for [market-based rate] authority,” based on current standards for authorization of market-based rate authority. We clarify that the “characteristics” refer to the Commission's four-part test and our analysis thereof. The Commission evaluates any request to obtain or retain market-based rate authority under its currently applicable standards for each of the four prongs; similarly, a notice of change in status is required in circumstances where the factors the Commission relied upon in evaluating the four-part test as it applies to an applicant change. Under these circumstances, the Commission will apply the currently applicable standard in its assessment of whether that entity may continue to make sales at market-based rates. Second, APPA's proposal to require reporting of changes that “could affect the public utility's eligibility for [market-based rate] authority” appears to be more subjective than our current standard and could result in sellers reporting information that the Commission would not consider relevant. We believe that we have given sufficiently clear guidance regarding triggering events to limit market-based rate sellers' discretion to avoid reporting changes in status that would confer or enhance market power.

27. We agree with EEI that the reporting obligation should extend only to changes in circumstances within the knowledge and control of the applicant. Accordingly, an applicant should not be required to report a change in circumstances based on an action taken by a competitor (such as a decision to retire a generation unit or take transmission capacity out of service) or natural events (such as hydro-year, higher wind generation or load disruptions due to adverse weather conditions). While we will not expand the triggering events as proposed in the NOPR in this Final Rule, interested persons can pursue these matters in the course of the generic rulemaking we have established in Docket No. RM04-7-000, which will address proposed modifications to the Commission's current four-part test for granting market-based rate authority.

Exemptions

Comments

28. Commenters suggest a number of events that should be exempted from the reporting requirement. BP Energy Company (BP Energy), Cinergy, Duke Energy Corporation (Duke), EPSA, FirstEnergy, and Edison Electric Institute and Alliance of Energy Suppliers (EEI) contend that the reporting requirement should not apply to events covered by section 203 applications.^[33]

29. Bank Power Marketers and Westar Energy, Inc. (Westar) oppose the proposals contained in the NOPR on the ground that the proposed reporting requirement would be both excessive and duplicative, given that the Commission already receives the same information through existing reporting requirements, e.g., section 203 applications, triennial updates, Electric Quarterly Reports (EQR), Form 3-Q, etc.^[34]

30. EEI and PacifiCorp argue that long-term contracts should not be reportable.^[35] National Grid USA (National Grid) argues that market-based rate sellers should not be required to report long-term contracts that were entered into either to satisfy their “provider of last resort” (POLR) obligations or through state-regulated competitive solicitation processes that are consistent with the Commission's standards for inter-affiliate transactions.^[36] National Grid and IEU—Ohio/PJMICC also support the exemption of purchases from qualified facilities mandated by the Public Utility Regulatory Policies Act of 1978 (PURPA).^[37]

31. Duke suggests that the following events should be exempt: (i) Transactions outside market-based rate sellers' home or first-tier control area markets; (ii) affiliate transactions subject to other reporting requirements; (iii) transactions involving post-1996 generation facilities; and (iv) intra-corporate reorganizations that do not involve the acquisition of additional assets and thus do not affect market share or concentration.^[38] Cinergy argues that the reporting obligation should not apply to transactions that do not increase ownership or control, specifically: (i) Intra-corporate transactions between affiliates within one holding company system or transactions that are simply a change in corporate form; (ii) purely financial transactions such as futures, swaps and derivatives that do not have a physical component; and (iii) construction of new generation otherwise exempt under Commission regulations.^[39] Tucson Electric Power Company (Tucson Electric) urges the Commission to exempt entities subject to oversight by an Independent Market Monitor (IMM) because the IMM will investigate and report to the Commission any anticompetitive behavior.^[40]

32. Finally, Cinergy and Tractebel urge the Commission to clarify that the Commission is only concerned with changes in status that may increase market power, but not those that decrease it, so, for example, the purchase of generation might trigger the reporting requirement, but a sale should not.^[41] Similarly, Calpine argues that a public utility's decrease in generation capacity cannot increase its generation market power over what the Commission assumed when it granted market-based rate authority, so it would be a waste of resources to require such reporting.^[42]

33. With respect to changes in ownership or control of transmission facilities, EEI, FirstEnergy and National Grid argue that, given the existence of the open access transmission tariff (OATT) requirement, which constrains the exercise of vertical market power, there should be no reporting requirement for changes in status regarding transmission facilities covered by an OATT.^[43] National Grid urges the Commission to defer the establishment of reporting requirements associated with changes in transmission market power status until it has developed, in the context of Docket No. RM04-7-000, more of an understanding of what transmission market power is and how it might be abused.^[44] EEI, FirstEnergy, and National Grid all argue that, since any transfer of ownership or control of transmission facilities would be covered by a section 203 application, a separate reporting requirement in the context of market-based rate authority is unnecessary and duplicative.^[45] National Grid argues that such a reporting requirement might discourage transmission providers from transferring their transmission facilities to Independent Transmission Companies (ITCs).^[46] Finally, National Grid contends that construction activities undertaken pursuant to a Commission-approved regional planning process should not be reportable because additional transmission capacity improves competition among resources.^[47]

Commission Conclusion

34. In order to avoid unnecessary duplication of effort, we clarify that a market-based rate seller may incorporate by reference in its notice of change in status any filings regarding the change in status made pursuant to other reporting requirements. Furthermore, intra-corporate reorganizations that do not otherwise have an impact on our four-part test and are not otherwise reportable need not be reported as a change in status.

35. We reject commenters' proposal to exempt from the reporting requirement transactions that are subject to other reporting requirements, such as dispositions of jurisdictional facilities covered by section 203 applications and long-term contracts or affiliate transactions that are filed pursuant to section 205. The Commission can best exercise its statutory duty to ensure just and reasonable rates by imposing an enforceable post-approval reporting requirement regarding changes in status.^[48] Appropriate market monitoring cannot be satisfied simply by ensuring that public utilities are complying with other provisions of the FPA. Moreover, as discussed below, the time and effort required to prepare the notice of a change in status—consisting of a transmittal sheet and a brief narrative statement—will be de minimis and will constitute a fraction of that required to submit the section 203 application or section 205 filing. Furthermore, the information required to comply with the reporting requirement would normally be collected by the market-based rate seller in the ordinary course of preparing the underlying filing.

36. We also reject Tucson Electric's proposal to exempt transactions involving entities subject to oversight by an IMM. Consistent with our decision not to allow an exemption from the generation market power analysis for sales into an ISO/RTO with Commission-approved market monitoring and mitigation, we will not exempt from the change in status reporting requirement entities subject to oversight by an IMM. The Commission has an independent statutory duty to ensure that rates are just and reasonable, and we cannot delegate this responsibility in these circumstances to an IMM.

37. Commenters also propose to exempt transactions outside the applicant's home or first-tier control area markets and to exempt new construction. These commenters have not presented any persuasive evidence that these transactions—to the extent that they are covered by the Commission regulations adopted herein and satisfy the materiality threshold set forth below—should be treated differently.

38. As a general matter, we reject Duke's suggestion that acquisitions of post-1996 generation be exempt from the reporting requirement. Section 35.27 merely adopts a rebuttable presumption that post-1996 generation cannot exercise market power,^[49] and the Commission considers post-1996 generation in initial applications for and triennial reviews of market-based rate authority under appropriate circumstances.^[50] However, we clarify that to the extent that the generation owned or controlled by an applicant [in the relevant market] and its affiliates is post-1996, and the applicant or an affiliate acquires through purchase or acquisition additional post-1996 generation, no change in status filing is required. The Commission has found that in circumstances where construction of all of an applicant's generation commenced after July 9, 1996, no interim generation market power analysis need be performed.^[51] On the other hand, in the above example, if the applicant owned pre-1996 generation a change in status filing may be required since the Commission has stated that if an applicant sites generation in an area where it or its affiliates own or control other generation assets, the applicant must study whether its new capacity, when added to the existing capacity, raises generation market power concerns.^[52] Finally, we note that the generic rulemaking in Docket No. RM04-7-000 will address whether the Commission should retain the exemption for post-1996 generation in section 35.27 of the Commission's regulations.

39. In response to Cinergy's request, we clarify that purely financial transactions involving future swaps and derivatives that do not provide for physical delivery are exempt from the reporting requirement for the same reason that such contracts need not be reported in Electric Quarterly Reports (EQRs).^[53]

40. The Commission accepts the proposal submitted by Calpine, Cinergy and Tractebel that a decrease in ownership or control due to dispositions of generation, transmission or inputs to production should not be reportable to the extent such transaction decreases the applicant's generation market power as measured by the indicative screens.

41. Finally, we reject National Grid's arguments that long-term contracts that were entered into by a utility to satisfy its POLR obligations or pursuant to a state-regulated competitive solicitation process should be exempted from the reporting requirement. To the extent that an applicant acquires additional capacity that impacts the Commission's analysis of one or more prongs of the four-part test used in evaluating whether to grant market-based rate authority, a change in status filing is required.

Control/Ownership

Comments

42. Several commenters express support for the inclusion of “control” as a triggering event. In supporting the inclusion of control as a triggering event, the California EOB argues that the concept of control should be used to expand the scope of the triggering requirements, not narrow them.^[54]

43. Other commenters argue that the definition of control is vague and overly broad and note, for example, that it could be interpreted to cover individual power purchase transactions.^[55] These commenters argue that the Commission should narrowly define control by identifying the specific decision-making authority that the purchaser or reseller must have in order to constitute control. PG&E argues that control should only cover cases where the purchaser has operational control of the resource, i.e., the ability to determine when it is available for operation, and should not apply to an entity who has contracted for the first right, or even the exclusive right, to call or dispatch the resource when it is needed.^[56] FirstEnergy contends that market-based rate sellers should only be required to report long-term contracts that transfer to the purchaser or reseller the authority over dispatch of the unit and preclude the generation owner from dispatching the unit without the consent of the purchaser or reseller.^[57] Similarly, Duke Energy Corporation (Duke) argues that the Commission should apply general principles of agency as developed by Commission precedent, whereby the Commission has found that a purchaser has control if it possesses decisionmaking authority over key operations, such as decisions to commit or de-commit a generator or to make or not make sales.^[58] EPSA agrees that control over an asset is a key consideration in a market power analysis. However, EPSA states that the use of the term “operational control” creates uncertainty and suggests that the Commission drop all references to “operational control” and replace it with “scheduling and dispatch control” or clarify that operational control refers to a contractual right to control the output of a plant.^[59] The Bank Power Marketers suggest that the factors indicating control include definitive authority to: Require a plant to run or to shut down; declare unscheduled outages; or establish output levels when running (i.e., to ramp-up or down).^[60]

44. Calpine suggests that the test for control should be whether the purchaser has the authority to make available to the market and withhold from the market generation products associated with generation capacity.^[61] For example, Calpine submits that a tolling agreement should be reportable if it permits a public utility to operate a plant that gives it the authority to generate or not generate from that plant.^[62] Cinergy argues that control should be defined in a manner that is more directly linked to standard measures of market power as used by the Commission and the antitrust agencies, i.e., whether a new contractual arrangement provides an applicant with the ability to economically or physically withhold from the market, or erect a barrier to entry.^[63] For the same reasons, TAPS urges the Commission to require reporting of long-term maintenance agreements between market-based rate sellers or their affiliates that grant the entity providing the maintenance services the ability to decide when such maintenance is performed. TAPS contends that, if the entity providing maintenance also operates facilities in the same market (or has an affiliate that does so), its decisions about when to perform the maintenance (thereby possibly requiring an outage) could be influenced by its (or its affiliate's) sales activities in the market.^[64]

45. SoCal Edison requests that the Commission identify the duration of the change in control necessary to trigger the reporting requirement. According to SoCal Edison, very short-term transactions may temporarily convey control over a resource, but it is doubtful that requiring reporting of such transactions 30 days after their conclusion will provide meaningful or useful information to the Commission. SoCal Edison suggests that the appropriate minimum duration would be at least a 32-day transaction involving change in control.^[65] SoCal Edison also argues that the Commission should consider focusing primarily on net changes in control of uncommitted generation.^[66]

46. BP Energy urges the Commission to clarify that the reporting requirement is limited to ownership or contractual control equivalent to ownership, rather than “influence”, which is vague and subject to conflicting interpretations.^[67] FirstEnergy argues that market-based rate sellers should only be required to report changes in ownership that result in a change in control. FirstEnergy states that the Commission has previously recognized that certain passive owners of generation assets do not have control over such assets, and therefore do not constitute regulated public utilities. According to FirstEnergy, even if a public utility acquires or increases its ownership interest in a generation or transmission facility, it would not be appropriate to attribute the capacity in that facility to the utility, unless the utility had decisionmaking authority over sales of electric energy from the facility. FirstEnergy asserts that it is essential that the Commission define more precisely when a change in ownership or control conveying the requisite decisionmaking authority is deemed to have occurred. It notes that the Commission has previously ruled that a voting interest of 10 percent or more creates a rebuttable presumption of control over a utility that is not an EWG and that a voting interest of five percent or more is used in the case of a utility that is an EWG.^[68] FirstEnergy submits that, as a practical matter, it is unlikely that a voting interest that is less than or equal to these thresholds, without more, will convey decisionmaking authority over sales of electric energy. FirstEnergy thus suggests that the Commission should adopt a higher threshold of asset ownership of at least 33.3 percent before a potentially reportable change in control is deemed to have occurred.^[69] FirstEnergy adds that even a 33.3 percent voting interest should not be deemed to have transferred decisionmaking control if another entity (either individually or in conjunction with affiliated interests) owns a larger voting interest.

Commission Conclusion

47. We will adopt the inclusion of control as one of the factors that could result in a change of status filing. We have previously stated that “control” refers to arrangements, contractual or otherwise, granting control of generation or transmission facilities, just as effectively as they could through ownership.^[70] In short, if an applicant has control over certain capacity such that the applicant can affect the ability of the capacity to reach the relevant market, then that capacity should be attributed to the applicant when performing the generation market power screens.^[71] As the Commission's guidelines for the assessment of mergers and its generation market power analysis for market-based rate authority provide, for the purposes of the market power analysis, the capacity associated with contracts that confer operational control of a given facility to an entity other than the owner must be assigned to the entity exercising control over that facility, rather than to the entity that is the legal owner of the facility. We believe that the Commission has given adequate specificity as to what constitutes control and the Commission will not, in this docket, further define or narrow the definition. Control of assets is a concept that this industry has dealt with for many years. The Commission is reluctant to provide a laundry list of agreements that may or may not constitute control of an asset. It is not possible to predict every contractual agreement that could result in a change of control of an asset. However, to the extent parties wish to propose specific definitions or clarifications to the Commission's historical definition of control, they may do so in the course of the market-based rate rulemaking in Docket No. RM04-7-000.

48. In response to SoCal Edison's request that the Commission identify the duration of the change in control necessary to trigger the reporting requirement, we clarify that long-term contracts with a duration of a year or more must be reported, which is consistent with our treatment of long-term contracts in the April 14 Order.^[72]

Affiliation

Comments

49. Commenters also request clarification as to the scope of affiliate-related reporting requirements.^[73] BP Energy states that, as proposed, the reporting obligation appears to attach to affiliation with any entity not disclosed in the original application that owns or controls generation or transmission facilities or inputs to electric power production, or any entity with a franchised service territory. BP Energy requests clarification that the reporting requirement does not require a public utility with market-based rates to file a notice of a change in status if an affiliated generator identified in the original application increases the amount of generation it owns, so long as the public utility with market-based rates does not own or control the newly-acquired generation.^[74]

50. Sempra Energy Global Enterprises (Sempra) seeks a similar clarification that, when updating information regarding activities of affiliates, a market-based rate seller is only required to report new affiliations and would not be required to report changes in status on behalf of other affiliates whose existence has already been disclosed to the Commission. Sempra adds that a market-based rate seller should only be required to provide information that relates to a new affiliation in markets where the seller's relevant operations or assets overlap with those of the new affiliate.^[75]

Commission Conclusion

51. With respect to BP Energy's and Sempra's request for clarification, as noted above, the reporting requirement applies to changes in status relevant to the Commission's current four-part analysis for market-based rate authority. To the extent that an affiliate experiences a change in status, such change in status must be reported to the extent that it impacts the factors the Commission relied upon in evaluating the four-part test as it applies to the applicant and granting the applicant market-based rate authority. To avoid any unnecessary duplication, we clarify that the various affiliates within a corporate family may submit a single notice for the corporate family as a whole for each reportable change in status that occurs listing all affiliated companies holding market-based rate authority in such notice.

Inputs to Electric Power Production

52. We noted in the NOPR that the Commission's general practice has been to require notifications of changes in status when the market-based rate applicant obtained ownership of new inputs to electric power production, other than fuel supplies. However, since the Commission is interested in being informed of significant acquisitions of ownership or control of any inputs to electric power production, we proposed to require a reporting obligation to this effect and sought comments on this proposal.

Comments

53. A number of commenters request clarification of the term “inputs to electric power production” and urge the Commission to define this term to include or exclude certain inputs. APPA, EPSA, Powerex and TAPS submit that fuel supplies should not be considered inputs to electric power production.^[76]

54. Cinergy argues against a reporting obligation for fuel supplies because, according to Cinergy, the Commission has found the markets for natural gas and coal to be workably competitive. Cinergy asserts that information regarding fuel supplies is typically not required for the initial application for market-based rate authority and therefore should not be presumed to be relevant to the question of continued eligibility for market-based rate authority. Thus, in light of the lack of benefits to be obtained from the reporting of fuel supply arrangements, Cinergy contends that reporting would be unduly burdensome. Cinergy also contends that the only conceivable relevance of fuel supplies in authorizing market-based rates is in demonstrating that no barriers to entry or vertical market power concerns are present. To the extent that the Commission wishes to extend its consideration of barriers to entry to fuel supplies, Cinergy argues that the appropriate context to do so is not in the current rulemaking, but rather in the generic rulemaking proceeding in Docket No. RM04-7-000.^[77]

55. APPA, Calpine, the National Association of State Utility Consumer Advocates (NASUCA) and TAPS, however, support the inclusion of fuel supplies within the list of triggers for reporting changes in status. NASUCA states that electric utilities, power brokers, and other sellers of energy at market-based rates can acquire substantial control over natural gas supplies or other sources of fuel for generating units and effectively dominate the fuel supplies in the markets in which they also sell electricity. According to NASUCA, including fuel supplies within the category of changes that warrant a reporting requirement properly reflects the convergence of the electricity and natural gas industries and the potential for exercising market power that can result from the acquisition of critical supplies of fuel.^[78] Calpine similarly asserts that the ability to control the transportation of inputs such as fuel may be just as important as controlling the input itself.^[79]

56. With respect to pipeline capacity, EPSA argues that increased pipeline capacity holdings should not be reportable because firm capacity is obtained through Commission-authorized programs and is posted on the pipeline's bulletin board.^[80] FirstEnergy, by contrast, argues that changes in status relating to ownership or control of interstate natural gas pipelines or local distribution companies should be reportable because control over natural gas supplies are the principal input to electric power production may enable an entity with market-based rate authority to erect barriers to entry by competitors, especially if the seller is a combination electricity/natural gas utility. FirstEnergy asserts that the acquisition of other inputs, e.g., generation plant sites, construction or engineering companies or fuel production resources, should not be reportable.^[81]

57. Other commenters also argue that the Commission's inquiry should be focused on the potential for market-based rate sellers to erect barriers to entry. Bank Power Marketers argue that the Commission should issue a supplementary NOPR to provide additional guidance on what level of ownership or control of inputs to electric power production is “significant” enough to warrant disclosure and submits that, in order to be “significant”, the acquisition of an input must be of the type that gives the acquirer vertical market power; otherwise, such acquisitions should not be reportable.^[82] Similarly, Sempra argues that the Commission has never clearly defined the scope of what constitutes “inputs to electric power production” and that it should either be deleted or, alternatively, the Commission should implement a “timeout” with regard to enforcement of the reporting requirement for such inputs until it has completed its consideration of the barriers to entry prong of its market-based rate analysis in the Docket No. RM04-7-000 proceeding.^[83] BP Energy contends that the disclosures should be limited to only the information necessary to identify the type and the source of potential barriers to entry.^[84] BP Energy states that the Commission should identify specifically what the relevant “inputs to electric power production” are, and it should state clarify whether such inputs include items other than those specified in previous orders, i.e., ownership or control of new generation sites, fuel supplies (natural gas, oil or coal), transportation of fuel supplies or whether the affiliate is a supplier of electric equipment.^[85] Duke argues that an arrangement regarding inputs to electric power production should only be reportable if it conveys to the market-based rate seller the decisional control sufficient to enable it to erect barriers to entry. Under this approach, Duke contends that natural gas, oil or coal transportation or storage contracts and fuel purchase contracts should not be reportable.^[86]

Commission Conclusion

58. As we stated in the NOPR, the Commission's general practice has been to require notification of changes in status when the market-based rate applicant obtained ownership of new inputs to electric power production, other than fuel supplies. However, we proposed in the NOPR to include fuel supplies as an input to electric power production and sought comments on this proposal. After careful consideration of the comments, including the arguments raised by commenters that this issue in any event is more appropriately raised in the proceeding in Docket No. RM04-7-000 as part of the Commission's consideration of the barriers to entry prong of the market-based rate analysis, we have decided not to make any changes to our precedent at this time as to what constitutes an input to electric power production, including expanding the definition to include fuel supplies. As a result, the regulations we adopt in this rule will require the reporting of ownership or control of inputs to electrical power production, other than fuel supplies. Nevertheless, we will provide interested persons an opportunity to propose modifications to this approach in the course of the generic rulemaking proceeding in Docket No. RM04-7-000.

59. Further, we clarify that an arrangement regarding inputs to electric power production, other than fuel supplies, is reportable to the extent that the factors the Commission relied on in evaluating the four-part market-based rate test as it applies to the applicant change.

Materiality Threshold

60. We recognized in the NOPR that the language in the proposed regulations may be susceptible to different interpretations among market-based rate sellers concerning the scope of their reporting requirement. Accordingly, we sought public comment as to whether and how this language should be modified to ensure that the types of changes in status that could impact the continued basis of a grant of market-based rate authority are identified and timely reported to the Commission. For example, we asked whether there should be a threshold level of increases in generation (such as through acquisition, self-build, long-term power purchases, re-powering) that would trigger the reporting requirement. If so, we asked what amount of increase in generation should trigger the reporting requirement.

Comments

61. Several commenters suggest specific materiality thresholds by designating a particular amount or percentage of increase in generation capacity as the trigger for the reporting requirement, while others urge the Commission to clearly define the threshold without suggesting a particular amount.^[87] For example, APPA, TAPS, and Tractebel suggest a threshold of 100 MW.^[88] APPA and TAPS further suggest that acquisitions of 100 MW or more should be promptly reported with all capacity changes (increases or decreases) identified as part of the market-based rate sellers' Order No. 2001 quarterly transactions reports.^[89] Powerex argues that the materiality threshold should be no less than a 250 MW change increase in the ownership or control of generation capacity from the last triennial review or the last notice of a change in status.^[90] EEI, supported by Xcel, proposes that the reporting threshold should be an increase in net excess generation capacity (i.e., an increase in the applicant's generation capacity above its forecasted native load growth requirements, reliability requirements and contractual obligations) that is equal to the greater of: (i) 250 MW, (ii) 10 percent of installed nameplate generation capacity, or (iii) five percent of the capacity in the control area market.^[91] FirstEnergy suggests that an increase in generation capacity should trigger the reporting requirement if it exceeds the greater of either 250 MW or a 10 percent increase in the market-based rate seller's uncommitted generation capacity.^[92]

62. BP Energy and EPSA both contend that the materiality threshold should take into account the increase in the market-based rate seller's market share and its impact on the relevant geographic market, as well as the absolute amount of the increase in generation capacity. EPSA suggests that the materiality threshold should be in the range of 250-500 MW or one to two percent of the installed capacity in a market area.^[93] BP Energy proposes a materiality threshold for ownership or control of generation that would be the greater of a net positive change of 300 MW or one to two percent of the installed capacity in the relevant market (determined by ISO/RTO or NERC region or control area).^[94] ELCON proposes that the final rule should include a materiality threshold for large, end-use corporations for changes in generation at its production sites, e.g., a 300 MW increase in generation, or alternatively, an increase in generation equal to one or two percent of installed capacity in a region market; to the extent that the increase in generation is less than this threshold, the 30-day reporting requirement should be waived.^[95]

63. SoCal Edison argues that EEI's proposal should be modified to provide that only the 10 percent threshold for increases in generation capacity should apply for load-serving entities because such entities may add 250 MW or more in the normal course of business—in order to meet resource adequacy requirements or in response to normal load growth—without effecting any material change in its ability to exercise market power.^[96] SoCal Edison proposes that the materiality threshold for a change in status other than an increase in generation capacity should be a net increase of 10 percent from the data that the Commission relied upon in granting market-based rate authority.^[97]

64. Cinergy proposes that a transaction should not be considered material if, first, it involves the acquisition of generation that is not in the same relevant geographic market as the applicant's existing generation. Alternatively, a transaction would not be material if: (i) It increases the applicant's generation in the relevant geographic market by two percent or less; (ii) the applicant's existing generation in the market is low (e.g., less than 1000 MW), and the increase is less than 10 percent of the total market; or (iii) the acquired generation is in an RTO that has restructured its market.^[98]

65. PacifiCorp urges the Commission to permit market-based rate sellers to rely on forecasts of load growth in determining whether an acquisition of new generation resources constitutes a material change in the conditions in the market.^[99] According to Pacificorp, a utility should be required to report a material change only when it increases its net generating capacity by acquiring additional resources in excess of its forecasts for native load growth. Avista Corporation (Avista) suggests that, for a utility the size of Avista, the threshold level of increase in generation before triggering the reporting requirement should be not less than 10 percent of the utility's retail and wholesale peak load obligations.^[100]

66. NASUCA opposes the establishment of a materiality threshold for reporting a change in status, but suggests instead that the Commission could exempt from the rule changes in status that do not stem from changes in ownership or control of generation, fuel, transmission or power supply assets such as a change in corporate name unrelated to a merger or acquisition.^[101] According to NASUCA, establishing triggers for determining when reporting of a change in status is necessary may lead to under-reporting due to varying interpretations of what types of assets should be considered. NASUCA asserts that requiring all changes, however small, to be reported will permit Commission review and ensure that a change in status will not allow a seller with market-based rate authority to exercise market power.

67. PG&E, as discussed above, opposes the imposition of a uniform reporting requirement that imposes identical reporting obligations on energy marketers and traditional utilities. PG&E urges the Commission to establish, for traditional utilities, a threshold for an increase in wholesale sales or revenues from wholesale sales that the Commission concludes is statistically relevant or has the potential to influence the overall market. Under PG&E's proposal, if a traditional utility's quarterly report shows an increase in wholesale sales or revenues from wholesale sales that exceeded this threshold, the utility would be obligated to provide—in the same quarterly report—additional information about the transactions that caused the increase. PG&E contends that this proposal, if adopted would ensure that the Commission received targeted information, while reducing the burden on both utilities and the Commission.^[102]

Commission Conclusion

68. After careful consideration of the comments received, the Commission has concluded that small increases in generation of less than 100 MW need not be immediately reported. However, market-based rate sellers must report as a change in status each cumulative increase in generation of 100 MW or more that has occurred since the most recent notice of a change in status filed by that seller, (i.e. multiple increases in generation that individually do not exceed the 100 MW threshold must all be reported once the aggregate amount of such increases reaches 100 MW or more). The Commission's market power analysis, which is performed at the time of an initial application and every three years thereafter, considers all relevant generation capacity to assess whether a seller lacks, or has adequately mitigated, generation market power. In light of these periodic reports, we believe that a minimum reporting threshold for generation increases during the interim period is appropriate. We believe that this approach strikes the proper balance between the Commission's duty to ensure that market-based rates are just and reasonable and the Commission's desire not to impose an undue regulatory burden on market-based rate sellers.

69. Finally, we believe that the definition of control (i.e., arrangements, contractual or otherwise, that grant to a purchaser or reseller or to another third party who is not the legal owner of the facilities in question operational control over the facility) that we discuss earlier in this order already contains within it a materiality threshold. Changes in status that do not comprise control (and that do not otherwise trigger the reporting requirement) need not be reported.

70. Likewise, we reject PG&E's proposal to treat traditional utilities in this regard differently than other market-based rate applicants. PG&E's suggestion that the Commission link the change in status reporting requirement to increases in wholesale sales or revenues is inconsistent with the market-based rate four-part test which evaluates, among other things, whether an applicant is a pivotal supplier and the applicant's size in relation to the market. However, to the extent an applicant has historical wholesale sales and transmission data it believes is relevant, the Commission encourages the inclusion of such data in the applicant's submittal, and the Commission will consider such data in its analysis.

Transmission Outages

71. In the NOPR, the Commission also asked whether the applicant should have a reporting requirement if portions of the applicant's transmission system are taken out of service for a significant period of time (thus potentially affecting the scope of the relevant geographic market). If so, we sought comments on what criteria should trigger this reporting requirement.

Comments

72. A number of commenters support the extension of the reporting requirement to cover transmission outages and propose specific thresholds for triggering the reporting requirement. The California Public Utilities Commission (California Commission) states that the Commission should require reporting (and provide guidelines regarding when such reporting is required) when a transmission facility remains congested over a specified period of time such that market power could result.^[103] Powerex supports the imposition of a reporting requirement for transmission outages that last for a significant period of time, but requests that the Commission clarify that the reporting requirement applies only to the market-based rate seller that owns or controls the transmission facilities suffering an outage and not to its affiliates.^[104] Powerex notes that, in any case, information on transmission outages typically is otherwise available on the transmission owner's Open Access Same-Time Information System (OASIS).^[105] Calpine submits that the transmission providers' reporting requirement should cover instances where a transmission outage that lasts 10 days or more results in a decrease of 10 percent or more in the amount of total transmission capacity on transmission facilities operated by the transmission provider within the control area in which the public utility owns or controls generating capacity, or in facilities connecting to an adjacent control area.^[106] APPA and TAPS propose that transmission providers be required to report all non-public, extended transmission outages to the Commission's Office of Market Oversight and Investigation for monitoring and to publicly report extended outages of certain designated critical facilities.^[107] NASUCA contends that all entities with market-based rate authority affected by an extended outage should be required to report such outages regardless of whether they own the affected transmission assets.^[108]

73. Certain investor-owned utilities such as FirstEnergy and Xcel oppose a reporting requirement for transmission outages, arguing that it is unnecessary because such outages are reported on a transmission provider's OASIS.^[109] National Grid argues that transmission outages should not be reportable where such outages are administered by independent entities such as an ISO or an RTO.^[110]

74. Other investor-owned utilities such as Avista and Cinergy support the reporting requirement for major transmission outages that last longer than one year.^[111] Duke also agrees that transmission outages should be reportable provided that they are expected to last 6 months or more and that they reduce available transmission capacity on the path or flowgate in question by 20 percent of the posted total transmission capability of that path.^[112] Cinergy further suggests that, for transmission outages that occur within an RTO-operated market, the filing of the change in status should be made by the RTO, in consultation with the transmission owner.^[113]

Commission Conclusion

75. After careful consideration of the comments, we are not prepared at this time to require the reporting of transmission outages per se as a change in status. However, to the extent a transmission outage affects one or more of the factors of the four-part market-based rate test (e.g., if it reduces imports of capacity by competitors that, if reflected in the generation market power screens, would change the results of the screens from a “pass” to a “fail”), a change of status filing would be required. Because such instances would occur on a company-specific basis, a minimum threshold (e.g., 10 percent reduction in capacity) is not workable. We will consider this matter further in the context of the generic rulemaking in Docket No. RM04-7-000 in which we are addressing, among other things, issues associated with transmission market power.

Other Reportable Arrangements

76. Beyond ownership or control of generation or transmission facilities or inputs to electric power production and affiliation with any entity not disclosed in the filing that owns or controls generation or transmission facilities or inputs to electric power production or affiliation with any entity that has a franchised service area, we sought comment as to whether there are other arrangements, contractual or otherwise, that should be promptly reported to the Commission. For example, we posed the following questions:

• What types of arrangements, contractual or otherwise, do market-based rate sellers enter into that could cause a need for the Commission to revisit the continuing basis of the grant of market-based rate authority for such sellers?
• What threshold of materiality, if any, of such arrangements should be met before such arrangements need be reported to the Commission?
• Should marketing alliances, brokering arrangements, tolling agreements or other sales-oriented arrangements be reported?

Comments

77. APPA, NASUCA and TAPS support the imposition of the reporting requirement for such sales-oriented arrangements and request that the Commission consider subjecting a wider range of arrangements to the reporting requirement.^[114] NASUCA recommends that financial transactions including, but not limited to, the above types of sales-oriented arrangements should be covered by the reporting obligation, because such transactions provide the same type of control over power sales as ownership of physical assets would.^[115] TAPS recommends that the Commission consider long-term maintenance agreements that grant a market-based rate seller the ability to decide when such maintenance is performed because, if the entity providing maintenance also operates facilities in the same market or has an affiliate that does so, its decisions about when to perform the maintenance (thereby possibly requiring an outage) could be influenced by its or its affiliate's sales activities in the market.^[116] APPA, Powerex, and TAPS support an approach of listing the specific types of arrangements that the Commission expects to be reported to provide clarity to power sellers.^[117]

78. BP Energy, however, questions whether brokering agreements can be subjected to the reporting requirement. BP Energy asserts that it is not presently clear whether brokering activities and agreements are subject to the Commission's jurisdiction under the FPA.^[118] BP Energy requests that, if the Commission intends to require reporting of brokering agreements, the Commission should identify the basis and scope of its claimed jurisdiction. Tractebel also questions the Commission's jurisdiction over such arrangements and argues that brokering arrangements should not be reportable, given that information on such arrangements need not be reported as part of an application for market-based rate authority or a triennial review.^[119]

79. Cinergy, EEI and Sempra argue that the Commission's suggestion to require reporting of specific types of contracts would elevate the form of the agreement over the substance. Cinergy opposes the Commission's proposal in the NOPR regarding other reportable arrangements, which it characterizes as a “label-based” approach, because there is little standardization or uniformity in the industry as to the content of such agreements. Cinergy urges the Commission to instead focus on the attributes of the agreement in question, i.e., what degree of control over generation or transmission it conveys.^[120] EEI similarly argues that the reporting requirement should be limited to those arrangements in which the seller acquires control over generation or transmission facilities, franchised distribution service facilities or production inputs exceeding the thresholds established by the Commission.^[121]

80. Sempra opposes as unnecessary the proposal in the NOPR to require reporting of specific types of contracts, arguing that the Commission's existing requirement that a notice of a change in status must be filed when an applicant acquires, or gains control of, additional generation or transmission assets already captures a transaction like that described in the El Paso Electric Power Co. case.^[122] Sempra further argues that to require market-based rate sellers to file updates for a broad, ill-defined list of commercial arrangements would unfairly place the burden on the market-based rate seller to guess which commercial relationships to report, in violation of the Commission's decision in Morgan Stanley Capital Group, Inc., where the Commission concluded that entities with market-based rate authority no longer needed to report “business and financial arrangements between power marketers and their customers and transmission providers.^[123]

81. APPA, Powerex, and TAPS, on the other hand, support an approach of listing the specific types of arrangements that it expects to be reported because this approach provides clarity to sellers.^[124] For example, APPA and TAPS argue that these arrangements should be reported because they may provide a market-based rate seller with the means to determine whether capacity is offered into a market or whether a competitor can or will enter a market and may create opportunities for sellers to coordinate their behavior with other competitors. APPA and TAPS further emphasize that tolling agreements should be reported because they allow a fuel supplier to control the plants' production of energy for sale, thus affecting market outcomes, even if the fuel supplier does not operate the plant.^[125]

Commission Conclusion

82. Based on our review of the comments received, we find that contracts or arrangements that convey ownership or control over generation, transmission or other inputs to electric power production, other than fuel supplies, should be reported as a change in status. This is consistent with the four-part test the Commission relies upon in determining whether to grant market-based rate authority. Specifically, the April 14 Order requires an applicant to include in its analysis all capacity owned or controlled by the applicant or its affiliates.^[126]

83. We agree in principle with the comments submitted by Cinergy, EEI and Sempra, which stated that the label placed on a specific contract does not determine whether it constitutes a reportable change in status. Instead, it is the manner in which the specific terms and conditions of the contract or arrangement convey ownership or control of the generation, transmission or other inputs to electric power production. Nevertheless, we believe that providing a non-exclusive, illustrative list of other reportable arrangements will assist market-based rate sellers in complying with their reporting obligations. Therefore, we clarify that agreements that relate to operation (including scheduling and dispatch), maintenance, fuel supply, risk management, and marketing that transfer the control of jurisdictional assets are subject to the change in status reporting requirement. These types of arrangements have been referred to as energy management agreements, asset management agreements, tolling agreements, and scheduling and dispatching agreements.

Form and Content of Reports

84. With respect to the form and content of change in status reports, the NOPR proposed that the market-based rate seller be required to submit a transmittal letter including a description of the change in status and a narrative explaining whether (and, if so, how) this change in status reflects a departure from the characteristics relied upon by the Commission in originally granting the seller market-based rate authority, in particular, whether the change in status affects the results of any of the prongs of the four-part test that the Commission uses to determine whether a public utility qualifies for market-based rate authority. If the market-based rate seller believes that a change in status does not affect the continuing basis of the Commission's grant of market-based rate authority, we proposed that it should clearly state the reasons on which it bases this conclusion.

Comments

85. BP Energy, California EOB, Calpine, EPSA, and Powerex agree that market-based rate sellers should provide a narrative explaining the manner in which changes in status reflect a departure from the characteristics relied upon for market-based rate authorization.^[127] EPSA submits that a short transmittal letter explaining the transaction should suffice to put the parties and the Commission on notice of any possible change in status. According to EPSA, requiring more of applicants would be administratively burdensome, costly and unnecessary. EPSA contends that that Commission's goal should be to adopt a cost-effective approach to protecting customers from the exercise of market power, while at the same time minimizing the costs and uncertainty associated with a change in status, and that a short transmittal letter would accomplish that goal.^[128]

86. BP Energy, Calpine, and Powerex argue that the report should consist of a narrative only and should not include an updated market analysis such as that which is required by the triennial review.^[129] Similarly, SoCal Edison supports the timely provision of a narrative that includes germane information, including a recitation of the key dimensions of the transaction, but opposes a requirement to make an extensive showing to justify retention of market-based rate authority.^[130]

87. With respect to contractual arrangements, the United States Department of Justice (DOJ) opposes a reporting requirement that might call for a full-blown competitive analysis for every reportable transaction and instead suggests that market-based rate sellers simply file a copy of the contract concerned along with a summary of its key attributes that have an effect on the parties' incentive or ability to exercise market power.^[131] DOJ also suggests that Commission limit the obligation of applicants to disclose confidential, “business sensitive” information, which may discourage utilities from entering into otherwise efficient agreements, and customer-specific transaction data, which may reduce competition by facilitating collusion among competitors in oligopolistic markets.^[132]

88. Cinergy proposes that the Commission adopt a two-tiered approach to reporting, depending on whether the event to be reported is material or not. In cases where an applicant concludes in good faith that the change is non-material, the applicant would submit a short letter describing the event and briefly informing the Commission why the applicant believes the event is non-material. For material changes in status, the applicant would describe with greater particularity the basis for a continued grant of market-based rate authority, including an updated market analysis where appropriate.^[133]

89. NRECA urges the Commission to minimize the reporting requirement for smaller market participants. NRECA suggests that the Commission could do so by including in the final rule a provision for waiver of the reporting requirement for small market participants that can show that the likelihood that the changes in status in question could affect the competitiveness of those markets is de minimis. Alternatively, the Commission could clarify that the report for small market participants may be as simple as a two-sentence letter describing the change and averring that they have not acquired market power as a result.^[134]

90. Some commenters contend that the change in status report should include some form of market power analysis. NASUCA contends that the report should include a revised triennial rate review filing and an updated market power analysis.^[135] Powerex and EPSA urge the Commission to affirmatively state that market participants may submit, in addition to the narrative explanation, the summary pages of their original pivotal supplier and market share analyses, modified to reflect the changed circumstances.^[136]

91. Finally, EEI and FirstEnergy argue that even the submission of a narrative only would be unduly burdensome and superfluous. According to EEI, a narrative filing requirement would be problematic because market-based rate sellers would not always know the complete scope and nature of the characteristics relied upon by the Commission or any changes in the ownership or control of other market participants in the market area and because the Commission has not yet adopted final generation market power screens or articulated the screens and tests for the remaining three prongs. EEI proposes that, instead, market-based rate sellers should be required to provide the Commission only with a description of the transaction and that such sellers should only be required to examine the implications of a change in status (as a supplement to the notice of a change in status) if the Commission or a market participant raises a concern.^[137]

92. FirstEnergy objects to the narrative requirement, first, on the ground that it is superfluous: the only changes in status for which a report may be required are changes in status that reflect a departure from the characteristics that the Commission relied upon in granting market-based rate authority; however, if a change in status does not affect the relevant characteristics, no report is required. FirstEnergy further contends that the narrative requirement unreasonably imposes on each seller an affirmative obligation to justify the continuation of their market-based rate authority every time it engages in a transaction that constitutes a reportable change in status, which would be costly and time-consuming. FirstEnergy also argues that there is no reason to believe that generation suppliers are uniquely situated to provide the kind of information that the Commission may need to evaluate whether a change in status might affect the continuation of a supplier's market-based rate authority, e.g., information concerning the size of the market or the availability of transmission import capacity into the market, which is equally available to the supplier and its competitors. FirstEnergy therefore suggests that, in the absence of a demonstration that legitimate concerns exist, the supplier should not be required to spend the time and resources that may be required to defend the continuation of its market-based rate authority between its triennial market power updates.^[138]

Commission Conclusion

93. We will adopt the proposal in the NOPR that the market-based rate seller submit a transmittal letter, including a description of the change in status and a narrative explaining whether (and, if so, how) this change in status reflects a departure from the characteristics relied upon by the Commission in originally granting the seller market-based rate authority.

94. After careful consideration of the comments received, we will not specify a uniform length for the narrative that an entity must file to explain whether a given change in its status reflects a departure from the characteristics relied upon by the Commission for the original and continued grant of market-based rate authority. The nature of the change that triggers the reporting requirement will necessarily determine the length and quality of the narrative, as well as whether additional documents and analysis is needed. It is incumbent upon the applicant to decide whether the change in status is a material change and to provide adequate support and analysis. This is consistent with our approach to new applications for market-based rate authority, where it is the applicant's responsibility to determine what to report and the degree of support and analysis to include.

95. Further, we will not require entities affected by a change in status to automatically file an updated market analysis, such as that required by the triennial review. However, an entity may provide such an analysis if it chooses. The Commission reserves the right to require additional information, including an updated market power analysis, if necessary to determine the effect of an entity's change in status on its market-based rate authority.

Inclusion of Reporting Requirement in Market-Based Rate Tariffs

96. In addition to including this reporting requirement in the Commission's regulations, we proposed that this reporting requirement be incorporated into the market-based rate tariff of each entity that is currently authorized to make sales at market-based rates, as well as that of all future applicants. Market-based rate sellers would be required to submit a conforming provision to their market-based rate tariffs at the time that they file any amendment to their tariffs or (if earlier) when they apply for continued authorization to sell at market-based rates (e.g., in their three-year updated market power analysis). However, the Commission proposed that the obligation to report be effective at the time that the Final Rule becomes effective.

Comments

97. Most commenters support the inclusion of the reporting requirement into the market-based rate tariff of each seller. No substantive opposition was expressed by commenters.

Commission Conclusion

98. We will adopt the proposal in the NOPR and require that the reporting requirement be incorporated in the market-based rate tariffs of each entity that is currently authorized to make sales at market-based rates, as well as that of all future applicants. Market-based rate sellers will be required to include the reporting requirement in their market-based rate tariffs either at the time that they file any amendment to their tariffs, when they report a change in status under this Final Rule, or when they file their three-year updated market power analysis, whichever occurs first. However, regardless of the date on which the seller amends its market-based rate tariff to include the reporting requirement, such reporting requirement will be considered part of the seller's market-based rate tariff as of 30 days after the date of publication of this Final Rule in the Federal Register.

Reporting Period/Timing

99. With respect to the procedures for reporting a change in status, we proposed in the NOPR that such notifications be filed no later than 30 days after the occurrence of the triggering event. We sought comment as to whether this proposed time period is appropriate.

Comments

100. Calpine and NRECA support the proposed 30-day reporting period.^[139] Calpine urges the Commission to clarify the event that marks the change in status and starts the 30-day clock running. Calpine proposes that it should be based on the legal effective date of the triggering event. For an increase in ownership or control of generation capacity, Calpine states that this would be the date that the public utility legally assumes ownership or control over the asset. For a self-build or repowering event, it could be the date of commercial operation.^[140] NRECA rejects arguments that the 30-day reporting period is burdensome, noting that events constituting a change in status such as the acquisition or disposition of generation assets, require advance planning in excess of 30 days and that the reporting requirement can be built into the planning process for such transactions.

101. ELCON asks the Commission to modify the 30-day reporting requirement to reduce the potential burden on entities that cannot exercise market power such as large industrial users that own and operate a growing amount of behind-the-meter customer generation. ELCON suggests that, first, the final rule keep the 30-day initial notice period that would alert the Commission that a potential change in status may have occurred, but it should then allow the respondent an additional 60 days thereafter to file additional documentation as necessary.

102. APPA, BP Energy and TAPS suggest the Commission permit prospective reporting, to the extent possible, of known or expected changes in status.^[141] IEU-Ohio/PJMICC would go further and require prospective reporting at least 60 days before the circumstances affecting market-based rate authority actually occur, to the maximum extent possible.^[142] Similarly, NASUCA urges the Commission to require that the report be submitted no later than the effective date of the change in status.^[143] In contrast, Avista argues that the time period for reporting should not begin to run until after the date of commercial operation and/or control over the asset is reached.^[144] Tractebel requests the Commission to consider pre-authorizing certain changes in status, as it does, for example in the context of changes in status regarding qualifying facilities under PURPA.^[145]

103. Other commenters, however, argue that the 30-day period is too short. EPSA, Xcel, and Powerex propose that change in status reports should be submitted on a quarterly basis, for example, concurrently with EQRs or Form 3-Qs.^[146] Duke suggests that the reporting period should be extended to six months,^[147] while Avista recommends a period of 60 days after initial delivery under a long-term contract begins.^[148]

104. Calpine and EPSA request clarification of the procedures for filing and responding to change in status reports to avoid uncertainty. EPSA proposes that such clarification should occur in a supplemental NOPR whereby the comments in this NOPR and in the supplemental NOPR can be considered by the Commission. Further, EPSA suggests that this reporting requirement be an interim requirement pending final issuance of a comprehensive market-based rate authority framework in Docket No. RM04-7-000 or another comprehensive proceeding.^[149] Calpine requests clarification of whether the reports should be filed in the same docket that originally granted market based-rate authority, whether the reports would be publicly noticed, and whether the Commission intends to respond to the reports if they raise no concerns.^[150]

Commission Conclusion

105. We are not persuaded by the suggestions to increase the 30-day period to a longer period of time, whether 60 days, quarterly, or six months. Thirty days appropriately balances the amount of time the applicant needs to prepare its filing against our need for timely information regarding changes in status that may affect prices and markets. The Commission finds the 30-day time period an appropriate one in which to receive information about a change in status so as to enable the Commission to effectively carry out our statutory responsibility to oversee competitive conditions in wholesale electricity markets. For this reason, we are not persuaded by the suggestion that we require entities to file changes in status concurrently with their EQRs. As discussed above, quarterly reporting would not provide the Commission with information on market developments in a sufficiently timely manner to perform our statutory duties. Furthermore, contrary to the suggestions of some commenters, combining the change in status reporting requirement with other reporting requirements, e.g., EQRs, would not create any efficiencies or reduce the burden on either the Commission or market-based rate sellers. In particular, the Commission has developed a specific electronic format for reporting transactions in EQRs ^[151] that would not accommodate the range of events that constitute changes in status.

106. We clarify that reports of changes in status must be filed no later than 30 days after the legal or effective date of the change in status, including a change in ownership or control, whichever is earlier. Parties are free to file reports of prospective changes, but that filing must contain the same information it would if it had filed after the change in status. We note that when performing the Commission's generation market power screens, applicants are prohibited from making forward-looking adjustments.

107. In response to a request for additional information about the processing of these reports, we clarify that the report should be filed in the same docket in which market-based rate authority was granted, and it should be served on the service list for that docket. The report will be noticed, and a comment period will be established.

Other Procedural Issues

Comments

108. BP Energy, EEI, EPSA and FirstEnergy request that the Commission clarify that change in status reports are purely informational and that any revisions or revocations to an entity's market-based rate authority will be made pursuant to section 206 proceedings.^[152] With respect to the burden of proof, Calpine recommends that the public utility should have the burden to demonstrate that it is still entitled to market-based rates after the change in status occurs and that if the Commission or any party believes that a report indicates that the basis for a public utility's market-based rates has been undermined by the change in status, there should also be a remedy through a section 206 action.^[153]

109. Powerex and SoCal Edison note that the NOPR failed to address the treatment of confidential and commercially sensitive information, and SoCal Edison requests that the Commission clarify that it requires only the minimal reasonable information necessary.^[154]

110. With respect to the procedural rights of third parties, APPA and TAPS argue that third parties should be permitted to report known or expected changes in status and that the Commission should permit them the opportunity to submit comments on change in status reports. Those reports meriting closer attention should result in the Commission's issuing a show cause order asking the seller to justify continuation of market-based rate authority.^[155]

111. Finally, Tractebel argues that the Commission should provide the opportunity for market-based rate sellers that comply with the reporting requirement, as well for protesters and intervenors, to obtain a timely “redetermination” or “reaffirmation” of their market-based rate authority.^[156]

112. Cinergy proposes that, for purposes of regulatory certainty, the Commission should commit to issue orders on notices of changes in status within 60 days of filing. Where an order accepts for filing a change in status report, such acceptance would be deemed an acknowledgement by the Commission that the reported event does not affect the applicant's market-based rate authorization. Similarly, if the Commission does not issue an order within 60 days, any reported transaction undertaken after such a 60-day period that conforms materially to the description of the transaction in the notice should fall within a safe-harbor and not trigger penalties, refunds or loss of market-based rates.^[157]

Commission Conclusion

113. In response to the requests above, we will clarify the legal effect of a notice of a change in status and the procedures that the Commission will follow in acting on notices of changes in status. First, a notice of a change in status, like the triennial update filing requirement, is a filing made in compliance with the terms and conditions under which the Commission has granted market-based rate authority. As discussed above, we will require that the reporting requirement be incorporated in the market-based rate tariffs of each market-based rate seller. Thus, a notice of change in status is an integral part of the market-based tariff, compliance with which is a condition for the retention of market-based rate authority. Consistent with the Commission's current practice, the Commission will continue the same procedures it has followed in processing filings of changes in status. Namely, the Commission will issue a notice of the filing to provide an opportunity for public comment. The filing will receive a subdocket under the docket number in which the seller originally received market-based-rate authority. The Commission, where appropriate, may request additional information from the market-based rate seller, institute a section 206 investigation or inform the parties that the Commission does not intend to take any further action regarding the change in status filing.

114. We further note that because a notice of a change in status, like a triennial update, is a compliance filing, rather than a rate filing under section 205 of the FPA, the Commission is not required to take action within 60 days. Consequently, we will reject Cinergy's proposal to commit to issuing an order on notices of a change in status within 60 days and to establish a safe harbor where the Commission has not acted on the filing within 60 days after receipt. Further, the filing alone may not provide sufficient information for the Commission to make a definitive finding regarding the impact of the change in status on the filing entity's market-based rate authority, and the Commission may require more than 60 days to gather the necessary information. However, it is the Commission's intention to act on these filings as expeditiously as possible.

115. With respect to the requests of BP Energy, EEI and FirstEnergy that the Commission clarify that it will only revoke or revise market-based rate authority pursuant to a section 206 proceeding, we note that the Commission's long-standing policy, in conformance with the FPA, has been to do so pursuant to a section 206 proceeding,^[158] and we will not change that policy here. In section 206 proceedings, the complainant or the Commission bears the burden of proof. Accordingly, we cannot change the statutory burden in response to Calpine's request.^[159]

116. Commission regulations set forth the procedures for requesting special treatment for confidential and commercially sensitive information to prevent public disclosure,^[160] and we do not find it necessary to establish additional procedures for such information contained in a notice of a change in status in response to the requests of Powerex and SoCal Edison.

117. With respect to APPA's and TAPS' concerns about the rights of third parties, we clarify that nothing in this final rule or the Commission regulations adopted herein changes the rights of third parties to file in response to a notice of change in status or to file a complaint pursuant to section 206.

Information Collection Statement

118. Office of Management and Budget (OMB) regulations require OMB to approve certain information collection requirements imposed by agency rule.^[161] The Commission solicited comments on the Commission's need for this information, whether the information will have practical utility, the accuracy of provided burden estimates, ways to enhance the quality, utility and clarity of the information to be collected, and any suggested methods for minimizing respondents' burden, including the use of automated information techniques.

119. Estimated Annual Burden to satisfy the reporting requirement, the Commission expects respondents to submit a transmittal letter including a description of the change in status and a narrative explaining whether (and, if so, how) this change in status reflects a departure from the characteristics relied upon by the Commission in originally granting the seller market-based rate authority. The Commission estimates that, on average, it will take respondents six hours per response and that approximately 25 percent of current market-based rate sellers would experience a change in status in any given year.

Data collection	Number of respondents	Number of hours	Number of responses	Total annual hours
FERC-516	1,238	6	.20	1,486

Title: Electric Rate Schedules and Filings, Reporting Requirement for Changes in Status For Public Utilities With Market-Based Rate Authority (FERC-516).

Action: Proposed collection.

OMB Control No.: 1902-0096.

Respondents: Businesses or other for profit.

Frequency of Responses: On occasion.

Necessity of Information: The proposed regulations will revise market-based rate sellers' reporting obligation and are intended to ensure that rates and terms of service offered by market-based rate sellers remain just and reasonable.

Internal Review: The Commission has reviewed the proposed amendment to its regulations to establish a reporting obligation for changes in status and has determined that these regulations are necessary to ensure just and reasonable rates. These regulations, moreover, conform to the Commission's plan for efficient information collection, communication, and management within the electric utility industry. The Commission has assured itself, by means of internal review, that there is specific, objective support for the burden estimates associated with the information/data retention requirements.

120. Interested persons may obtain information on the reporting requirements by contacting: Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, Attention: Michael Miller, Office of the Executive Director, phone: [phone], fax: [phone], e-mail: [e-mail]. Comments on the proposed requirements of the subject rule may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503, Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: [phone].

Comments

121. DOJ contends that the preparation of the transmittal letter may take more than six hours to prepare and may impose significant costs on applicants.^[162]

Commission Conclusion

122. The estimate contained in the NOPR of the time necessary to comply with the reporting requirement is an average. While such a letter may take more than six hours in some cases, we believe that in most cases compliance will take substantially less time. As we explain above, the more significant events triggering the reporting requirement will also trigger other reporting requirements, e.g., a section 203 application. In such a case, market-based rate sellers may incorporate by reference the related filing, and compliance with the change in status reporting requirement accordingly would require a minimal amount of time to prepare.

Environmental Analysis

123. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.^[163] The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. Included in the exclusion are rules that are clarifying, corrective, or procedural or that do not substantially change the effect of the regulations being amended.^[164] Thus, we affirm the finding we made in the NOPR that this final rule is procedural in nature and therefore falls under this exception; consequently, no environmental consideration would be necessary.

Regulatory Flexibility Act Certification

124. The Regulatory Flexibility Act of 1980 (RFA) ^[165] generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities.^[166] The Commission is not required to make such analyses if a rule would not have such an effect.

125. The Commission concludes that the final rule would not have such an impact on small entities. Based on past experience, most of the sellers having changes in status that would likely trigger a filing under the proposed regulations would be entities that do not meet the RFA's definition of a small entity. Therefore, the Commission certifies that this final rule will not have a significant economic impact on a substantial number of small entities.

Document Availability

126. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.

127. From FERC's Home Page on the Internet, this information is available in the Commission's document management system, eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

128. User assistance is available for eLibrary and the FERC's Web site during normal business hours. For assistance, please contact FERC Online Support at 1-866-208-3676 (toll free) or 202-502-6652 (e-mail at [e-mail]), or the Public Reference Room at 202-502-8371, TTY 202-502-8659 (e-mail at [e-mail]).

Effective Date and Congressional Notificiation

This Final Rule will take effect March 21, 2005. The Commission has determined with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of the Office of Management and Budget, that this rule is not a major rule within the meaning of section 251 of the Small Business Regulatory Enforcement Fairness Act of 1996.^[167] The Commission will submit the Final Rule to both houses of Congress and the General Accounting Office.^[168]

List of Subjects in 18 CFR Part 35

• Electric power rates
• Electric utilities
• Reporting and recordkeeping requirements

By the Commission.

Linda Mitry,

Deputy Secretary.

In consideration of the foregoing, the Commission amends part 35, Chapter I, Title 18 of the Code of Federal Regulations, as set forth below:

PART 35—FILING OF RATE SCHEDULES AND TARIFFS

1. The authority citation for part 35 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.

2. In § 35.27, paragraph (c) is added to read as follows:

§ 35.27

Power sales at market-based rates.

* * * * *

(c) Reporting requirement. Any public utility with the authority to engage in sales for resale of electric energy in interstate commerce at market-based rates shall be subject to the following:

(1) As a condition of obtaining and retaining market-based rate authority, a public utility with market-based rate authority must timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority. A change in status includes, but is not limited to, each of the following:

(i) Ownership or control of generation or transmission facilities or inputs to electric power production other than fuel supplies, or

(ii) Affiliation with any entity not disclosed in the application for market-based rate authority that owns or controls generation or transmission facilities or inputs to electric power production, or affiliation with any entity that has a franchised service area.

(2) Any change in status subject to paragraph (c)(1) of this section must be filed no later than 30 days after the change in status occurs.

Footnotes

1. ^-2.  16 U.S.C. 824d(a) (2000).

3.  Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31,043 (May 8, 2002), FERC Stats. & Regs. ¶ 31,127 (Apr. 25, 2002). The required data sets for contractual and transaction information are described in Attachments B and C of Order No. 2001.

4.  See, e.g., Entergy Services, Inc., 58 FERC ¶ 61,234 (1992); Louisville Gas & Electric, 62 FERC ¶ 61,016 (1993).

5.  See, e.g., Citizens Power & Light Corp., 48 FERC ¶ 61,210 (1989); Enron Power Marketing, 65 FERC ¶ 61,305 (1993); InterCoast Power Marketing Co., 68 FERC ¶ 61,248 (1994).

6.  See, e.g., Morgan Stanley Capital Group, Inc., 69 FERC ¶ 61,175 (1994).

7.  See, e.g., AEP Power Marketing, Inc., 76 FERC ¶ 61,307 at 62,516 (1996); Montaup Electric Co., 85 FERC ¶ 61,313 at 62,232 (1998); Sithe/Independence Power Partners, 101 FERC ¶ 61,210 at 61,907 (2002).

8.  16 U.S.C. 824d(f) (2000).

9.  Mayflower at 2, 8.

10.  109 FERC ¶ 61,019 (2004) (Perryville).

11.  Tractebel at 3-4.

12.  PG&E at 4-6.

13.  Perryville, 109 FERC ¶ 61,019 at P 20, 22.

14.  See AEP Power Marketing, Inc., 107 FERC ¶ 61,018 at P 186 (2004) (April 14 Order), order on reh'g, 108 FERC ¶ 61,026 at P 175 (2004) (July 8 Order).

15.  The Commission's regulations define “affiliated companies” as “companies or persons that directly, or indirectly through one or more intermediaries, control, or are controlled by, or are under common control with, the [subject] company.” 18 CFR part 101 (2004). See also 18 CFR 161.2 (2004); Morgan Stanley Capital Group, 72 FERC ¶ 61,082 (1995).

16.  See, e.g., Citizens Power, 48 FERC ¶ 61,210 at 61,777 (“Usually, the source of market power is dominant or exclusive ownership of the facilities. However, market power also may be gained without ownership. Contracts can confer the same rights of control. Entities with contractual control over transmission facilities can withhold supply and extract monopoly prices just as effectively as those who control facilities through ownership.”).

17.  See April 14 Order, 107 FERC ¶ 61,018 at P 95; 108 FERC ¶ 61,026 at P 65; Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, 61 FR 68,595 (1996), FERC Stats. & Regs. ¶ 31,044 (1996), recons. denied, Order No. 592-A, 62 FR 33,341 (1997), 79 FERC ¶ 61,321 (1997) (Merger Policy Statement); see also Revised Filing Requirements Under Part 33 of the Commission's Regulations, Order 642, 65 FR 70,983 (2000), FERC Stats. & Regs. ¶ 31,111 (2000), order on reh'g, Order No. 642-A, 66 FR 16,121 (2001), 94 FERC ¶ 61,289 (2001).

18.  El Paso Electric Power Co., 108 FERC ¶ 61,107 at P 14 (2004), reh'g pending.

19.  See, e.g., Xcel Energy Services (Xcel) at 4-5.

20.  Barclays Bank PLC, DB Energy Trading, LLC, Aron & Company, Merrill Lynch Commodities, Inc., Morgan Stanley Capital Group Inc. (Bank Power Marketers) at 13-14; FirstEnergy Service Company (FirstEnergy) at 5.

21.  Powerex Corporation (Powerex) at 5; Electric Power Supply Association (EPSA) at 2.

22.  Cinergy at 6.

23.  Calpine at 4-11; TAPS at 2 and 15.

24.  383 F.3d 1006 (9th Cir. 2004).

25.  NRECA at 5.

26.  Bank Power Marketers at 14.

27.  IEU—Ohio/PJMICC at 10-12.

28.  APPA at 7.

29.  EEI at 10-11; Pacificorp at 7.

30.  TAPS at 2 and 15.

31.  IEU—Ohio/PJMICC at 10-12.

32.  SoCal Edison at 9-10.

33.  BP Energy at 4-5; Cinergy at 16-17; Duke at 11-12; EPSA at 8-9; EEI at 4-5; FirstEnergy at 17-18.

34.  Bank Power Marketers at 6-12; Westar at 2-4.

35.  EEI at 4, 9-11; PacifiCorp at 5-7.

36.  National Grid at 4-5.

37.  16 U.S.C. 1601 et seq. (2000); National Grid at 3-4; IEU—Ohio/PJMICC at 7.

38.  Duke at 11-13.

39.  Cinergy at 12-17 (citing 18 CFR 35.27(a) (2004)).

40.  Tucson Electric at 3-4.

41.  Cinergy at 14-15; Tractebel at 6. Other commenters, in contrast, urge the Commission to treat the retirement or deactivation of generation as a triggering event. See, e.g., California Electricity Oversight Board (California EOB) at 2; IEU—Ohio/PJM ICC at 12.

42.  Calpine at 4-5.

43.  EEI at 7-8; FirstEnergy at 16-18; National Grid at 7.

44.  National Grid at 6. See also EEI at 13-14 (urging the Commission to consolidate the generic market-based rate rulemaking in Docket No. RM04-7-000 with the changes in status rulemaking in Docket No. RM04-14-000).

45.  EEI at 7-8; FirstEnergy at 16-18; National Grid at 6-7.

46.  National Grid at 8-9.

47.  National Grid at 10-11.

48.  See, e.g., Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 870 (DC Cir. 1993) Louisiana Energy and Power Authority v. FERC, 141 F.3d 365, 369-370 (DC Cir. 1998).

49.  18 CFR 35.27 (2004)

50.  April 14 Order, 107 FERC ¶ 61,018 at P 116.

51.  July 8 Order, 108 FERC ¶ 61,026 at P 110.

52.  See e.g., LG&E Capital Trimble County LLC, 98 FERC at 62,034-35.

53.  Revised Public Utility Reporting Requirements, Order No. 2001-F, 106 FERC ¶ 61,060 at P 15 (2004).

54.  California EOB at 3.

55.  See, e.g., Powerex at 8.

56.  PG&E at 9.

57.  FirstEnergy at 11-12.

58.  Duke at 3-7. Duke proposes that the analysis should thus focus on whether the arrangement shifts to a third party the economic decisionmaking authority regarding such matters as whether to buy and sell power, what products should be offered and what market should be bid into, which parties to transact with, or the prices and terms for service.

59.  EPSA at 6-7.

60.  Bank Power Marketers at 14.

61.  Calpine at 5.

62.  Calpine at 6-7. See also APPA at 19; TAPS at 19 (discussing tolling agreements).

63.  Cinergy at 7.

64.  TAPS at 19-20.

65.  SoCal Edison at 4.

66.  SoCal Edison at 6.

67.  BP Energy at 2, 5-6. BP Energy submits, for example, that if a public utility has a first call option on the output of a given generator but no control over the operation of that facility, the public utility seller should not be subject to the reporting requirement.

68.  FirstEnergy at 11 (citing Morgan Stanley Capital Group, Inc., 72 FERC ¶ 61,082 (1995)).

69.  FirstEnergy at 11.

70.  Citizens Power, 48 FERC ¶ 61,210 at 61,777.

71.  July 8 Order, 108 FERC ¶ 61,026 at P 65.

72.  April 14 Order, 107 FERC ¶ 61,018 at P 155.

73.  BP Energy at 2, 7-8.

74.  BP Energy at 7-8 and Sempra 10-11.

75.  Sempra at 10-11.

76.  APPA at 15; EPSA at 4; Powerex at 9; TAPS at 15.

77.  Cinergy at 8-10.

78.  NASUCA at 9-10.

79.  Calpine at 8-9. See also at 15; TAPS at 15. APPA and TAPS argue that affiliation or control over companies that produce or deliver fuel and long-term contracts for fuel transportation or storage should be reportable.

80.  Powerex at 9 and EPSA, 4.

81.  FirstEnergy at 19-21.

82.  Bank Power Marketers at 14-16.

83.  Sempra at 4-6.

84.  BP Energy at 8-9 (citing Vermont Electric Coop., 108 FERC ¶ 61,223, at P 12 (2004).

85.  BP Energy at 8-9 (citing Vermont Electric Coop., 108 FERF ¶ 61,223, at p 12 (2004)).

86.  Duke at 5.

87.  NRECA at 5; Sempra at 9-10.

88.  APPA at 2; TAPS at 2; Tractebel at 7.

89.  APPA at 2 and 17, TAPS at 2.

90.  Powerex at 5.

91.  EEI at 6-7.

92.  FirstEnergy at 22-23.

93.  EPSA at 7.

94.  BP Energy at 5.

95.  ELCON at 3-4.

96.  SoCal Edison at 8-9.

97.  SoCal Edison at 2-3.

98.  Cinergy at 20.

99.  PacifiCorp at 4.

100.  Avista at 1-2.

101.  NASUCA at 12.

102.  PG&E at 10-11.

103.  California Commission at 3; Powerex at 6.

104.  Powerex at 6.

105.  Powerex at 6.

106.  Calpine at 10.

107.  APPA at 2; TAPS at 14.

108.  NASUCA p10.

109.  Xcel at 7-8 and FirstEnergy at 23-24.

110.  National Grid at 10.

111.  Avista at 3; Cinergy at 17-18.

112.  Duke at 8.

113.  Cinergy at 18.

114.  TAPS at 19; APPA at 18.

115.  NASUCA at 11.

116.  TAPS at 19.

117.  APPA at 18; Powerex at 7; TAPS at 19.

118.  BP Energy at 6-7 (citing, e.g., Energy East South Glen Falls, 86 FERC ¶ 61,254, at 61,915 (1999); Citizens Energy Corp., 35 FERC ¶ 61,198 (1986); APX, Inc., 82 FERC ¶ 61,287 (1998)).

119.  Tractebel at 5.

120.  Cinergy at 10-11.

121.  EEI at 13.

122.  Sempra at 6-7 (citing 108 FERC ¶ 61,071 (2004), reh'g pending).

123.  Id. at 8 (citing 72 FERC ¶ 61,082 at 61,435 (1995).

124.  APPA at 18; Powerex at 7; TAPS at 19.

125.  APPA at 18-19; TAPS at 19.

126.  April 14 Order, 107 FERC ¶ 61,018 at P 95, 100.

127.  California EOB at 4; BP Energy at 10; Calpine at 11; Powerex at 9; EPSA at 7.

128.  EPSA at 7.

129.  BP Energy at 9-10; Calpine at 11; Powerex at 9.

130.  SoCal Edison at 4-6.

131.  DOJ at 11-12. DOJ asserts that the most important data are the names of the parties to the contract, the location of the generating assets under contract, and the location of any other generating assets owned or otherwise controlled by either counterparty, which would allow the Commission to quickly determine whether there is any geographic overlap among generating assets controlled by the parties. Other pertinent information includes information regarding any ownership interests parties have in common, the compensation scheme established between them, and agreement execution and start dates. DOJ at 8-9.

132.  DOJ at 313.

133.  Cinergy at 19.

134.  NRECA at 3-5.

135.  NASUCA at 13.

136.  Powerex at 9; EPSA at 9.

137.  EEI at 14-15.

138.  FirstEnergy at 12-15.

139.  NRECA at 4.

140.  Calpine at 12.

141.  APPA at 4; BP Energy at 10; TAPS at 4.

142.  PJMICC/IEU-Ohio at 14.

143.  NASUCA at 6.

144.  Avista at 4.

145.  Tractebel at 6 (citing 18 CFR 292.207 (2004)).

146.  EEI at 16-17; EPSA at 4; Powerex at 7; Xcel at 9-10.

147.  Duke at 9-10.

148.  Avista at 4.

149.  EPSA at 10.

150.  Calpine at 11.

151.  Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31,043 (May 8, 2002), FERC Stats. & Regs. ¶ 31,127 (Apr. 25, 2002).

152.  BP Energy at 3-4; EEI at 15; EPSA at 9; FirstEnergy at 15-16.

153.  Calpine at 12.

154.  Powerex at 10.

155.  APPA and TAPS at 2.

156.  Tractebel at 7.

157.  Cinergy at 21.

158.  See, e.g., Enron Power Marketing, Inc., 103 FERC ¶ 61,343 (2003), reh'g denied, 106 FERC ¶ 61,024 (2004); April 14 Order, 107 FERC ¶ 61,018 at P 201, 209.

159.  In addition, we note that we did not attempt to alter this statutory allocation of the burden of proof in the April 14 Order, as Calpine has previously argued. In the April 14 Order, we stated that failure of one of the generation market power screens would establish a rebuttable presumption of market power in the resulting section 206 proceeding. April 14 Order, 107 FERC ¶ 61,018 at P 201. In the July 8 Order, we explicitly rejected Calpine's allegation there that we had inappropriately shifted the statutory burden and clarified that an applicant's screen failure satisfied the Commission's initial burden of going forward with evidence in the section 206 proceeding. July 8 Order, 108 FERC ¶ 61,026 at P 29-30.

160.  18 CFR 388.112 (2004).

161.  5 CFR 1320.11 (2004).

162.  US DOJ at 11-12.

163.  Regulations Implementing the National Environmental Policy Act, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (Dec. 10, 1987).

164.  18 CFR 380.4(a)(2)(ii)(2004).

165.  5 U.S.C. 601-612 (2000).

166.  The RFA definition of “small entity” refers to the definition provided in the Small Business Act, which defines a “small business concern” as a business which is independently owned and operated and which is not dominant in its field of operation. 15 U.S.C. 632 (2000). The Small Business Size Standards component of the North American Industry Classification System defines a small electric utility as one that, including its affiliates, is primarily engaged in the generation, transmission, and/or distribution of electric energy for sale and whose total electric output for the preceding fiscal years did not exceed 4 million MWh. 13 CFR 121.201 (Section 22, Utilities, North American Industry Classification System, NAICS) (2004).

167.  See 5 U.S.C. 804(2) (2000).

168.  See 5 U.S.C. 801(a)(1)(A) (2000).