G. Other Changes to Remove Undue Discrimination and Improve the

Efficiency of the Markets under Standard Market Design

1. The existing pro forma tariff was constructed primarily to apply to vertically integrated public utilities. It was the first step toward competitive electric power markets since it allowed alternate suppliers to access loads through an open access transmission tariff. It sought to replicate the terms and conditions under which the host public utility served its own loads. It also was the first step in separating the generation and transmission arms of a public utility.

2. But more changes are needed to further the development of regional competitive wholesale electric markets and assure comparable and non-discriminatory treatment of all market participants. Accordingly, the following revisions must be made to the pro forma tariff to change the market rules in ways that will improve the efficiency of wholesale electric markets.

1. Capacity Benefit Margin

3. Capacity Benefit Margin is the set-aside of transmission capability by a transmission provider to ensure the ability to import external resources to meet generation reliability requirements or in case of a generation capacity deficiency. During the Commission's outreach process, many commenters asserted that Capacity Benefit Margin ties up valuable transfer capability without a specific reservation and payment by the customers who receive the benefit of the set-aside. The subsidy occurs because, while part of the transfer capability is withheld from the market as Capacity Benefit Margin, the wholesale transmission customers using the system pay the entire transmission cost (including that of the Capacity Benefit Margin) through their transmission charges, thus subsidizing the Capacity Benefit Margin beneficiaries. The use of a Capacity Benefit Margin has also been regularly challenged on the grounds that the host transmission provider is withholding transfer capability under the guise of Capacity Benefit Margin in order to thwart competition.

4. We propose to standardize the treatment of Capacity Benefit Margin to ensure that (1) only customers benefitting from it pay for it, and (2) transfer capability needed to access resources on a neighboring system is treated consistent with all other portions of the transmission grid. Thus, an Independent Transmission Provider itself would not be permitted to set aside transfer capability for generation reliability reasons. Rather, a load-serving entity wanting access to resources on a neighboring transmission system to meet its resource adequacy requirement should instead acquire Congestion Revenue Rights from the interface to its load to ensure that access. This will free up transfer capability now unavailable to wholesale transmission customers and prevent cross-subsidization of transmission customers that serve load within the Independent Transmission Provider's service area by point-to-point transmission system users.¹⁶0

5. This prohibition of the generic set-aside of transfer capability by the Independent Transmission Provider for generation reliability reasons does not apply to an Independent Transmission Provider's responsibility to set aside transfer capability to ensure transmission reliability (e.g., to ensure that a line can take up the power flows it must absorb if a parallel line should go out of service or other uncertainties in system conditions arise). Such a set-aside is called Transmission Reliability Margin and must be consistent with good utility practice and should not be implemented in a way that favors particular transmission customers (e.g., by release of the set-aside capability for use by native load).

2. Regional and Independent Calculation of Available Transfer Capability, Performance of Facilities Studies and OASIS

6. The Commission has found specific instances of abuse by transmission providers regarding the Available Transfer Capability calculation process and delays in the completion of transmission facilities studies.¹⁶1 There are obvious incentives for a vertically integrated transmission provider to favor its own generation by delaying facilities studies or manipulating the Available Transfer Capability calculations or postings on its OASIS. Under Standard Market Design, calculations of transmission capability and the performance of facilities studies for transmission expansions must be performed by an independent entity to reduce the opportunity for preferential treatment by the transmission provider.

7. More broadly, the SMD Tariff must recognize the regional nature of today's energy markets. Transmission capabilities must be calculated not for a single utility's service territory, but regionally to encompass existing trading patterns and power flows, particularly parallel path flows on neighboring systems. All transmission providers that are not part of a Commission-approved RTO must contract with an independent entity to perform transmission capability calculations on a regional basis. Likewise, we propose to require a common OASIS for the region.

3. Regional Planning Process

8. Competitive and reliable regional power markets require adequate transmission infrastructure to allow geographically broad supply choices and minimize the complications created by loop flow. The recent DOE National Grid Study documented the problems resulting from recent under-investment in transmission infrastructure and identified a number of causes. Among the causes were the lack of regional planning and coordination of transmission needs and siting issues.

9. Transmission planning and expansion have generally been performed for a single control area rather than on a regional basis. This yields sub-optimal solutions, as individual transmission providers consider power flows across a limited area and do not adequately consider entire markets. Parallel path flows that occur on neighboring systems may make the construction of specific facilities less cost-effective than a regional solution. This effect can be properly considered by performing transmission planning and expansion on a regional basis. Moreover, facilities that, if constructed in one system would be the optimal solution for a neighboring system, might never be considered under a single control area-based planning model.

10. Implementation of Standard Market Design will only increase the importance of examining these issues on a regional basis. More open and transparent markets will enable customers to purchase from distant suppliers, increasing use of the grid. Locational marginal prices that result from the spot markets operated by an Independent Transmission Provider would signal to all market participants the value of additional supply and demand response at particular locations. Based on these prices over time, market participants will be able to decide whether additional investment – in transmission or generation facilities or demand response – is warranted. The ability of individual market participants to see the economics of possible solutions and make market-driven decisions concerning the addition of infrastructure is the fundamental mechanism that induces efficient investment under Standard Market Design. The policy relies primarily on a "ground-up" planning process that encourages construction by private companies yet also recognizes the need for of a regional evaluation process for loop flow effects and cost-effectiveness It is neutral with respect to the type of investment market participants may make in response to these price signals. However, due to loop flow, all system modifications would need to be coordinated through a regional process and would have to meet any criteria needed to maintain reliability and stability, and assure that existing customer rights are not impaired.

11. Given the need for transmission investment in much of the country and the time it will take to implement Standard Market Design and for investors to observe and respond to price signals, we propose that a regional planning process be instituted within six months of the effective date of the Final Rule. This process should be designed to identify beneficial transmission needed for both reliability and economic reasons to support regional markets and reduce the effects of generation concentration. The regional planning process should allow the market to respond to those identified needs.

12. A critical piece of the transmission planning process is state-level siting decisions. We note a recent National Governors' Association report that recommends Multi-State Entities to facilitate regional transmission planning decisions.¹⁶2 Multi-State Entities, along with an open regional planning process, would preserve the states' role in siting decisions, while promoting regional solutions. A Multi-State Entity could be an important component of the regional planning process.

13. Certain areas of the country and organizations already have proposals or processes to consider regional planning or development of regional markets. Building off of these existing efforts will help facilitate the development of a regional planning process in the near term. We emphasize that a planning area need not coincide with the geographic area of a Commission-approved RTO or Independent Transmission Provider required by this rule. Also, because of the interrelationships between Canadian and US energy markets, we encourage participation by Canadian entities and provincial authorities in the regional planning process.

14. Current processes such as the Committee on Regional Electric Power Cooperation in the West provide for state and provincial advice in the planning across the entire Western grid. Therefore, we propose to use the area covered by Western Electricity Coordinating Council (WECC) that encompasses the geographic area covered by the Western Grid for regional planning purposes.

15. In the Eastern Interconnection there have been several efforts at developing regional wholesale electricity markets that we propose to build on for the regional planning process. PJM and MISO developed a Memorandum of Cooperation dated May 9, 2002 that commits to develop a joint and common wholesale electric market for PJM, MISO, and SPP. Consequently, we propose that the area covered by these organizations would also be a regional planning area.

16. Similarly, New York ISO and ISO-New England are currently pursuing discussions on the merger of these two organizations into a Northeast RTO. Both are also members of the Northeast Power Coordinating Council which has recently conducted studies of transmission needs in the region.¹⁶3 We propose to build on these efforts and use the area covered by these organizations as a planning area.

17. Finally, we recognize that there has been ongoing discussion development of regional markets in the Southeast. SETrans Regional Transmission Organization proposes to encompass a broad area in the Southeast. The Tennessee Valley Authority (TVA) has signed a Memorandum of Understanding with Southern Companies and Entergy, two sponsors of SETrans, to work together to develop coordination agreements. Additionally, the SETrans and GridSouth Transco, LLC parties signed a Memorandum of Understanding in January 2002 calling for similar regional coordination. Thus we propose to build on these efforts and propose a Southeast planning area composed of the Southeastern Electric Reliability Council and the Florida Reliability Coordinating Council.

18. We propose that all public utilities that own, control, or operate transmission facilities must participate in a regional planning process for the planning areas discussed above. We propose that this process start within six months after the effective date of the Final Rule and that the first regional transmission plan be completed within twelve months after the effective date of the Final Rule. Reliance on these existing regional efforts should facilitate the start-up of the regional planning process before Standard Market Design is implemented and all areas have Independent Transmission Providers operating transmission facilities.

19. After Standard Market Design is fully implemented, we believe the regional planning process will change as Independent Transmission Providers play a greater role in that process. There will still remain a significant need for a regional planning process to supplement private "ground up" investment decisions. The regional planning process is intended to supplement these private investment decisions, not supplant them. The regional planning process must provide a review of all proposed projects to assess whether the project would create loop flow issues that must be resolved on a regional basis. In addition, because of the externalities involved, there may be no private investment sponsor for some projects that would benefit the region. Private investment decisions in response to prices may not result in adequate expansions for two reasons. First, private parties may not be eligible to ask the state to exercise its eminent domain rights. Second, some needed and beneficial expansions may not create enough identifiable financial benefits to compensate private investors adequately, so those projects will not be built under a system that relies solely on private investment to expand the grid. A regional planning process can identify both the projects that would benefit the planning area and potential alternatives in a fair and unbiased manner. Additionally, a regional planning process, would evaluate the benefits of alternative proposals and provide an independent assessment of which projects are the most cost effective and/or have the least environmental impact.

20. To complement private investment initiatives, we propose that Independent Transmission Providers establish a mechanism for regional transmission planning and expansion guided by the following principles. First, the planning process should identify all expansion needs on the system, including both reliability and economic needs (e.g., to reduce congestion). The planning process should leave open the question of how and by whom those needs should be met, without favoring one solution (whether it is transmission, generation or demand response) over another. The planning process should be open to all industry segments. Additionally, all entities could propose projects. As long as the project did not make existing Congestion Revenue Rights infeasible due to loop flow problems, the entity would be free to complete the project as long as it is willing to assume any market or regulatory risk. However, to the extent the entity sought to roll-in the costs of the facilities, the rate treatment should be reviewed through the planning process.

21. Second, an Independent Transmission Provider should have the responsibility to issue requests for proposals when the planning process determines that additional resources are needed to serve the regional market. Parties may respond with proposals to expand the grid, add generation (including distributed generation), or implement demand response.¹⁶4 The Independent Transmission Provider would approve transmission expansions that would be paid for by all customers only when planned private investments are judged to be inadequate to meet the reliability and market needs of the region. If the bidding process fails to produce a satisfactory outcome, such that the Independent Transmission Provider determines that additional facilities are needed, the affected transmission owner(s) would be required to expand or upgrade the transmission system.¹⁶5

22. Finally, the Independent Transmission Provider would act as a clearinghouse for proposed projects. It could identify separate projects that could be constructed at a lower cost if the projects were combined. Also, if there are alternative projects that have been proposed, the Independent Transmission Provider could evaluate the relative advantages of the alternative projects.

23. This approach to regional planning and expansion is fully consistent with Standard Market Design's goal of inducing efficient investment by relying primarily on price signals and independently administered Congestion Revenue Rights. At the same time, it recognizes that private investment decisions may not be fully adequate in all cases because of eminent domain and the possibility that private benefits of investment could be significantly less than social benefits. The planning process would have a regional scope, permit direct competition among all types of investment, include all market participants equally, and minimize the need to rely on eminent domain and the support of captive customers. Because existing transmission owners are the transmission builder of last resort, it also respects the reality that not all states allow non-traditional utilities to build in their state or to obtain eminent domain, thus creating a legal barrier to entry.

5. Transmission Facilities That Must be Under the Control

of an Independent Transmission Provider

24. In a variety of public forums, including RTO conferences and comments to RTO proceedings, much uncertainty has been expressed concerning two questions: which facilities belong under the control of the RTO; and which customer-owned transmission facilities that are turned over to RTO control are entitled to a credit?¹⁶7 In some instances, the dispute centers on whether the facilities are integrated. Other disputes involve the voltage level at which a facility is determined to be transmission. Under this proposed rule, the question becomes which transmission facilities must be under the control or an Independent Transmission Provider, be it an RTO or not.

a. Before Order No. 888

25. Before Order No. 888, much of the industry consisted of vertically integrated investor-owned utilities (IOUs) that, for the most part, provided a single service – bundled requirements power – to retail and wholesale customers alike. The classification of delivery facilities between transmission and distribution came up only in a ratemaking context. Because wholesale requirements customers purchased bulk power, they often did not require service over distribution facilities. Often, only a stepdown substation or a feeder line was involved. For those few stand-alone transmission services that an IOU might provide, the cost allocation issue was the same. The Commission approached this allocation issue by defining an integrated transmission grid as those facilities that operate in a single cohesive fashion to deliver bulk power and allocating wholesale (and stand-alone transmission customers) a proportional share of the embedded costs of those facilities on a rolled-in basis with postage stamp pricing.

26. Infrequently, the Commission would consider rate treatments premised on the distinction between transmission and subtransmission (high and low voltage transmission). If there were delivery facilities (transmission or distribution) that were not part of the integrated grid, but were used by a specific wholesale customer (e.g., radial tap line or stepdown substation), the Commission would allow the direct assignment of those facility costs in wholesale rates.

27. These issues were discussed at length in Commission cases in the 1970s when IOUs attempted to bifurcate the pricing (effectively pancaking) and thereby increase their wholesale revenues. Customers, on the other hand, wanted to classify facilities as transmission and thereby decrease their delivered energy charges by only paying one charge for these facilities. While the issue was often framed as a transmission/distribution issue, it was mostly a battle over utilities trying to pancake rates (through charging a rolled-in rate plus a direct assignment charge) for transmission facilities or facilities that provided both transmission and distribution functions (dual-function facilities).

b. Order No. 888

28. Order No. 888 did not require a change in traditional rate treatments. However, since the Commission issued its open access rules, a number of utilities have proposed subclassifications of transmission, e.g., transmission and subtransmission. Protestors (generally transmission-dependent utilities) have argued that this rate treatment favors transmission users that are connected to the transmission system at higher voltages (i.e., the transmission owners' own generation) by reducing their rates for open access transmission service (because they pay only the high-voltage charge) and that reclassification is just another way to pancake rates and increase charges to low-voltage users. During the Commission's public outreach, commenters pointed to such splits as the pool transmission facilities (PTF)/non-pool transmission facilities in ISO New England as an example. This is not a consistent classification of pool transmission facilities and non-pool transmission facilities among transmission owners in New England. A generator located on a lower voltage portion of the ISO's grid must pay an additional non-PTF charge to access the New England market, but other, generators do not, putting the first generator at a competitive disadvantage.

29. The issue of transmission/distribution classification in Order No. 888 was in the context of unbundled retail transmission service and the Federal Power Act's legal jurisdiction distinction between "transmission" facilities (subject to Commission jurisdiction) and "local distribution" facilities (subject to state or local jurisdiction). To determine what facilities would be under Commission jurisdiction for purposes of the Order No. 888 open access requirements and what facilities would remain subject to state jurisdiction for purposes of retail stranded cost adders or other retail regulatory purposes, the Commission developed a seven factor test to determine what facilities are transmission facilities and what facilities are local distribution facilities.¹⁶8 With respect to the seven factor test, the Commission also stated that it would defer to the state commission’s findings as to what facilities constitute local distribution facilities if the state's determination was consistent with our comparability principles. In addition, dual purpose facilities, i.e., those used both for transmission or wholesale sales and for local distribution, would fall under the Commission's jurisdiction. To the extent use of particular facilities changed over time, the Commission would revisit these determinations. The Supreme Court upheld these determinations upon appellate review.¹⁶9

c. Test for Transmission Facilities

30. Order No. 888's seven factor test was designed to determine the local distribution component of an unbundled retail sale. The test did not exist prior to Order No. 888 and in fact was created to do something the Commission had never done before – identify local (retail) distribution facilities. Thus, the test identifies all facilities that are not local distribution facilities. We propose that this is the appropriate starting point for determining which facilities belong under the control of an Independent Transmission Provider. To the extent that a transmission owner or Independent Transmission Provider believes that certain facilities should not be under the Independent Transmission Provider's control, the Independent Transmission Provider may request an exception to this presumptive determination.

31. This proposed test focuses on the presumption that, if a facility is transmission, it belongs under the control of the Independent Transmission Provider. Thus, once a determination is made with the seven factor test, there would be no need for an additional review under the Commission's previous integrated facilities test. In MidAmerican Energy Company,¹⁷0 the Commission explained that the Commission's determination of which facilities are transmission is fluid and dependent on actual the use of the facilities:

Although we are accepting the state commissions' classification, we reiterate our finding in Order No. 888 that to the extent that any facilities, regardless of their original nominal classification, in fact, prove to be used by public utilities to provide transmission service in interstate commerce in order to deliver power and energy to wholesale purchasers, such facilities become subject to this Commission's jurisdiction and review.¹⁷1 In addition, the rates, terms and conditions of all wholesale and unbundled retail transmission service provided by public utilities in interstate commerce are subject to this Commission's jurisdiction and review.¹⁷2

Further, our deference in this proceeding does not affect the Commission's separate determination of what facilities must be under the operational control of RTOs, including ISOs and Transcos.¹⁷3 The Commission will make this latter determination, taking into account the seven factors formulated for purposes of determining jurisdiction as set forth in Order No. 888,¹⁷4 the ISO principles set forth in Order No. 888,¹⁷5 and the principles set forth in the RTO Final Rule.¹⁷6

We note that the determination of which facilities are under the operational control of the Independent Transmission Provider does not dictate transmission pricing.¹⁷7

We request comment whether, either in addition to or in lieu of the seven factor test, the Commission should use a bright line voltage test (e.g., 69 kV) to determine which facilities are placed under the control of the Independent Transmission Provider. If so, we seek comment on the bright line, whether we should allow regional variation, and how transmission facilities that are not placed under the control of the Independent Transmission Provider's tariff are treated with respect to open access and rates.

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1⁶⁰To the extent that an Independent Transmission Provider’s load ratio share access charge calculation does not pick up this reservation, the amount of interface capability can be imputed and added to the customer’s peak day amount.

1⁶¹See Section III and Appendix C.

1⁶²See Interstate Strategies for Transmission Planning and Expansion, National Governors' Association, posted on July 18, 2002, available in <http://www.nga.org/center/divisions/1,1188,C_ISSUE_BRIEF^D_4110,0.html>.

1⁶³Northeast Power Coordinating Council Collaborative Planning Initiative Phase I issued March 13, 2002.

1⁶⁴We recognize that the states have the ultimate authority over siting.

1⁶⁵See existing pro forma tariff §§ 13.5 and 15.4 (transmission provider required to expand its transmission system if transmission customer agrees to compensate the transmission provider). This requirement extends to the transmission owners. 

1⁶⁷See, e.g., City of Vernon, California, 93 FERC ¶ 61,103 (2000), 94 FERC ¶ 61,344 and 61,148 (2001); 95 FERC ¶ 61,274 (2001); and 96 FERC ¶ 61,312 (2001).

1⁶⁸ Order 888 at 31,771.

1⁶⁹ New York v. FERC, 122 S. Ct. 1012.

1⁷⁰90 FERC ¶ 61,105 (2000).

1⁷¹In Order No. 888, the Commission explained that "a public utility's facilities used to deliver electric energy to a wholesale purchaser, whether labeled "transmission," "distribution," or "local distribution," are subject to the Commission's exclusive jurisdiction under sections 205 and 206 of the FPA." Order No. 888 at 31,969; accord Nevada Power Company, 88 FERC ¶ 61,234 at 61,768 (1999).

1⁷²Transmission service in interstate commerce by public utilities, including the rates, terms and conditions for such service, remains within this Commission's exclusive jurisdiction. 16 U.S.C. 824, 824d, 824e (1994). See generally Order No. 888_A at 30,339_41.

1⁷³Which facilities will or will not be under an RTO's operational control also does not predetermine transmission pricing, cost allocation, or rate design determinations at either a state commission or at this Commission.

1⁷⁴Order No. 888 at 31,771.

1⁷⁵Order No. 888 at 31,730_32.

1⁷⁶Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ¶ (1999) (RTO Final Rule).

1⁷⁷As noted in MidAmerican, present ISO agreements obligate transmission owners to provide access over facilities that are not under the control of the ISO if those facilities are needed to provide wholesale transmission service regardless of ownership or whether those facilities are labeled transmission, distribution (i.e., distribution facilities other than local distribution), or local distribution. The same holds for Independent Transmission Providers.