SYNOPSIS
§ 1.01 Introduction
§ 1.02 Background – How Did FERC Get Here?
[1] The Energy Policy Act of 1992
[2] FERC Order No. 888
§ 1.03 FERC's Order No. 2000 - The Framework for RTO Development
[1] The Four Minimum Characteristics of an RTO
[a] RTO Characteristic No. 1 – Independence
[b] RTO Characteristic No. 2 – Scope and Regional Configuration
[c] RTO Characteristic No. 3 – Operational Authority
[d] RTO Characteristic No. 4 – Short-Term Reliability
[2] The Eight Minimum Functions of an RTO
§ 1.04 The Standard Market Design (SMD) Notice of Proposed Rulemaking
§ 1.05 FERC's RTO Orders
[1] The Midwest Independent System Operator (MISO) RTO
[2] PJM Interconnection RTO
[3] FERC's Recent Western RTO Orders: Signs of Flexibility and a Convergence with the SMD Proposal
[4] Other RTO Issues
[a] Governance
[b] Seams
[c] Pricing of Transmission Service
[d] Funding of Transmission Expansions: Who Pays?
[e] Inclusion of Non-Jurisdictional Entities and State Regulators
[f] Scope and Configuration
[g] New York and New England: Where Do They Go?
§ 1.06 Summary and Conclusion
§ 1.01 Introduction
This article is an attempt to provide an overview of the activities of the Federal Energy Regulatory Commission (FERC) relating to a standard design for electricity markets and the formation of regional transmission organizations.[1] It begins with a brief discussion of developments leading up to these activities, including the passage by Congress in 1992 of the Energy Policy Act and the 1996 issuance by FERC of Order No. 888. Next, there is a discussion of FERC's Order No. 2000, which provided a framework for the development of regional transmission organizations. The article concludes with summaries of FERC's orders approving, and conditionally approving, various applications across the country to form regional transmission organizations.
§ 1.02 Background – How Did FERC Get Here?
[1] The Energy Policy Act of 1992
FERC's current activities relating to Standard Market Design and RTOs can be traced back to the passage of the Energy Policy Act (EPAct) of 1992.[2] Congress passed this legislation in an effort to encourage the further development of the nascent national wholesale electricity market originally created, in part, by 1978's Public Utility Regulatory Policies Act (PURPA)[3]. While PURPA provided the impetus for the original development of independent, competitive wholesale power generators, EPAct provided the catalyst for the rapid development of merchant generators in the late 1990s and early 2000s.
Specifically, EPAct aimed to eliminate two constraints that had been identified as impediments to the development of a competitive wholesale electric market: (1) discriminatory conduct by transmission-owners in granting competitive generators access to transmission facilities, and (2) the ownership restrictions of the Public Utility Holding Company Act (PUHCA)[4]. To accomplish this, EPAct contained two key components. First, the legislation granted FERC explicit authority to order utilities that own transmission facilities to transmit, or "wheel," wholesale power.[5] Second, the law eliminated PUHCA ownership restraints by allowing entities "engaged exclusively in the business of selling energy at wholesale" to obtain exempt wholesale generator (EWG) status, exempting them from PUHCA restrictions.[6]
FERC utilized the transmission authority contained in EPAct aggressively following its passage. In nearly all the cases entertained by the Commission between 1993 and 1996, the Commission ordered the provision of wholesale transmission.[7]
[2] FERC Order No. 888
Ending the case-by-case use of its EPAct authority to order transmission-owning entities to wheel wholesale power, FERC promulgated an all-encompassing open-access rule, Order No. 888, in 1996.[8] The rule, applicable to all public utilities that own, control, or operate facilities used for transmitting electric energy in interstate commerce, was adopted by the Commission to "remedy undue discrimination in transmission services in interstate commerce and provide an orderly and fair transition to competitive bulk power markets."[9]
Specifically, the rule required all public utilities owning, controlling or operating transmission facilities to file with FERC an open-access transmission tariff (OATT) setting forth the terms and conditions of non-discriminatory transmission service. Those terms were required to contain, at a minimum, the terms proposed by FERC in the pro-forma OATT included in Order No. 888. The order also required public utilities to unbundle the transmission service function from generation and power marketing functions, and to sell each of these services separately under their OATT.[10] Additionally, the rule required public utilities owning transmission and also serving retail load to take transmission service for all of its sales and purchases of energy under the terms of their filed OATT, just as any other transmission customer would.
Two other aspects of Order No. 888 must be noted. First, FERC used this order to clarify what it believed to be the extent of its power under EPAct to order public utilities to provide transmission service. Traditionally, and under the FPA, the line between federal jurisdiction and state jurisdiction over transmission was drawn between wholesale and retail transactions: federal jurisdiction applied to wholesale, interstate transmissions of electricity, while state jurisdiction applied to retail electricity transactions. In Order No. 888, FERC concluded, under the FPA and EPAct, that it has authority over the rates, terms and conditions of transmission in interstate commerce of electricity, including transmission of electricity destined for sale at retail.[11] As a result, it applied the open-access requirements of Order No. 888 to the transmission in interstate commerce of electricity to be sold at retail.[12] The rule did not apply to bundled retail sales of electricity. Several parties sought appeal of these conclusions in the courts. In New York et al. v. FERC, the United States Supreme Court upheld FERC's determinations as to the extent of its authority over transmission.[13]
Finally, Order No. 888 expressed FERC's desire that utilities reorganize and place the control of their transmission facilities under independent system operators ("ISOs"). ISOs are "independent, third-party operators of regional transmission systems."[14] FERC proposed the ISO structure to "offer assurance to customers of transmission that access is truly nondiscriminatory."[15] FERC did not require utilities to join ISOs; rather, it encouraged utilities to explore the ISO model as a means to ensure that their provision of transmission service would meet the non-discriminatory, open-access requirements of Order No. 888.[16] Since ISOs, if formed, would be public utilities subject to FERC jurisdiction, Order No. 888 also included 11 "ISO Principles" that the Commission would require an ISO to satisfy before the agency would grant it approval to operate.[17]
§ 1.03 FERC's Order No. 2000 - The Framework for RTO Development
Order No. 888, according to FERC, "fostered a rapid growth in dependence on wholesale markets for acquisition of generation resources."[18] While encouraged by this further development of the competitive wholesale electricity market, and the establishment of ISOs in some regions, the Commission still found inequities in the provision of wholesale electricity transmission service.[19] Additionally, the Commission found that the increased prevalence of the wholesale market, and of wholesale generators, had placed new strains on the nation's transmission networks.[20] Finally, the Commission expressed concern that only five ISOs had been proposed and granted approval or conditional approval by the agency.[21]
Based on these developments, and the concerns noted above, FERC issued Order No. 2000 early in the year 2000.[22] Principally, this rule establishes the requirements for forming Regional Transmission Organizations ("RTOs"). RTOs are transmission controlling-entities that operate all of the transmission facilities within a given region, similar to ISOs. While the rule does not require that utilities join RTOs, it strongly encourages them to do so, and requires transmission-owners not joining RTOs to make a filing with the Commission explaining their decision. FERC believed that "appropriate RTOs could successfully address the existing impediments to efficient grid operation and competition.[23]
What makes RTOs different from ISOs, at least under the terms of Order No. 2000, is that these new entities may utilize more flexible governance and business structures. While the five ISOs approved by FERC under Order No. 888 were not-for-profit entities, Order No. 2000 expressly declined to "propose to require or prohibit any one form of organization for RTOs."[24] The rule requires that before any RTO will be approved by the Commission, it must prove that it has four prescribed characteristics and will be equipped to carry out eight prescribed functions. These characteristics have framed the Commission's analysis of RTO proposals and are explained in more detail below. In Order No. 2000, the Commission has also expressly adopted an open architecture policy regarding the governance structure of RTOs, to allow for flexibility and rapid changes in scope and operations should market conditions necessitate them.[25]
[1] The Four Minimum Characteristics of an RTO
[a] RTO Characteristic No. 1 – Independence
Order No. 2000 requires, first and foremost, that all RTOs be independent of market participants.[26] To satisfy this independence requirement, the rules require that RTO proponents make three demonstrations that: (1) the RTO, its employees, and "any non-stakeholder directors" have no financial interest in any market participant, (2) the RTO has a decision-making process that is independent of any control by market participants, either individually or as a class, and (3) the RTO has "exclusive and independent authority" under the Federal Power Act to propose rates, terms and conditions of transmission service for the transmission facilities under its control.[27] The regulations also require that if a market participant will have an ownership stake in the RTO, or will play a role in the RTO's decision-making process, a compliance audit be conducted to assess the independent of the RTO.[28]
[b] RTO Characteristic No. 2 – Scope and Regional Configuration
Order No. 2000 provides:
The [RTO] must serve an appropriate region. The region must be of sufficient scope and configuration to permit the [RTO] to maintain reliability, effectively perform its required functions, and support efficient and non-discriminatory power markets.[29]
In Order No. 2000, the Commission expressly declined to prescribe initial boundaries for RTOs, leaving it to the transmission owners and market participants in individual regions to propose appropriate boundaries.[30] The final rule's preamble does, however, identify "factors that affect appropriate regional configuration."[31] Those factors are related to both the size of an RTO and its exact boundaries, and include such things as whether the proposed size and boundaries will help facilitate the performance of RTO functions, will allow for transmission at non-pancaked rates, and will recognize existing regional boundaries, institutions and trading patterns.[32]
[c] RTO Characteristic No. 3 – Operational Authority
Order No. 2000 additionally requires that an RTO have "operational authority" over all transmission facilities under its control. Specifically, the regulations require that two items be demonstrated to meet this characteristic: (1) if operational functions are delegated to or shared with entities other than the RTO, the RTO must ensure such an arrangement will not impair reliability or give any market participant a competitive advantage, and must also prepare a report regarding these matters within two years after initial operation, and (2) the RTO must be the security coordinator for the transmission facilities it controls.[33]
[d] RTO Characteristic No. 4 – Short-Term Reliability
Finally, Order No. 2000 requires that an RTO have "exclusive authority for maintaining the short-term reliability of the grid that it operates."[34] To satisfy this final characteristic, the rule requires that a proposed RTO make four demonstrations that: (1) it has "exclusive authority for receiving, confirming and implementing all interchange schedules," (2) it has the right order redispatch of generation resources to ensure reliable operation of the grid, (3) it has the authority to approve or disapprove of any scheduled outages of transmission facilities, and (4) it will report to FERC if any regional reliability standards established by another organization "hinder it from providing reliable, non-discriminatory and efficiently proved transmission service."[35]
[2] The Eight Minimum Functions of an RTO
Order No. 2000 also specifies eight minimum functions that an RTO must provide in order to be approved by the Commission. Those functions are:
(1) Tariff Administration and Design. An RTO must control its own transmission tariff, employ its own pricing system, and be the sole provider of transmission service within its control area.[36]
(2) Congestion Management. RTOs are required to develop and operate congestion management mechanisms.[37]
(3) Parallel Path Flow. RTOs must develop procedures to address parallel path flow issues within their area of operation, and to coordinate parallel path flow with other regions.[38]
(4) Ancillary Services. An RTO must serve as "provider of last resort" for all ancillary services.[39] Market participants are given the opportunity to self-supply these services, or acquire them from a third person.[40]
(5) OASIS and Total Transmission Capability ("TTC") and Available Transmission Capability ("ATC"). RTOs must be the sole OASIS site administrator, and must be the sole calculator of TTC and ATC.[41]
(6) Market Monitoring. An RTO must establish procedures for objective monitoring of all energy markets it operates or administers "to identify market design flaws, market power abuses and opportunities for efficiency improvements."[42]
(7) Planning and Expansion. RTOs "must be responsible for planning, and for directing or arranging, necessary transmission expansions, additions, and upgrades."[43]
(8) Interregional Coordination. RTOs are also responsible for ensuring that reliability practices and interconnections are coordinated among regions, and that seams issues between regions will be adequately addresses.[44]
FERC's orders that have approved or given conditional approval to RTO proposals also give significant attention to these functions.
§ 1.04 The Standard Market Design ("SMD") Notice of Proposed Rulemaking
The 2000-2001 electricity-market meltdown in California, and the general supply-shortage in the Western U.S., came upon the Commission as it was beginning the process of reviewing RTO proposals. Additionally, even after Order Nos. 888 and 2000, the Commission believed that there continued to be discrimination in the provision of transmission service that was blocking access to the grid by competitive generators. As a result, the Commission issued a proposed rule seeking to establish a single, standard market design for all power markets in the country. Known as the "SMD Rule," FERC intends that the new regulations created by the rule eliminate any remaining discrimination in the provision of transmission service, eliminate other barriers to effective wholesale competition, relieve congestion management problems, and curb market abuses.[45]
The NOPR contains several important mechanisms designed to implement a single set of rules governing electricity markets in all regions of the country. One of the most significant and controversial aspects of the proposal is that it would require the transmission component of bundled retail load to be taken under the OATT, just as unbundled retail transmission was required to be taken under the OATT in Order No. 888.[46] State regulators have expressed their objection to this provision, arguing that it usurps their authority over rates and provision of service for retail electricity sales.
The driving force behind FERC's vision of SMD appears to be the proposed rule's requirement that all transmission activities be performed by an Independent Transmission Provider (ITP).[47] The draft regulations require that in order to be designated an ITP, the provider must be "independent," which is further defined in the regulations to mean that the ITP "has no financial interest, either directly or through an affiliate, . . . in any market participant in the region in which it provides transmission services or in neighboring regions."[48] If implemented, the SMD rule would mandate that public utilities owning, operating, or controlling transmission facilities must do one of three things: (1) prove that they meet the ITP definition, (2) turn over the operation of their transmission system to an RTO that meets the definition of an ITP, or (3) contract with another entity that meets the definition of an ITP to operate their transmission facilities.[49] The ITP (or RTO meeting the definition of an ITP) must then file a tariff conforming with the SMD pro forma OATT, and offer service under that tariff.
Under the provisions of the pro forma OATT in the proposed rule, ITPs would offer only one form of transmission service, called "Network Access Service" (NAS).[50] This single type of transmission service replaces the two types of transmission service that were offered to different classes of customers under Order No. 888's OATT, Network Integration Service and Point-to-Point Transmission Service. Essentially, NAS is a combination of these two previously offered systems because NAS contains both the flexibility found in Network Integration Service in designating load, and the reassignability of transmission rights contained in Point-to-Point Service. FERC believes that this single transmission service offering will offer more certainty to transmission customers with regard to price and availability.
Under SMD, transmission service pricing would change significantly. The NOPR proposes that an access charge for transmission service be assessed against mostly load-serving entities, to allow transmission-owners to recover the fixed cost of the transmission system.[51] That access charge could either be a "license plate rate" (charge based on point of delivery within system) or a "postage stamp rate" (same charge anywhere in the system), and would be based proportionally on the load-serving entities' share of the system's total peak load.[52] In return for the payment of the access charge, the market participants would receive congestion revenue rights, discussed below. Additionally, in an effort to eliminate rate-pancaking when transmission service is taken across multiple systems, FERC's proposed rule would require that a customer purchasing transmission of electricity beginning in one ITP region and ending in another be charged only the access charge of the ITP system where the electricity is delivered to load.[53] FERC states that this proposal would allow for broader areas of competition because it would eliminate the multiple access charges that currently plague long-distance transmission of electricity supply. In the NOPR, FERC has sought comments from interested parties on whether to continue to allow "license plate rates" after a transitional period, or whether to require "postage stamp rates" for all ITP service areas.[54]
The ITP would perform several functions under the SMD rule as it is proposed. Probably the most notable ITP function, given recent events in the wholesale power markets of the West, is the establishment and operation of certain energy markets. Under the rule, ITPs would operate real-time energy markets, taking bids to buy and sell power in each hour.[55] Additionally, ITPs would be required to have within their structure a market-monitoring unit.[56] Such a unit would be required to be independent of the ITP's management and would report and be accountable directly to FERC.[57] The market-monitoring unit, under the draft regulations, would monitor all markets operated by the ITP for "exercises of market power, flaws in . . . tariff rules or operations that contribute to economic inefficiency, and market participants' compliance with the [ITP's] tariff."[58]
The NOPR would also make the ITP responsible for congestion management. Primarily, FERC's proposal would require ITPs to manage congestion through the use of locational-marginal pricing ("LMP") and congestion revenue rights ("CRRs").[59] LMP, currently in use in the PJM ISO, establishes separate prices for energy during times of congestion at each area on the transmission grid, and separate prices for the transmission of such energy, based on the marginal costs of producing the energy and delivering it to the requested location.[60] LMP is intended to operate to reflect the costs of congestion and mitigate it through market-price signals. CRRs, in turn, are offered by the ITP for purchase by a transmission customer ahead of time to allow them to be assured of a delivery price and to avoid congestion costs, regardless of system conditions.[61] ITPs would be required by the SMD rule to offer several types of CRRs with various terms. FERC states in the rule a desire that "an active secondary market" for CRRs be developed to allow market participants an opportunity to acquire such rights.[62] Under the congestion management system laid out by LMP and CRR, a transmission customer could either pay the higher LMP rate if it wants to deliver power through a constrained area at a particular time, or it could utilize CRRs to ensure itself a more certain cost for transmission service regardless of market conditions.
The SMD NOPR also proposes changes to the assignment of costs for transmission system expansions. In the past, the Commission has favored the use of "rolled-in pricing" for transmission system upgrades, in which all users pay a share of the new facilities.[63] FERC notes in the NOPR that it has preferred this policy under the "rationale that the transmission grid is a single piece of equipment such that system expansions are used by and benefit all users due to the integrated nature of the grid."[64] This rationale does not hold, however, when a transmission upgrade is intended to allow a particular generator to reach a more distant, and often out-of-state market, because in that case state interests responsible for the siting of transmission "have no interest in siting a line that benefits a particular generator or a distant load in another state because to do so would require the load on the constructing public utility's system to pay for the new facilities."[65] As a result, the Commission expressly states in the proposed rule that it would prefer the use of "participant funding," whereby the entity who benefits from the upgrade also pays for its costs.[66] The proposed rule seems to leave the ultimate decision up to ITPs, however, to determine based upon the perceived needs in their region and the benefits attached to a particular expansion project, subject to Commission approval. In the interim, the rule would implement rolled-in pricing on a regional basis as a default.[67] The rule would also encourage the development of Regional State Advisory Committees ("RSACs") to facilitate collaboration between states on transmission system expansion projects.[68]
A final aspect of the proposed rule is its resource adequacy requirements. The draft rule proposes a minimum, nationwide 12 percent reserve margin.[69] ITPs would be required under the rule to maintain at least that margin and to forecast future demand in the areas they serve. ITPs would then allocate a percentage of the reserve margin to each load-serving entity in their service area, and that entity would be responsible for procuring the capacity to meet the reserve margin in any of a number of ways, including self-generation or purchase from other generators.[70]
The rule contains several other proposals not summarized herein. State leaders in many areas reacted negatively to FERC's proposal, fearing that its provisions would usurp their authority and shift costs from other regions to their own.[71] While state leaders were not uniform in their outcry of concern to the SMD NOPR, the opposition of many states, especially in the South, was unprecedented.[72] As discussed further below, one could argue that FERC's most recent RTO orders have reflected an awareness of, and attempt to respond to, these state concerns.
§ 1.05 FERC's RTO Orders
Since the Commission finalized Order No. 2000, several RTO proposals have been submitted to it for approval. In early 2003, RTOs are proposed, conditionally-approved, or have been approved for almost the entire country. The exception is the Northeast, where New England and New York have stalled on various proposals to form an RTO in that transmission-constrained region. Should all the proposed and conditionally approved RTOs reach full operation, a much greater percentage of the national transmission system will be under an independent grid-operating organization than was under Order No. 888.
To date, two RTO's have been fully approved by FERC; the Midwest Independent System Operator, Inc. (MISO), covering a large swath of the Midwest, and the PJM Interconnection, covering portions of the Midwest and Middle Atlantic regions. Several other RTO's have received conditional approvals from FERC. They include RTO West, covering the Northwest; WestConnect, in the Southwest; and SeTrans, in the Southeast. Other proposed RTOs are in the planning stages. The map below, created by FERC staff, shows the current layout of approved, conditionally approved, and proposed RTOs:
FERC's orders in several of the RTO cases it has considered have provided guidance on its current thinking regarding the development of these organizations. The Commission, since the issuance of Order No. 2000, has developed an approach in which RTO proposals come to the Commission for interim approvals. Those approvals are either granted or denied, but in either case, the RTO's developers are often given further guidance on how to proceed toward final Commission approval.
[1] The Midwest Independent System Operator (MISO) RTO
MISO became the first officially-approved RTO when FERC issued its final order on December 20, 2001.[73] Significantly, the order chose MISO over a competing proposal, the Alliance RTO. The two proposals, which at first competed to be the lone RTO in the region, had worked out some issues in an attempt to work together as approved RTOs in the Midwest. In the final order, FERC found that the MISO proposal "most fully complied with the vision and requirements of Order No. 2000, in particular the requirement that an RTO be of sufficient scope."[74] Concerns over the scope of the Alliance proposal, seams issues between the two RTOs, and the "overwhelming" opinion of the Midwestern state commissions that MISO be the single RTO in the region, led FERC to its final decision.[75]
MISO meets the Commission's independence requirements in several ways. Its governance structure is largely the same as it was when it existed as an ISO under Order No. 888. The RTO is governed by a board elected by the membership of the ISO from a group of candidates selected by an independent search firm.[76] MISO board members have not served as directors, officers or employees of any market participant in two years prior to their tenure with the ISO, and may not do so for two years following.[77] The board has "independent decision-making authority with respect to strategic and operational matters," and has the independent right to amend the MISO tariff.[78] Also, MISO has the independent authority to seek recovery of its own costs, subject only to Commission-approval.[79]
The Commission's decision to approve MISO as the single RTO for the Midwest, and reject the proposal of the Alliance RTO, was essentially an exercise relating to the scope and configuration characteristic. At the time, MISO's proposal contained over 62,000 miles of transmission lines in 20 states and one Canadian province.[80] Additionally, MISO was in the beginning stages of a plan to merge with the Southwest Power Pool (SPP) and had received applications from several other utilities seeking to join it. Its large scope seemed preferable to the Commission.[81]
With regard to operational authority and short-term reliability (RTO characteristics 3 and 4), MISO meets these requirements because it has "functional control" of all transmission facilities in its control area, meaning that it operates the transmission system, schedules transmission service, and administers the tariff in the region.[82] MISO also serves as the security coordinator for all transmission systems under its functional control and coordinates emergency planning.[83] Finally, MISO "has the exclusive authority to receive, confirm, and implement all interchange schedules and . . . the authority to order redispatch of any generator connected to transmission facilities it operates if necessary for the reliable operation of these facilities," giving it control over short-term reliability in its region.[84]
MISO also satisfies the Commission's eight minimum RTO functions in several areas. For example, MISO is the sole administrator of its FERC-approved transmission tariff and has exclusive authority to consider and approve or deny all transmission service requests, satisfying the tariff administration and design function.[85] The MISO proposal contained provisions allowing transmission owners to exercise certain veto rights with regard to tariff administration, but FERC ordered that those provisions be removed.[86] MISO also controls congestion management (function number 2), is of sufficient scope and configuration to adequately address parallel path flow issues (function number 3), serves as the provider of last resort for ancillary services (function number 4), will be the single OASIS administrator for all transmission facilities under its control, and will perform independent calculations of TTC and ATC (function number 5).[87]
MISO has an advanced market monitoring operation, satisfying minimum function number 6. An independent contractor performs market monitoring functions within MISO. Under MISO's market monitoring scheme, an Independent Market Monitor (IMM) surveys the conduct of market participants, transmission owners, and the participating RTOs to detect exercises of market power or attempts to "reduce the quantity or quality of transmission service in the region." FERC approved of the fact that the IMM may report its findings directly to the Commission.[88]
MISO has expanded since FERC's order officially granting it the RTO designation. Its scope has grown to over 100,000 miles of transmission lines.[89] Many of the companies within MISO have sold their transmission facilities to independent transmission companies, who have then committed to cede operational authority to the Midwest ISO. The proposed merger of MISO with SPP has continued forward, and FERC recently gave conditional approval to a joint filing by the two entities to offer transmission services under a single transmission tariff.[90] Additionally, MISO, SPP and PJM are seeking to establish a single, common market out of the three groups' areas of control.[91] Should that market be become a reality, a power plant in Eastern New Mexico could deliver power, for one price, to a utility serving Manhattan.
[2] PJM Interconnection RTO
On December 20, 2002, FERC granted RTO status to PJM Interconnection.[92] FERC's order was actually an order on rehearing of its July 12, 2001 order granting PJM provisional RTO status.[93] Due to changed circumstances regarding seams issues between the three Northeastern ISOs, and a significantly increased scope, FERC moved PJM from provisional status to an officially approved RTO.
Similar to MISO, PJM was also previously an ISO under Order No. 888. Under this structure, PJM's board and employees may have no financial interest in or affiliation with any market participant, and PJM itself owns no generation or transmission facilities.[94] The PJM governing board is a "non-stakeholder" board, meaning it contains no market participants. The board has independent authority to amend its tariff, has exclusive authority to seek recovery of its own costs, and has authority to file rate changes for recovery of its own costs.[95] These characteristics of the entity led FERC to proclaim that it meets the independence requirements of Order No. 2000, because it was "founded on independence from market participants." [96]
Also in similar fashion to MISO, the major difficulty in PJM's achievement of RTO status was its satisfaction of the scope and configuration characteristic. As originally proposed, PJM members covered five states and the District of Columbia and contained 8,000 miles of transmission lines. In its order granting conditional RTO status, FERC expressed concern over the prospect of three RTOs in the Northeast. The Commission found that "the existence of three separate ISOs in the Northeast . . . has resulted in a balkanized market that does not encourage trade across seams or increase efficiencies," and that for these reasons it would "not permit three RTOs in the Northeast."[97] While PJM's scope and configuration were provisionally adequate, the Commission concluded that it represented "only a first step, a platform which must be built upon."[98] In its order granting PJM full RTO status, the Commission stated that its concerns regarding seams problems between PJM and the New York and New England ISOs had been satisfied, due to the recent approval of a market design proposal for ISO New England which contained market rules tracking PJM's market rules.[99] Also, the Commission noted that PJM had enlarged its overall scope, adding utility members to its west and south.[100]
PJM has operational authority over all transmission facilities it controls, schedules all transmission service across those facilities, and is the security coordinator for the entire region, satisfying the operational authority characteristic.[101] Additionally, PJM directs all actions in its control area through a central control area, which provides operating instructions to local control centers which are operated by PJM's utility members.[102] Order No. 2000's operational authority characteristic permits this arrangement. PJM monitors nearly all activities on its grid, and only certain low voltage facilities are not monitored by the RTO. This central control structure also allows PJM to exercise several reliability functions, in satisfaction of the short-term reliability characteristic in Order No. 2000.[103]
PJM satisfies the eight minimum functions as well. PJM alone administers its transmission tariff, in satisfaction of the first minimum function.[104] With regard to this function, however, PJM's original proposal allowed transmission owners to conduct feasibility and system impact studies for new interconnections, and only transmission owners could sign interconnection requests. FERC was concerned with this arrangement, fearing that transmission owners could "exercise excessive influence over this process, and so favor their own affiliated generation in interconnection decision-making."[105] PJM submitted a compliance filing placing the entire interconnection process under its control, but the issue was effectively mooted when the Commission decided to consider a new generator interconnection through rulemaking. The Commission noted that once this final rule was adopted, PJM would be subject to it.
PJM was found to satisfy most of the other minimum functions in the order granting provisional RTO status.[106] With regard to the second minimum function, congestion management, FERC enthusiastically approved PJM's use of LMP and fixed financial rights for pricing transmission, noting that "markets based on LMP and financial rights for firm service appear to provide a sound framework for efficient congestion management."[107] As noted above, FERC has adopted PJM's pricing system in its SMD proposal.
PJM's market monitoring system, in satisfaction of minimum function six, provides for the use of a market monitoring unit (MMU) to investigate and monitor market participants' activities.[108] Specifically, the MMU is charged with monitoring congestion pricing, exercises of market power, flaws in market rules, and structural problems within the market. The MMU may recommend changes to the PJM tariff and operating agreement and can issue demand letters to market participants requesting that they discontinue activities that may violate market rules.[109] The MMU does not, however, have specific powers to institute mitigation measures. FERC found this structure consistent with Order No. 2000's requirements.[110]
[3] FERC's Recent Western RTO Orders: Signs of Flexibility and a Convergence with the SMD Proposal
The two initially approved RTOs may provide models for how future proposals will garner the approval of FERC. However, recent FERC orders show more flexibility in breaking with the strict pretexts of Order No. 2000 and the SMD proposal. More recent FERC decisions on the RTO proposals before it have also explicitly discussed the Commission's SMD proposal. These are found in FERC's recent issuances concerning two RTO proposals in the Western U.S., RTO West and WestConnect.
The RTO West proposal covers the Northwest and would include the transmission systems of utilities from Nevada to British Columbia. It also includes the vast grid of the Bonneville Power Administration (BPA). The WestConnect proposal embraces utilities in New Mexico, Arizona, and a small portion of West Texas not included with the Electric Reliability Council of Texas (ERCOT). In both proceedings, the Commission has expressly included discussion of its proposed SMD rule in its order on the RTO proposal's compliance with Order No. 2000.
For example, on September 18, 2002, FERC issued a declaratory order approving the "Stage 2" filing of the RTO West participants.[111] Early in the order, the Commission stated:
The Commission has recently issued for public comment a Notice of Proposed Rulemaking relating to standard electricity market design. Because there is broad overlap of issues between that proposal and this filing, the Commission will take the opportunity here to provide a comparison between RTO West's filing and the proposed rule. We look at this comprehensive filing as both informing and being informed by the proposed rule.[112]
The order providing provisional approval to the WestConnect RTO proposal, issued on October 10, 2002, includes a similar declaration.[113]
These recent Western RTO orders have important aspects that may guide the future course of RTO development and SMD. FERC has stated that the RTO West proposal is a "model" both for RTO development and for the SMD proposal. During the regular FERC open meeting at which the agency issued its Stage 2 approval of RTO West, Chairman Pat Wood III called the proposal "pretty much best in class," noting that it can be a model for other RTO organizers.[114] As a result, the Commission's order is likely to receive significant attention and citation.
The Commission has also stated that the RTO West order displays its ability to be flexible regarding the proposed SMD rule, in response to concerns from the states that a rigid rule would bring negative consequences. State and regional officials in the Northwest, where RTO West would operate, were especially concerned about a rigid set of nationwide standard market rules because the region has several unique features, including its large amount of hydroelectric resources and the presence of many entities not subject to FERC regulation, including BPA and several municipal and public power entities. Former Commissioner Linda Breathitt noted, in approving the order, that the Commission will "allow for regional differences," and "give an indication where . . . regional variations might be employed."[115] FERC accepted the applicant's proposal to institute an eight-year transition period, even though it is longer than the transition period contemplated by the SMD NOPR, because it would allow for greater participation by the public power entities in the region and provide more cost certainty.[116] Additionally, the Commission allowed for several variations from the SMD proposal in the area of congestion management, to accommodate the region's hydroelectric resources, which have operating characteristics significantly different from fossil fuel resources.[117]
In the Commission's Declaratory Order granting preliminary approval to the WestConnect RTO, and a separate order issued on the same day granting the same approval to the SeTrans RTO, a proposed RTO for the Southeast, the Commission declared that it would not revisit any approvals therein in the event the final SMD rule conflicted with those approvals. As the Commission explained in its WestConnect order:
[B]ecause of the extensive efforts committed by industry participants to developing a framework for a sound RTO proposal here, we take this opportunity that it is not this Commission's intent to overturn, in the final Standard Market Design Rule, decisions that are made in this docket. In other words, unless the Commission has specifically indicated in this order that an element of the RTO proposal is inconsistent with the Standard Market Design proposal or needs further work in light of the Standard Market design proposal, we do not intent, in the final Standard Market Design rule, to revisit prior approvals or acceptances of RTO provisions because of possible inconsistencies with the details of the final rule.[118]
Commissioner William Massey dissented from this statement, which he called a "significant policy shift," arguing that it "unnecessarily ties the Commission's hands in developing regional electricity markets, " and "risks compromising the objectives of SMD."[119]
From a policy standpoint, the developments in these recent orders will prove significant as FERC looks to establish RTOs and standardize the national wholesale electricity market. FERC's commitment to regional flexibility is likely to be important to satisfy the concerns of state policymakers, and the members of Congress who represent them. Additionally, future RTO organizers are likely to look for the same "grandfather clause" given to WestConnect and SeTrans. RTO West, in fact, returned to the Commission after these orders, asking for the same treatment.[120] In its order on rehearing in the RTO West case, the Commission granted RTO West's request.[121]
[4] Other RTO Issues
[a] Governance
FERC quickly disposed of governance issues in considering the now fully-approved RTOs, MISO and PJM, largely because their ISO structures, approved under the dictates of Order No. 888, also satisfied the requirements of Order No. 2000. With regard to the "from scratch" RTO proposals, the most significant issue regarding organization governance has been the amount of governing authority transmission owners may have in the RTO. Essentially, the issue centers around what kind of decision-making by the RTO the transmission-owners members of that RTO may participate in.
The Commission set key precedent in this area early in its RTO consideration process. In Carolina Power & Light Co., et al.,[122] FERC considered a proposal to form the GridSouth Transco RTO, covering transmission systems in North and South Carolina. The utilities forming GridSouth proposed to form a for-profit "Transco," with the new entity having functional control over the transmission assets and the utility transmission owners having only passive control. In other words, the transmission owners would share in the profits and losses of the organization but would be permitted to make only a few business decisions. In GridSouth, the RTO would make all the business decisions relating to the provision of transmission service, while the transmission owners would be able to participate in limited fundamental business decisions, such as whether to dissolve the Transco, whether to sell assets, merge with another entity, or engage in businesses other than transmitting power. Additionally, with regard to removing members of the RTO Board, 85% of the passive transmission owners may request an independent panel of arbitrators to remove a board member for cause.[123]
Several intervenors in the case believed that this arrangement violated the independence characteristic of Order No. 2000, arguing that giving market participants such as the transmission owners any ownership interest would compromise the independence of the RTO.[124] FERC approved GridSouth's governing arrangement, however, subject to minor modifications, finding that "GridSouth will be independent of market participants in both perception and reality."[125] The Commission reasoned, in response to the intervenors' arguments, that Order No. 2000 allows the Commission to approve passive ownership arrangements if those passive owners have "relinquished control over operation, investment and other decisions."[126] Also, FERC noted in the order that Order No. 2000 "recognized the need for passive owners to protect the value of their assets they commit to and investments they make in the RTO."[127] Thus, the Commission found that "a limited reservation of rights over certain fundamental business decisions is an acceptable means for the GridSouth members to preserve their financial investment."[128]
FERC has followed this precedent in subsequent cases. For example, the WestConnect RTO organizers proposed in their FERC filing that the RTO operate as a Transco, with transmission owners turning over functional control of their facilities and retaining passive ownership rights, in much similar fashion to GridSouth.[129] Several intervenors protested, with some arguing that the for-profit nature of a Transco makes it inherently opposed to the independence requirements of Order No. 2000.[130] FERC refused these arguments and approved WestConnect's proposal, affirming its initial holdings in its GridSouth order with regard to passive ownership and retained rights of passive owners.
[b] Seams
"Seams" issues are arguably some of the most important issues the Commission faces in these proceedings. The term "seams" refers generally to the connections between RTOs. These connections raise several concerns, including coordination of facilities and the imposition of additional rates as transmission of electricity passes over seams and into new RTO regions.
The Commission's decision approving MISO as the first officially-approved RTO, and rejecting the proposal of the Alliance companies, was an early indication of the agency's concern over seams between RTOs. In July 2001, about six months before the final order on MISO was issued, the Commission issued an order finding that the Alliance proposal had an adequate scope to satisfy Order No. 2000.[131] At the time, according to the Commission, it was relying on the development of an Inter-RTO Cooperation Agreement ("IRCA") between Alliance and MISO that would remedy seams problems between the two RTOs. But, at the time it chose MISO over Alliance, the Commission found that the IRCA had not developed as hoped, and that "significant seams issues still exist."[132] For example, the Commission noted that the two RTOs would calculate ATC and TTC in a similar, but not identical, manner, creating "a seam that inhibits efficient market operations."[133]
MISO has clearly heeded the Commission's call to eliminate seams. As noted above, MISO, PJM and SPP are in the process of establishing a single, seamless market through their three regions. On December 19, 2002, FERC issued an order that, among other items, conditionally approved a joint tariff filing of MISO and SPP.[134] The approval of this filing allows transmission customers "one-stop shopping," at a single rate, for transmission service across the entire MISO and SPP service area.
The Western RTO proposals are also dealing with seams issues. In a recent order on rehearing concerning the RTO West and WestConnect proposals, FERC highlighted the groups' participation in the seams working group in the West, called the Seams Steering Group – Western Interconnect ("SSG-WI").[135] SSG-WI consists of members of RTO West, WestConnect, and the California ISO, and is intended to address coordination of facilities, market monitoring, transmission planning, congestion management and price reciprocity among the three regions.[136] In its order, FERC explained that our "approval of any individual RTO market design solution is based on our expectation that the parties will continue to identify and work toward a successful resolution of any resulting seams issues."[137] Additionally, in these rehearing orders the Commission asked the parties to specifically consider export rate issues through the SSG-WI process. FERC made this request as it backtracked on a statement in its September 18, 2002 order conditionally approving RTO West that found an export fee imposed by the entity on power moving out of the RTO reasonable. On rehearing, the Commission noted that an export fee could create disincentives for trade between RTO regions and create seams.
[c] Pricing of Transmission Service
Closely linked with seams issues are issues surrounding the pricing of transmission service in individual RTOs, and the pricing applicable to transmissions of electricity that begin in one RTO and move through another, or several others. The Commission's goal with regard to the formation of RTOs and a standard market design, in addition to removing discrimination in the provision of transmission services, has been to eliminate price disparities and provide more economic efficiency in transmission markets. This policy goal has driven FERC's concerns both in this area and with regard to seams issues, discussed previously.
It is difficult to identify a pattern in FERC's RTO orders regarding the pricing of transmission service. For certain, the Commission has evidenced a strong intent to eliminate "rate-pancaking," a term that has been used to describe the multiple charges that can apply to transmissions of electricity flowing through the transmission facilities of more than one utility. Each utility exacts a charge for the transmission service, leading to a "pancaked" final charge for the transmission. While MISO and PJM have taken steps to allow for one-rate transmission service across their territories, they have not reached a final agreement, and FERC has strongly urged them to do so.[138]
In general, most RTO proposals have included a transition period before the new rates charged by the RTO for transmission service will be in effect. In general, the proposals have included either "license plate" rate design, where the rate charged for transmission service varies depending on the starting or ending point of the service, or "postage stamp" rates, where the charge is the same for all transmission service within the system. Additionally, most RTO proposals are including a separate charge for service into or out of the RTO, sometimes called an export fee. The Commission seems to be giving these charges more scrutiny, because they can lead to seams problems or other issues similar to "rate-pancaking."
[d] Funding of Transmission Expansions: Who Pays?
State regulators have been especially concerned with potential cost-shifts for transmission service, and especially for the potential increased costs from upgrades to transmission systems necessitated by new generation projects. These state concerns were especially apparent following the FERC's release of its SMD NOPR. Many state leaders are concerned that large standard markets would spread costs for transmission upgrades necessary to interconnect new, independent generation projects not intended to serve customers in their own region. Those concerns have been especially strong in the Southeast, where several new competitive generation projects have been installed, or are planned to be installed, to serve national wholesale markets.[139] Southeast regulators are concerned that the costs of transmission upgrades in the region that such projects would necessitate would be passed on to local consumers, who they argue would receive no benefit from the new plants.[140]
FERC indicated flexibility in this area in an October 10, 2002 order granting provisional approval to the SeTrans RTO proposal, a proposed entity serving a large area of the Southeast.[141] The SeTrans proposal contained a plan for funding transmission expansions within the RTO under one of two mechanisms. The first mechanism, called participant funding, requires the entity in need of the expansion (usually the merchant generator) to fund the costs of the expansion itself. Under the proposal, this first mechanism would be utilized when the transmission expansion project at issue will add, integrate or interconnect new generation to the grid, and when the project will add capacity to move power into or out of the SeTrans system. The second mechanism, called "base plan funded," would include the costs of the transmission expansion in the rates applicable to transmission service in a particular zone of the RTO. This mechanism would be used in instances such as when the project is required to reliably serve forecasted load in the region and to maintain the existing transmission grid.[142]
In its order accepting this framework, FERC noted that its Generator Interconnection Notice of Proposed Rulemaking and the SMD NOPR indicated that it would accept participant funding as part of a pricing policy, provided that the costs of the expansion were determined by a private entity.[143] Additionally, the SMD NOPR "suggested that the Commission would look favorably upon a consensus pricing policy of state commissions in a region."[144] Based on these prior statements of policy, the Commission found that the SeTrans proposal "provides the independent administration of a regional planning process that the Commission has said is necessary to consider participant funding."[145] FERC was also influenced by the consensus support for the SeTrans framework among state commission in the Southeast.[146]
Following this order, the Commission scheduled a technical conference on participant funding as part of its series of technical conferences on the SMD proposal. The Commission's vision of participant funding, and its use in any future standard market design order, seems likely to evolve in the months to come.
[e] Inclusion of Non-Jurisdictional Entities and State Regulators
Since the outcry of state regulators against FERC's SMD proposal, the Commission has given increasing attention to finding roles for state governing bodies in RTOs and a SMD final rule. RTO West includes participation by Bonneville Power Administration (BPA), a non-FERC jurisdictional utility not subject to Order No. 2000, and it has provisions that will ease participation by municipal utilities, who are also non-FERC jurisdictional. Non-jurisdictional entities are also participating in the WestConnect RTO proposal.
In its RTO West order, the Commission asked the RTO West organizers to establish a "separate state representatives committee" charged with voicing concerns directly to the RTO's independent board of directors, instead of having state representatives participate in a "board advisory committee."[147] The Commission based this recommendation on the state representatives committee concept in its SMD proposal.[148]
[f] Scope and Configuration
The scope and configuration characteristic of Order No. 2000 has arguably proven to be somewhat malleable. While the MISO/Alliance competition described above could be described as a case study in this essential characteristic of RTOs, there have been a wide variety of proposals that have been deemed to satisfy FERC's scope and configurations requirements.
On March 28, 2001, relatively early in the consideration of RTO proposals, FERC issued an order granting provisional RTO status to GridFlorida, LLC.[149] GridFlorida is a one-state RTO proposal, made up of three large utilities in peninsular Florida. When proposed at FERC, many intervenors in the case questioned the scope of the RTO, arguing that it was not of sufficient size to mitigate market power, as required by Order No. 2000.[150] The Commission disagreed with these arguments, and found that the proposal "satisfie[d] several scope and configuration factors laid out in Order No. 2000."[151] Specifically, the Commission noted that GridFlorida's territory represents one contiguous geographic area, includes a highly integrated portion of the transmission grid, and encompasses an existing reliability region within the North American Electric Reliability Council (NERC).[152] FERC concluded that all of these factors supported a finding that GridFlorida's scope was consistent with Order No. 2000.
Later that year, however, in a series of orders, the Commission expressed a strong preference that just four RTOs be created for the entire country. Specifically, the Commission believed that one RTO could be created in the Midwest, the Southeast, the Northeast and the West. While the Commission excepted Florida and Texas from this statement, it still seemed to represent a stark policy shift.[153] The Commission has since backed away from this policy, largely because of protests in the West regarding the possibility of one RTO for that entire area. The Commission's acceptance of the scope of both the WestConnect and RTO West proposals in the Western region have likely put to rest any possibility that only four RTOs will be created.
[g] New York and New England: Where Do They Go?
The New York ISO and ISO New England had proposed to merge and create a Northeast Regional Transmission Organization. However, the ISOs withdrew their proposal on November 22, 2002. The proposal had come under protest from several parties, including state government officials in the New England states.[154] ISO-NE officials stated that the opposition of market participants to the proposed merger signaled that the groups should focus on establishing a standard market design and resolving seams issues between the two regions.[155] Connecticut Attorney General Richard Blumenthal opposed the proposed merger, and like many other New England opponents, argued that the merger would result in significant cost-shifts away from New York at the expense of New England.[156]
In January 2003, it was reported that ISO-NE would seek to become an RTO.[157] Even if this proposal succeeds, there could be significant seams issues in the Northeast region, where depending on the final course of the various RTO proceedings currently pending, an ISO-NE RTO, the New York ISO, and PJM RTO could all meet. Given the transmission constraints already present in this region, significant seams problems in this highly populated area could severely hamper FERC's goal of a seamless national power market.
§ 1.06 Summary and Conclusion
The design of wholesale electricity markets in the United States is still evolving. It has only been fifteen months since FERC approved the first RTO, the Midwest Independent System Operator. The PJM Interconnection was approved only two months ago. In between these two approvals, FERC proposed a standard market design. That has been something of a blueprint for the development of other RTO's. However, FERC's recent orders regarding western RTO proposals reflect an interest in being more flexible on the design of markets than the SMD proposal, on its face, might convey. The year 2003 promises continued development of market design and RTO formation as numerous RTO applications work their way through the approval process at FERC.
[1] I want to acknowledge and thank Jeffrey S. Dennis for the significant and excellent work he did on the research and writing of this article.
[2] Pub. L. No. 102-486, 106 Stat. 2776 (codified as amended in scattered sections of titles 15, 16, 25, 30, 40, 42 & 49 U.S.C.).
[3] Pub. L. No. 95-617, 92 Stat. 3117 (codified as amended in scattered sections of titles 15, 16, 42 & 43 U.S.C.)
[4] 15 U.S.C. §§ 79-79(z) (2000).
[5] See 16 U.S.C. §§ 824j-824k (2000). These utilities include intrastate utilities, federal power marketing agencies, and qualifying cogeneration and small power production facilities. The legislation specifically provides, however, that FERC may not order transmission providers to provide access to transmission for unbundled retail power sales.
[6] 15 U.S.C. §79z-5a (2000).
[7] See, e.g., Florida Mun. Power Agency, 65 F.E.R.C. ¶ 61,125 (1993); Tex-La Electric Cooperative of Texas, Inc., 67 F.E.R.C. ¶ 61,019 (1994). See also Suedeen G. Kelly, "Electricity," in The Energy Law Group, Energy Law and Policy for the 21st Century 12-25 (Rocky Mt. Min. L. Fdn. 2000)
[8] Federal Energy Regulatory Commission (FERC) Final Rule Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities, Order No. 888, 61 Fed. Reg. 21,540 (May 10, 1996) (codified at 18 C.F.R. pts. 35 & 385) [hereinafter Order No. 888].
[9] Id. at 21,543.
[10] Traditionally, public utilities had provided all of these services together in a single "bundled" price.
[11] Order No. 888, supra note 8, at 21,571.
[12] This requirement effected utilities who either voluntary, or as a result of state mandate, offered unbundled retail access.
[13] 535 U.S. 1 (2002).
[14] Fred Bosselman, Jim Rossi & Jacqueline Lang Weaver, Energy, Economics and the Environment: Cases and Materials 762 (2000).
[15] Id.
[16] Id.
[17] See Order No. 888, supra note 8, at 21,595-597
[18] Federal Energy Regulatory Commission (FERC) Final Rule on Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 810 (Jan. 6, 2000) (codified at 18 C.F.R. § 35.34) [hereinafter Order No. 2000].
[19] Id. at 811.
[20] Id. at 813-14.
[21] Id. at 815-16.
[22] See Order No. 2000, supra note 18.
[23] Id. at 811.
[24] Id.
[25] Id. at 811-12.
[26] 18 C.F.R. § 35.34(j)(1) (2002).
[27] Id.
[28] 18 C.F.R. § 35.34(j)(1)(iv).
[29] 18 C.F.R. § 35.34(j)(2).
[30] See Order No. 2000, supra note 18, at 860.
[31] Id. at 861.
[32] Id at 861-64.
[33] 18 C.F.R. § 35.34(j)(3).
[34] 18 C.F.R. § 35.34(j)(4).
[35] Id.
[36] 18 C.F.R. § 35.34(k)(1).
[37] 18 C.F.R. § 35.34(k)(2).
[38] 18 C.F.R. § 35.34(k)(3)
[39] 18 C.F.R. § 35.34(k)(4). "Ancillary services" are defined in Order No. 2000 as those required by Order No. 888, and include scheduling, system control and dispatch, voltage control, and operating reserve requirements. See Order No. 888, supra note 8, at 21,586-87.
[40] 18 C.F.R. § 35.34(k)(4).
[41] 18 C.F.R. § 35.34(k)(5).
[42] 18 C.F.R. § 35.34(k)(6).
[43] 18 C.F.R. § 35.34(k)(7).
[44] 18 C.F.R. § 35.34(k)(8).
[45] Federal Energy Regulatory Commission (FERC) Proposed Rule, Remedying Undue Discrimination Through Open Access Transmission Service and Standard Electricity Market Design, 67 Fed. Reg. 55,452 (Aug. 29, 2002) (to be codified in 18 C.F.R. Part 35) [hereinafter SMD Proposal.]
[46] Id. at 55,470.
[47] Id.
[48] Id. at 55,529.
[49] Id.
[50] Id. at 55,471-75.
[51] SMD Proposal, supra note 45, at 55,476.
[52] Id. at 55,476-77.
[53] Id. at 55,476.
[54] Id. at 55,477.
[55] Id. at 55,487.
[56] Id. at 55,508.
[57] SMD Proposal, supra note 45, at 55,508.
[58] Id. at 55,530.
[59] Id. at 55,479-482 & 55,484-487.
[60] Id. at 55,479-480.
[61] Id. at 55,484.
[62] Id. at 55,486.
[63] SMD Proposal, supra note 45, at 55,479.
[64] Id.
[65] Id.
[66] Id.
[67] Id.
[68] Id.
[69] SMD Proposal, supra note 45, at 55,514.
[70] Id.
[71] See generally "Many State Commissions Demand that FERC Withdraw Proposed SMD Rule, but Others Just Want Initiative Tweaked," Foster Electric Report, Dec. 4, 2002.
[72] Lori A. Burkhart, "A Fight Over Market Design: FERC's Attempts to Standardize Markets Have Some State Regulators Up in Arms," Pub. Util. Fortnightly, Nov. 15, 2002, at 18.
[73] Midwest Independent Transmission System Operator, Inc., 97 F.E.R.C. ¶ 61,326 (2001).
[74] Id. at ¶ 62,501.
[75] Id.
[76] Id. at ¶ 62,504.
[77] Id.
[78] Id.
[79] Midwest Independent Transmission System Operator, Inc., 97 F.E.R.C. ¶ 61,326, ¶ 62,504 (2001).
[80] MISO has an agreement with Manitoba Hydro for the coordination of facilities and operations.
[81] Midwest Independent Transmission System Operator, Inc., 97 F.E.R.C. at ¶ 62,501.
[82] Id. at ¶ 62,508.
[83] Id.
[84] Id.
[85] Midwest Independent Transmission System Operator, Inc., 97 F.E.R.C. ¶ 61,326, ¶ 62,510 (2001).
[86] Id. at ¶ 62,505.
[87] See generally id. at ¶¶ 62,511-516.
[88] See generally id. at ¶¶ 62,516-519.
[89] Midwest ISO, About Us, at http://www.midwestiso.org/about_us.shtml (last visited February 19, 2003).
[90] See Midwest Transmission System Operator, Inc., FERC Docket Nos. ER02-1420-003, ER02-1420-004, ER02-1420-006 (Dec. 19, 2002.)
[91] See MISO – PJM – SPP website, at http://www.miso-pjm-spp.com/ (last visited February 19, 2003).
[92] PJM Interconnection, L.L.C., et al., 2002 FERC LEXIS 2621.
[93] PJM Interconnection, L.L.C., et al., 96 F.E.R.C. ¶ 61,061 (2001).
[94] Id. at ¶ 61,228.
[95] Id.
[96] Id. at ¶ 61,229.
[97] Id. at ¶ 61,231.
[98] Id. at ¶¶ 61,231-232.
[99] PJM Interconnection, L.L.C., et al., 2002 FERC LEXIS 2621, *6-9.
[100] Id.
[101] PJM Interconnection, L.L.C., et al., 96 F.E.R.C. ¶ 61,061, ¶¶ 61,232-233 (2001).
[102] Id.
[103] Id. at ¶ 61,233.
[104] PJM Interconnection, L.L.C., et al., 2002 FERC LEXIS 2621, *12-13.
[105] See id.
[106] See generally PJM Interconnection, L.L.C., et al., 96 F.E.R.C. at ¶¶ 61,234-242.
[107] PJM Interconnection, L.L.C., et al., 96 F.E.R.C. ¶ 61,061, ¶ 61,235 (2001).
[108] Id. at ¶ 61,238.
[109] Id.
[110] Id. at ¶ 61,239.
[111] Avista Corp. et al., 100 F.E.R.C. ¶ 61,274 (2002).
[112] Id. at ¶ 62,051.
[113] Arizona Public Service Co. et al., 2002 FERC LEXIS 2094, *3-4.
[114] "Commissioners Conditionally Approve RTO West Stage 2 Filing, Suggesting That Order Shows Their Ability to Be Flexible Regarding SMD," Foster Electric Report, Sept. 25, 2002.
[115] Id.
[116] Avista Corp. et al., 100 F.E.R.C. at ¶ 62,071.
[117] Avista Corp. et al., 100 F.E.R.C. ¶ 61,274, ¶¶ 62,076-77 (2002).
[118] Arizona Public Service Co. et al., 2002 FERC LEXIS 2094, *4; see also Cleco Power LLC et al., 2002 FERC LEXIS 2076, *3-4.
[119] Arizona Public Service Co. et al., 2002 FERC LEXIS 2094, *149-51.
[120] See "RTO West Wants the Same Leeway Afforded to SeTrans, WestConnect," Platts Inside FERC, Oct. 28, 2002, at 10.
[121] See Avista Corp. et al., 2002 FERC LEXIS 2637.
[122] 94 F.E.R.C. ¶ 61,273 (2001).
[123] For a more in-depth description of the proposal, see generally id. at ¶¶ 61,981-982.
[124] Id. at ¶ 61,983.
[125] Id. at ¶ 61,985.
[126] Id.
[127] Id. at ¶ 61,986.
[128] Carolina Power & Light Co. et al., 94 F.E.R.C. ¶ 61,273, ¶ 61,986 (2001). It should be noted that the GridSouth RTO has recently ceased implementation activities. See "GridSouth Sponsors Suspend RTO Implementation Activities," Foster Electric Report, Jun. 18, 2002.
[129] Arizona Public Service Co. et al., 2002 FERC LEXIS 2094, *11.
[130] Id. at *16-17.
[131] Alliance Companies et al., 96 F.E.R.C. ¶ 61,052, ¶ 61,135 (2001).
[132] Alliance Companies et al., 97 F.E.R.C. ¶ 61,327, ¶¶ 62,529-530 (2001).
[133] Id. at ¶ 62,530.
[134] See Midwest Transmission System Operator, Inc., FERC Docket Nos. ER02-1420-003, ER02-1420-004, ER02-1420-006 (Dec. 19, 2002.)
[135] See, e.g., Arizona Public Service Co. et al., 2002 FERC LEXIS 2637.
[136] See "RTO West and WestConnect Rehearing Orders Provide Greater Flexibility, Require More Work by Organizers," Foster Electric Report, Dec. 31, 2002.
[137] Arizona Public Service Co. et al., 2002 FERC LEXIS 2637, *9.
[138] See "FERC Urges Midwest ISO, PJM to Settle Rate Dispute," Reuters, Jan. 7, 2003.
[139] See generally "Southern Governors Revile SMD 'Socializing' of Transmission Costs," Platts Inside FERC, Sept. 2, 2002, at 7.
[140] Id.
[141] Cleco Power LLC et al., 2002 FERC LEXIS 2076.
[142] For a more in-depth description of the two mechanisms, see id. at *76-78.
[143] See Federal Energy Regulatory Commission (FERC) Proposed Rule, Standardization of Generator Interconnection Agreements and Procedures, 67 Fed. Reg. 22,250 (May 2, 2002) (to be codified in 18 C.F.R. Part 35).
[144] See SMD Proposal, supra note 45, at 55,479.
[145] Cleco Power LLC et al., 2002 FERC LEXIS 2076, *83.
[146] Id. at *83-84.
[147] Avista Corp. et al., 100 F.E.R.C. ¶ 61,274, ¶ 62,057 (2002).
[148] SMD Proposal, supra note 45, at 55,519.
[149] GridFlorida LLC et al., 94 F.E.R.C. ¶ 61,363 (2001).
[150] Id. at ¶ 62,335.
[151] Id. at ¶ 62,336.
[152] Id.
[153] See, e.g., GridSouth Transco, LLC et al., 96 F.E.R.C. ¶ 61,067, ¶ 61,287 (2001).
[154] "NYISO, ISO-NE Yank NERTO Proposal After Opposition Pours In," Platts Inside FERC, Dec. 2, 2002, at 1.
[155] Id.
[156] Id.
[157] "ISO New England Seeks Right to Create Regional Transmission Group," Providence (R.I.) Journal, Jan. 21, 2003.