FERC Order No. 1000 State Siting and Construction Requirements
White Paper Published by: SPP Legal/Regulatory For the SPP Strategic Planning Committee Final – December 8, 2011
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TABLE OF CONTENTS 1. HISTORY AND BACKGROUND ........................................................................................... 3 2. DEFINITIONS ........................................................................................................................... 3 3. ORDER NO. 1000 REQUIREMENTS REGARDING NONINCUMBENT TRANSMISSION DEVELOPER PARTICIPATION IN REGIONAL TRANSMISSION PLANNING .............. 4 4. OVERVIEW OF STATE CONSTRUCTION AND SITING REQUIREMENTS ................... 4 5. STATE-BY-STATE CITING LAWS AND REQUIREMENTS .............................................. 5 A. Arkansas ........................................................................................................................... 5 B. Kansas .............................................................................................................................. 7 C. Louisiana .......................................................................................................................... 8 D. Missouri ........................................................................................................................... 9 E. Nebraska ........................................................................................................................ 11 F. New Mexico ................................................................................................................... 12 G. Oklahoma ....................................................................................................................... 14 H. Texas .............................................................................................................................. 15 6. CONCLUSION ........................................................................................................................ 17
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1. HISTORY AND BACKGROUND On July 21, 2011, the Federal Energy Regulatory Commission (“FERC”) issued Order No. 1000, Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities.1 Order No. 1000 requires all public utility transmission providers to (among other things) facilitate nonincumbent transmission developer participation in regional transmission planning by removing from FERC-approved tariffs and agreements any language creating a federal right of first refusal (“ROFR”) for an incumbent transmission provider to construct transmission facilities selected in a regional transmission plan for cost allocation.2 Compliance filings to address this requirement are due October 11, 2012. During its August 30, 2011 meeting, the Strategic Planning Committee (“SPC”) directed Southwest Power Pool (“SPP”) staff to develop a series of white papers examining the various compliance requirements of Order No. 1000 and proposing possible modifications to the SPP Open Access Transmission Tariff (“OATT”) and other SPP documents and processes to comply with Order No. 1000. This white paper examines state laws and regulations governing the construction and siting of transmission facilities in the SPP Region. As a multi-state Regional Transmission Organization (“RTO”), SPP will need to examine state laws and regulations governing siting and authority to construct transmission facilities when determining how to address the requirement to eliminate federal ROFR from the SPP OATT and agreements.
2. DEFINITIONS Order No. 1000 uses the following terminology relevant to this white paper: Incumbent transmission developer/provider: An entity that develops a transmission project within its own retail distribution service territory or footprint. Nonincumbent transmission developer: An entity that either: (1) does not have a retail distribution service territory or footprint; or (2) is a public utility transmission provider that proposes a transmission project outside of its existing retail distribution service territory or footprint, where it is not the “incumbent” for purposes of the project. Transmission facility selected in a regional transmission plan for purposes of cost allocation: A transmission facility that has been selected, pursuant to a Commission-approved regional transmission planning process, as a more efficient or cost-effective solution to regional transmission needs. This term does not include: (1) facilities planned by local planning process that are “rolled-up” into regional plans; and (2) facilities for which the sponsor does not intend to 1
136 FERC ¶ 61,051 (FERC Docket No. RM10-23-000).
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Order No. 1000 indicates that the elimination of federal ROFR from FERC-approved tariffs and agreements does not: (1) apply to transmission facilities not selected in a regional transmission plan for purposes of cost allocation; (2) apply to upgrades to existing transmission facilities, such as tower change outs or reconductoring; (3) affect existing rights-of-way; and (4) affect state or local laws or regulations regarding the construction or siting of transmission facilities.
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seek cost allocation under the regional cost allocation methodology (i.e., merchant transmission facilities). Transmission planning region: The region in which a public utility transmission provider, in consultation with stakeholders and affected states, has agreed to participate for purposes of regional transmission planning and development of a single regional transmission plan. For RTO members, the transmission planning region is the RTO region.
3. ORDER NO. 1000 REQUIREMENTS REGARDING NONINCUMBENT TRANSMISSION DEVELOPER PARTICIPATION IN REGIONAL TRANSMISSION PLANNING Order No. 1000 requires public utility transmission providers to remove from their OATTs and other FERC-jurisdictional tariffs and agreements any provisions that grant a federal ROFR to incumbent transmission owners to construct transmission facilities that are selected in a regional transmission plan for purposes of cost allocation.3 The focus of this requirement is transmission facilities that are evaluated at the regional level and selected in the regional plan for purposes of cost allocation, as opposed to facilities that are planned exclusively in the public utility transmission provider‟s local planning process and simply “rolled-up” and listed in the regional transmission plan for informational purposes and analysis. This requirement does not apply to the right of an incumbent utility to build, own, and recover costs for upgrades to its existing transmission facilities, and does not alter an incumbent transmission provider‟s use and control of existing rights of way, even if such upgrades or facilities on existing rights-of-way are selected in the regional transmission plan for purposes of cost allocation. In Order No. 1000, FERC expressly indicated that its requirement to eliminate federal ROFR from all FERC-approved tariffs and agreements was not intended to limit, preempt, or otherwise affect state or local laws or regulations with respect to construction of transmission facilities, including but not limited to authority over siting or permitting of transmission facilities. Moreover, Order No. 1000 does not require public utility transmission providers to remove from FERC-approved tariffs and agreements references to state or local laws or regulations that address ROFR.
4. OVERVIEW OF REQUIREMENTS
STATE
CONSTRUCTION
AND
SITING
As discussed above, FERC‟s mandate to eliminate federal rights of first refusal for incumbent transmission owners to construct facilities selected in the regional transmission plan for cost 3
Order No. 1000 at P 313. Order No. 1000 continues to permit incumbent transmission providers to meet their reliability needs or service obligations by choosing to build new transmission facilities that are located solely within their retail distribution service territory or footprint and that are not included in the regional transmission plan for cost allocation. Id at P 262.
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allocation was not intended to affect state or local laws governing the construction, siting, or permitting of transmission facilities. In developing its compliance filing to remove ROFR for such facilities, it is useful for SPP to examine the relevant state laws and regulations governing the construction of transmission facilities in the SPP Region. Specifically, state statutes and regulations addressing the siting and/or permitting of new transmission facilities and state laws governing the types of entities that are permitted to construct transmission facilities are particularly relevant to the Order No. 1000 requirement to eliminate federal ROFR. With respect to siting of transmission facilities, state laws in Arkansas, Kansas, Missouri, Nebraska, New Mexico, and Texas contain some requirements for public utilities to seek state commission approval for the siting of transmission facilities. In these states, the laws vary from requiring siting approval for each individual transmission facility to requiring that an entity obtain certification to construct in a service territory or area. Louisiana and Oklahoma do not require entities to obtain siting approval before constructing transmission facilities. Several states also place limits on the types of entities that are eligible to construct transmission facilities or require entities to obtain a certificate prior to engaging in transmission construction and ownership activities in the state. Such states include Arkansas, Kansas, Missouri, Nebraska, and Texas. Section 5 of this White Paper examines the specific state-by-state construction and siting requirements, with citation to relevant statutes and regulations.
5. STATE-BY-STATE CITING LAWS AND REQUIREMENTS A.
Arkansas
The Arkansas Code, as interpreted by the Arkansas Public Service Commission (“APSC”), authorizes only entities that are currently public utilities certificated by the APSC to construct and own transmission facilities in the state.4 The Arkansas Code states that “[n]ew construction or operation of equipment or facilities for supplying a public service or the extension of a public service shall not be undertaken without first obtaining from the Arkansas Public Service Commission a certificate that public convenience and necessity require or will require the construction or operation.”5 The APSC has interpreted the Arkansas Code to limit its ability to grant such certificates to “public utilities,”6 and that the definition of public utility “requires „owning or operating in this state equipment or facilities for . . . transmitting . . . power to or for the public for compensation.‟”7 The APSC acknowledged the circularity involved in requiring an entity to own or operate transmission facilities prior to being able to become 4
In re Application of Plains and Eastern Clean Line LLC for a Certificate of Public Convenience and Necessity to Construct, Own and Operate as an Electric Transmission Public Utility in the State of Arkansas, Docket No. 10-041-U, Order No. 9 (APSC Jan. 11, 2011) (“Clean Line Order”).
5
Ark. Code Ann. § 23-3-201(a).
6
Clean Line Order at 9.
7
Id. at 10-11 (citing Ark. Code Ann. § 23-1-101(9)(A)).
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certificated to construct transmission facilities, but declined a nonincumbent transmission developer‟s request for certification based on this interpretation of its statutory authority.8 For transmission siting authorizations, Arkansas Law distinguishes between “major utility facilities” (transmission lines and associated facilities with a design voltage of at least 100-kV if the transmission line is more than 10 miles in length, or transmission lines and associated facilities with a design voltage of at least 170-kV for lines more than one mile in length),9 and other, non-major transmission facilities. Major transmission facilities undergo more rigorous review than non-major projects; however, modifications to existing facilities to replace, upgrade, or modernize existing lines and associated equipment do not require additional authorizations if they do not exceed existing rights-of-way.10 Applicants are required to submit information showing: (1) that the proposed construction is or will be required by the public convenience and necessity; (2) the proposed location or route; (3) maps specifying the route to be followed in constructing the new transmission line, the location of nearby airports, and applicable allocation boundaries; (4) cost estimates and related data; and (5) the proposed method of financing.11 Applicants seeking to construct major utility facilities are also required to submit information regarding: (1) a general description of the location and type of transmission line and associated facilities; (2) a general description of any reasonable alternative locations or routes considered; (3) the need and reasons for construction of the transmission line and associated facilities; (4) the estimated construction cost; (5) the method of financing and reasonable alternative methods of financing, including the comparative merits and demerits of each alternative financing method; (6) the projected economic and financial impact on the applicant and the local community; (7) the estimated effects on energy costs to the consumer; (8) an environmental impact statement setting forth the environmental impact, any adverse environmental effects that cannot be avoided, a statement of the reasons why the proposed location and production processes were chosen over the identified alternatives, and any irreversible and irretrievable commitments of resources that would be involved in the proposed construction; (9) if the facilities are to be located within a national interest electric transmission corridor, the expected interstate benefits to be achieved by the proposed transmission line and associated facilities; and (10) such other information of an economic or environmental nature that the applicant may consider relevant. 12 Applicants seeking to construct transmission lines and related facilities in a national interest electric transmission corridor are also required to submit a discussion of the interstate benefits to be achieved by the proposed construction.13 8
Id. at 11.
9
Ark. Code Ann. § 23-18-503(6)(B).
10
Id. §§ 23-3-201(a)(2), 23-18-510(a).
11
Arkansas Public Service Commission Rules of Practice and Procedure § 7.04 (Certificates of Public Convenience and Necessity – Electric Utilities).
12
Ark. Code Ann. § 23-18-511.
13
Id. § 23-18-511(9).
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In approving an application for siting and construction of a major utility facility, the APSC is required to make findings and issue an order determining: (1) the basis of the need for the transmission project; (2) that the transmission line will serve the public interest, convenience, and necessity; (3) the nature of probable environmental impacts; (4) that construction and the location of the proposed transmission line represents an acceptable adverse environmental impact; (5) the nature and extent of probable economic impact of the construction and siting of the proposed transmission line and associated facilities; (6) that the financing method represents an acceptable economic impact; (7) that construction of the proposed project is not inconsistent with the filed and known plans of other electric utilities serving the state; (8) that the energy efficiency of the facility has been given significant weight in the decision-making process; and (9) that the proposed location or route conforms as closely as practicable to applicable state, regional, and local laws.14 For projects proposed in national interest electric transmission corridors, the APSC is also required include in its order an assessment: (1) of the interstate benefits expected to be achieved by the proposed construction or modification of the major electric transmission facility; and (2) that any conditions attached to a certificate for construction or modification of transmission facilities to be located within a national interest electric transmission corridor do not interfere with the reduction of electric transmission congestion in interstate commerce and do not render the project economically infeasible.15 The APSC is required hold a public hearing on an application no sooner than 40 days and no later than 180 days after the filing of the application; and is required to issue an order on the application “as expeditiously as practicable.16 B.
Kansas
Pubilc utilities seeking to construct transmission facilities in Kansas are required to obtain a certificate from the Kansas Corporation Commission (“KCC”) prior to transacting business in Kansas. Under the Kansas Statutes, “[n]o common carrier or public utility. . . shall transact business in the state of Kansas until it shall have obtained a certificate from the [OCC] that public convenience will be promoted by the transaction of said business . . . .”17 Public utilities are defined as (among other things) “all companies for the production, transmission, delivery or furnishing of heat, light, water or power,”18 and the Kansas Statutes addressing the siting of transmission facilities define the term “electric utility” to include “every public utility, as defined by K.S.A. 66-104, which owns, controls, operates or manages any equipment, plant or generating machinery for the production, transmission, delivery or furnishing, of electricity or
14
Id. § 23-18-519(b).
15
Id. §§ 23-18-519(b)(11)–(12).
16
Id. § 23-18-516(a)(1).
17
KSA § 66-131.
18
Id. § 66-104.
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electric power.19 The KCC has relied on these statutory provisions in granting certificates to nonincumbent transmission developers seeking authorization to operate in the state.20 Electric utilities seeking authority for construction of transmission facilities in Kansas are required21 to submit an application to the KCC prior to beginning site preparation or construction, detailing: (1) the proposed location; (2) the names and addresses of the landowners of record whose land is proposed to be acquired in connection with the construction of or is located within 660 feet of the center line of the easement where the line is proposed to be located; and (3) such other information as may be required by the KCC.22 The KCC is required to conduct a public hearing in one of the counties through which the proposed transmission line is expected to traverse within 90 days after receiving an application, to determine the necessity for and reasonableness of the location of the proposed electric transmission line.23 The KCC must issue a final order on the application within 120 days of the filing of the application,24 taking into consideration the benefit to both consumers in Kansas and consumers outside the state, as well as economic development benefits in Kansas.25 C.
Louisiana
Louisiana state law does not require a public utility26 to obtain siting approval from the Louisiana Public Service Commission (“LPSC”) prior to constructing a transmission facility in 19
Id. § 66-1,177(a).
20
See, e.g., In the Matter of the Application of ITC Great Plains, LLC for a Limited Certificate of Public Convenience to Transact the Business of an Electric Public Utility in the State of Kansas, Order Approving Stipulation and Agreement and Addressing Application of Statutes, KCC Docket No. 07-ITCE-380-COC, at para. 35 (June 5, 2007). The KCC has subsequently indicated that will continue to “certify companies seeking to build transmission lines” citing its authority under KSA § 66-131 and other statutory provisions. See, e.g., In the Matter of the Application of ITC Great Plains, LLC to Amend Its Certificate of Public Convenience and Authority to Transact the Business of an Electric Public Utility in the State of Kansas (Ford, Kiowa, Clark and Comanche Counties), Order Granting Joint Motion to Approve Stipulation and Agreement and Denying CURB‟s Objection, Kansas Corporation Commission Docket Nos. 08-ITCE-936COC, et al., at para. 74 (Oct. 5, 2009)
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The Kansas Siting Act does not apply to: (1) portions of any electric transmission line to be constructed on an easement where there currently exists one or more electric transmission lines if the easement is not within the corporate limits of any city; (2) portions of any electric transmission line to be constructed on property adjacent to a right-of-way along a four-lane controlled access highway; or (3) any electric utility that complies with the provisions of the National Environmental Policy Act of 1969 regarding the siting of electric transmission lines. KSA § 66-1,182.
22
Id. § 66-1,178(a).
23
Id. § 66-1,178(b).
24
Id. § 66-1,178(d).
25
Id. § 66-1,180. The KCC may issue or withhold the permit or condition the permit to protect the rights of all parties and the general public. Id.
26
The term electric public utility refers to any person furnishing electric service within Louisiana, the parish of Orleans excepted, including any electric cooperative transacting business in this state. La. Rev. Stat. Ann. § 45:121.
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the state, and, while state courts have determined that the LPSC has broad “plenary” authority over electric utilities,27 the LPSC has not issued regulations requiring utilities to seek approval for transmission siting.28 However, construction of electric public utility facilities is limited by the statutory “three hundred foot rule,” which indicates that electric public utilities cannot construct or extend facilities, or furnish or offer to furnish electric service, to any point of connection that is being served by another electric public utility or within three hundred feet of an existing electric line of another electric public utility.29 Additionally, public utilities are prohibited from constructing new facilities or extending existing facilities in cities “unless and until the governing authority of the city certifies that public convenience and necessity require the same.”30 Although this requirement remains on the books, in practice the utility has a franchise and no certification takes place. It is rare for a city to certify a new facility. Utilities are required to obtain property or rights-of-way either from landowners through voluntary agreement or eminent domain, which could further involve state and local government agencies in the process. D.
Missouri
The Missouri Public Service Commission (“MoPSC”) is empowered with issuing certificates of convenience and necessity for the construction of electric plants, including electric transmission facilities (“line certificate authority”),31 and for electric utility franchise areas (“area certificate authority”).32 Line certificates may be granted without a local franchise being granted, and area certificates entitle the electric utility to construct transmission lines within the 27
See, e.g., La. Power & Light Co. v. La. Pub. Serv. Comm’n, 609 So. 2d 797, 800 (La. 1992) (citing La. Const. art. IV, § 21(B)).
28
Although there is no current requirement for approval, Docket No. R-26018, In Re: Determination As To Whether the Commission Should Issue A General Order Asserting Jurisdiction Over the Certification Of Utility Transmission Projects And The Determination Of Whether These Projects Are In the Public Interest, has been pending before the LPSC since January 2007.
29
La. Rev. Stat. Ann. § 45:123. Under the statute, “electric line” means both transmission and distribution lines. Id. § 45:123(B). Given that the three hundred foot rule applies to electric service furnished to “points of connection,” it generally does not preclude the building of transmission lines located within three hundred feet of other existing transmission lines.
30
Id. § 33:4406. City approval for extensions of existing facilities are only required where the extension “will cost over two per cent of the rate-making value of the property at the time the extension or addition is made.” Id.
31
Id. § 393.170(1) (“No gas corporation, electrical corporation, water corporation or sewer corporation shall begin construction of a gas plant, electric plant, water system or sewer system without first having obtained the permission and approval of the commission.”). The term “electric plant” includes facilities operated or used for the transmission of electricity. Id. § 386.020(14). An electric corporation is defined as “every corporation, company . . owning, operating, controlling or managing any electric plant.” Id. § 386.020(15).
32
Id. § 393.170(2).
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certificated franchise area without having to obtain separate line certificates or additional approval from the MoPSC. Upon application for a certificate of convenience and necessity, the MoPSC is authorized to grant approval if, after due hearing, it determines that the construction or exercise of the right, privilege, or franchise sought is necessary or convenient for the public service.33 MoPSC may also impose conditions upon the certificate as it may deem reasonable and necessary. 34 The Missouri Revised Statutes do not specify any criteria for the MoPSC to consider or define what is “necessary or convenient,”35 nor do they impose any deadline for MoPSC action on an application. The MoPSC‟s procedural rules outline certain criteria an applicant must include in its application for an area or line certificate. For area certificates, the applicant must include: (1) a statement regarding other similar utility service provided in the area; (2) information regarding the identity of landowners and residents in the proposed franchise area; (3) a legal description of the area to be certificated; (4) a plat of the proposed area; (5) a feasibility study containing plans and specifications for the utility system and estimated cost of the construction of the utility system during the first three years of construction; (6) plans for financing; and (7) proposed rates and charges and an estimate of the number of customers, revenues, and expenses during the first three years of operations.36 For line certificates, the MoPSC requires: (1) a description of the route of construction and a list of all electric and telephone lines, railroad tracks, and underground facilities that the proposed construction will cross; (2) construction cost information and specifications; and (3) plans for financing.37 Applications for both area and line certificates also must present facts demonstrating that the granting of the application is required by the public convenience and necessity.38 Missouri statutory provisions do not preclude nonincumbent transmission developers from constructing new transmission facilities but require them to obtain authorization from the MoPSC before constructing such facilities.39 The MoPSC has granted certificates of 33
Id. § 393.170(3).
34
Id.
35
Missouri courts, however, have determined that a finding that a facility or franchise is “necessary and convenient” requires at least a determination that the facility or franchise is “adequate,” which includes assessing the relative experience of competing suppliers of the service. State ex rel. Ozark Elec. Coop. v. Pub. Serv. Comm’n of the State of Mo., 527 S.W.2d 390, 394 (Mo. Ct. App. 1975).
36
Mo. Code Regs. Ann. tit. 4 § 240-3.105(1)(A).
37
Id. § 240-3.105(1)(B).
38
Id. § 240-3.105(1)(E).
39
Section 393.170 RSMo, as interpreted by case law, See State ex rel. Harline v. Public Service Commission of Missouri, 343 S.W.2d 177, 180-83 (Mo. App. K.C.D. 1960); Public Service Commission v. Kansas City Power & Light Company, 31 S.W.2d 67, 71 (Mo. Banc 1930); State ex rel. Utility Consumers Council of Missouri v. Public Service Commission, 562 S.W.2d 688, 690 (Mo. App. St.L.D.1978), cert. denied, 439 U.S. 866, 99 S.Ct. 192, 58 L.Ed.2d 177 (1978).
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convenience and necessity to nonincumbent public utilities for transmission lines in two uncontested dockets considering the applications of IES Utilities, Inc and Westar Generating, Inc.40 Although the issue was not raised in either docket, the Missouri Supreme Court has held that an electrical corporation is not subject to regulation by the MoPSC unless it is offering electricity for public use.41 The issue of the MoPSC to grant certificates of convenience and necessity is a question that has not been addressed in a contested case. In the two uncontested dockets approving the applications for a certificate of convenience and necessity of IES Utilities, Inc. and Westar Generating, Inc., the MoPSC Staff asserted that an interconnection in Missouri with a Missouri regulated utility is enough to satisfy “public use” and result in MoPSC jurisdiction over the proposed line. E.
Nebraska
Nebraska electric service is provided exclusively by public power entities, which must have defined service territories42 and be approved by the Nebraska Power Review Board (“NPRB”).43 Although it is not specifically prohibited for private entities to build transmission facilities in the state, the NPRB‟s approval statutes are designed for applications filed by public power entities, and there is no separate process or criteria for applications filed by private entities. The NPRB has jurisdiction over certain aspects of transmission facility siting, while the Nebraska Public Service Commission (“NPSC”) has jurisdiction over compliance with safety code issues. A utility seeking to construct new transmission facilities in Nebraska is expected to first reach agreement with other affected transmission owners regarding what facilities are needed.44 If an agreement cannot be reached, the matter will be set for hearing before the NPRB. The builder must then seek approval from the NPRB by applying for a certificate of convenience and necessity.45 The NPRB Rules of Practice and Procedure outline the application requirements including: (1) a map showing all transmission and distribution lines within one mile of the proposed facility; (2) a statement of how the applicant will provide service at its “low [sic] overall cost as possible consistent with sound business practices;” and (3) construction cost 40
In the Matter of the Application of IES Utilities, Inc. for a Certificate of Public Convenience and Necessity Authorizing it to Construct, Install, Own, Operate, Control, Manage, and Maintain Electric Transmission Facilities in Clark County, Missouri and Request for Waiver, Missouri Public Service Commission Case No. EA-2002-296, April 18, 2002; and In the Matter of the Application of Westar Generating, Inc. for a certificate of Public Convenience and Necessity Authorizing it to Construct, Install, Own, Operate, Control, Manage, and Maintain Electric Transmission Facilities in Jasper County, Missouri Pursuant to the terms of A July 26, 1999, Agreement for the Construction, Ownership and Operation of a State Line Combined Cycle Generating Facility, Missouri Public Service Commission Case No. EA-2000-153 (consolidated with EA-2000-145), June 13, 2000.
41
State ex rel. Danciger v. PSC of Missouri, 205 S.W. 36 (Mo. 1918).
42
Neb. Rev. Stat. Ann. § 70-1002(1).
43
Id. § 70-1007.
44
Id. § 70-1002.03.
45
Id. § 70-1012. Utilities are not required to apply for certificates to extend facilities within the supplier‟s own service area or within one-half mile outside its service area if all of the other owners of transmission facilities within one-half mile consent to the extension in writing. Id.
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information, whether the cost will be paid in part by any customer, and if so, the amount of the customer‟s contribution.46 The NPRB must schedule a hearing within 60 days (or within not more than 120 days if the applicant requests an extension and demonstrates good cause), and must render its decision within 60 days of the hearing.47 To issue a certificate, the NPRB must determine that the facilities will serve the public convenience and necessity and that the applicant can most economically and feasibly supply the electric service without unnecessary duplication of facilities or operations.48 NPSC approval is required for all transmission lines located outside of incorporated cities where the line crosses a highway or railroad track or is to be located within a certain distance (depending on the voltage of the proposed line) of existing electrical, communication, or railroad signal lines or airports.49 In such instances, the applicant is required to provide maps and engineering specifications regarding the proposed facility.50 F.
New Mexico
The New Mexico Public Utility Act51 excludes entities that engage solely in interstate commerce from the definition of “public utility” and “utility.” 52 The New Mexico Public Regulation Commission (“PRC”) only has jurisdiction over public utilities.53 In addition, the New Mexico Public Utility Act provides that “[t]he business of any public utility other than of the character defined in Subsection G of Section 62-3-3 NMSA 1978 [which defines the retail activities of public utilities] is not subject to provisions of the Public Utility Act.”54 However, the New Mexico Public Utility Act grants the PRC location control authority over 300 MW or more of generation and 230 kV or more of transmission lines in connection with such generation, whether or not owned or operated by a public utility subject to regulation by the 46
285 Neb. Admin. Code § 2-004.
47
Neb. Rev. Stat. § 70-1013.
48
Id. § 70-1014. The NPRB is responsible for approving the siting of transmission facilities but has no jurisdiction over rates. Id. § 70-1002.03.
49
Id. §§ 75-701–724.
50
291 Neb. Admin. Code § 7-002.02.
51
N.M. Stat. Ann. §§ 62-3-1, et seq.
52
Id. § 62-3-3.G (“„[P]ublic utility‟ and „utility‟ means every person not engaged solely in interstate business . . . may own, operate, lease or control: (1) any plant, property or facility for the generation, transmission or distribution, sale or furnishing to or for the public of electricity for light, heat or power or other uses.”).
53
Id. §§ 62-6-4.A.
54
Id. § 62-3-4.
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PRC.55 Thus, there is a process requiring PRC approval for a nonincumbent transmission developer seeking to build an interstate transmission facility of 230 kV or more.56 Unless the Commission finds that the location will unduly impair important environmental values, the Commission is required to approve an application for transmission line location.57 The Public Utility Act lists the criteria the commission may consider in reaching this determination.58 The PRC may approve an application filed without a formal hearing if no protest is filed within sixty days of the date of notice of the application and is required to issue an order within six month from the date the application is filed with the Commission.59 Additionally, unless otherwise agreed to by the parties, the Public Utility Act prohibits any person from beginning the construction of any transmission line requiring a width for right of way of greater than one hundred feet without first obtaining from the Commission a determination of the necessary right of way width to construct and maintain the transmission line.60 In this case, “transmission” is not limited to any threshold voltage. Thus there is a process requiring PRC approval for a nonincumbent transmission developer seeking to build an interstate transmission facility requiring right of way of greater than one hundred feet if width is not agreed to. An application, notice to property owners and hearing are required and the Commission is required to act upon an application within sixty days from the date the application is filed with the Commission or the application is deemed approved.61
55
Id. § 62-3-9.B (“No person, including any municipality, shall begin the construction of any plant designed for or capable of operation at a capacity of three hundred thousand kilowatts or more for the generation of electricity for sale to the public within or without this state, whether or not owned or operated by a person that is a public utility subject to regulation by the commission, or of transmission lines in connection with such plant, on a location within this state unless the location has been approved by the commission. For purposes of this section, „transmission line‟ means any electric transmission line and associated facilities designed for or capable of operations at a nominal voltage of two hundred thirty kilovolts or more, to be constructed in connection with and to transmit electricity from a new plant for which approval is required.”)‟
56
Id.
57
Id. § 62-3-9(F).
58
Id. § 62-3-9(M).
59
Id. § 62-3-9(K).
60
Id. § 62-9-3.2(A).
61
Id. §§ 62-9-3.2(D), (E) and (F).
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With regard to public utilities regulated by the PRC, a certificate from the PUC is required prior to construction of “any public utility plant or system” outside that utility‟s service territory.62 The PRC is required to act on an application for a certificate of public convenience and necessity and a location permit within nine months of submission of the application, but may grant itself a six-month extension for good cause shown.63 Utilities are required to comply with all local permitting requirements; however, if the local authority does not act within 240 days or does not approve the permit application, the applicant may file for approval with the PRC.64 The PRC cannot approve a permit for a project that violates existing state, county, or municipal land use statutes or administrative regulations unless the PRC finds that the regulation is unreasonably restrictive and compliance with the regulation is not in the interest of the public convenience and necessity.65 G.
Oklahoma
The Oklahoma Corporation Commission (“OCC”) is a body of limited jurisdiction, with regulatory powers and responsibilities regarding public utilities.66 Oklahoma Statutes do not require nonincumbent transmission developers to obtain certification or approval prior to developing and building transmission facilities in Oklahoma. The Oklahoma Statutes also do not require that a nonincumbent entity first obtain authorization from the OCC to operate as a public utility.67 In 2008, in reviewing a request by a nonincumbent transmission developer for authority to operate as a transmission-only electric utility, the OCC adopted Administrative Law Judge (“ALJ”) findings that the nonincumbent transmission developer was not required to obtain OCC approval “to start constructing, owning, operating, and maintaining transmission facilities in Oklahoma.”68 The nonincumbent transmission developer did “not have an obligation to demonstrate that there will be a significant public benefit prior to its application being granted.”69 However, the OCC‟s decision in that case does not have precedential effect, 70 and 62
Id. § 62-9-1.
63
Id. §§ 62-9-1(C) and 62-9-3(K).
64
Id. § 62-9-3(H).
65
Id. § 62-9-3(G).
66
Okla. Const. Art. 9, §§ 18 and 34, and Okla. Stat. Tit. 17 § 152. “Public utilities include entities that “now or hereafter may own, operate, or manage any plant of equipment, or any part thereof, directly or indirectly, for public use, or may supply any commodity to be furnished to the public . . . (c) For the production, transmission, delivery or furnishing electric current for light, heat or power.” Okla. Stat. Tit. 17. § 151(c).
67
However, retail electric suppliers are allocated and restricted to specific territories and consumers in furnishing electric service, pursuant to the Retail Electric Supplier Certified Territory Act. Okla. Stat. Tit. 17 §§ 158.21 et seq. In addition, public utilities selling power in the retail market, must have approved tariffs. Okla. Stat. Tit. 17, § 152 and Okla. Admin. Code 165:35-5-1.
68
See In the Matter of the Application of ITC Great Plains, LLC to Conduct Business as an Electric Public Utility in the State of Oklahoma, Cause No. PUD 200700298, Final Order, Report and Recommendation of the Administrative Law Judge, at 9 (Okla. Corp. Comm‟n Sept. 11, 2008) (“ITC Great Plains Oklahoma Order”)
69
Id.
14
the sitting Commission members as of late October 2001 are/were deliberating a subsequent case brought by a non-incumbant transmission developer.71 Additionally, the OCC does not oversee the siting of transmission facilities in the state. Under Oklahoma law, companies authorized to furnish electricity service in the state have the same right of eminent domain as applies to railroads operating in the state.72 A party seeking to exercise eminent domain must petition the district court for the district in which the property is located,73 and must include in its petition a statement indicating: (i) that it is authorized to exercise the power of eminent domain and it has been unable to make a voluntary purchase of the property or right-of-way in question; (ii) the owner of the property and the specific property in question; and (iii) that the specific property sought to be taken is necessary for a purpose for which the power of eminent domain may be exercised, (i.e., a public purpose and for public use).74 Additionally, the OCC also has adopted ALJ findings that “no determination by the [OCC] that additional transmission capacity is needed in Oklahoma is required, prior to any company building transmission lines in Oklahoma.”75 In 2010, the Oklahoma Legislature by statute declared the Legislature and OCC shall work with SPP to develop plans to expand transmission capacity in Oklahoma and to monitor construction of new transmission facilities in Oklahoma, indicating the State has not ceded any of its authority in this area to SPP and will participate in the process.76 H.
Texas
Texas does not limit construction of transmission facilities to existing electric utilities; however, the Public Utility Regulatory Act (“PURA”) requires that “an electric utility or other person may not directly or indirectly provide service . . . unless the utility or other person first obtains from the [Public Utilities Commission of Texas] a certificate.”77 The Public Utilities (. . . continued) 70
Okla. Stat. Tit. 75, § 302(C).
71
In the Matter of the Application of Plains and Eastern Clean Line, LLC, to Conduct Business as an Electric Utility in the State of Oklahoma, Cause No. PUD 201000075.
72
Okla. Stat., tit. 27, § 7.
73
Id. at tit. 66, § 53.
74
See, e.g., McCrady v. W. Farmers Elec. Coop., 323 P.2d 356, 359 (Okla. 1958). “Necessity” has been determined by the Oklahoma Supreme Court to be “reasonable necessity” as opposed to “absolute” necessity. See Pub. Serv. Co. of Okla. v. Willis, 941 P.2d 995, 1000 (Okla. 1997).
75
See ITC Great Plains Oklahoma Order, Report and Recommendation of the Administrative Law Judge, at 11.
76
Okla. Stat., titl 17 §287
77
Tex. Util. Code Ann. § 37.051(a).
15
Commission of Texas (“PUCT”) will issue a certificate “only if the commission finds that the certificate is necessary for the service, accommodation, convenience, or safety of the public.”78 Utilities are not required to obtain a certificate for: (1) extensions into contiguous territories that do not receive similar service from another electric utility and are not in another electric utility‟s certificated area; (2) extension in or to territory that the utility serves or is authorized to serve; or (3) operation, extension, or service in progress on September 1, 1975.79 Moreover, an entity does not need to be an electric utility with a defined service area, or even already a utility, to be eligible for a certificate of convenience and necessity to construct or acquire transmission facilities.80 In reviewing a certificate application, the PUCT considers: (1) the adequacy of existing service; (2) the need for additional service; (3) the effect of granting the certificate on the recipient and any electric utility service in the proximate area; (4) impacts to community values, recreation and park areas, historic and aesthetic values, and environmental integrity; (5) the probable improvement of service or lowering of costs to consumers; and (6) the effect of granting the certificate on the ability of the state to meet renewable energy goals. 81 Under its Substantive Rules, the PUCT also considers the needs of the interconnected transmission system to support a reliable and adequate network and to facilitate robust wholesale competition, and gives “great weight” to recommendations from “essential organizations” (i.e., independent system operators) or written documentation that the proposed facility is needed to connect a new transmission service customer.82 PUCT transmission line routing decisions are based on whether the proposed route: (1) utilizes existing compatible rights-of-way, including vacant positions on existing multiple-circuit transmission lines; (2) parallels existing compatible rights-of-way; (3) parallels property lines or other natural or cultural features; and (4) conforms with the policy of prudent avoidance, which seeks to limit exposure to electric and magnetic fields.83 The PUCT is required to render its certificate decision within one year of the application;84 however, the PUCT has reserved the right to extend the one-year period for good cause.85 Projects that have been formally designated by an “essential organization” as critical for 78
Id. § 37.056(a); see also 16 Tex. Admin. Code § 25.101(b).
79
Tex. Util. Code Ann. § 37.052(a). Extensions of service are only allowed to interconnect to existing facilities or solely to transmit electric utility services from an existing facility to a customer of retail electric utility service. Id. § 37.052(b).
80
Pub. Utils. of Tex. v. City of Harlingen, 311 S.W.3d 610, 617 (Tex. App. Austin 2010) (“[T]he Commission has been given the power to approve a [certificate of convenience and necessity] for a utility that provides only transmission services, provided that such services meet the applicable standards.”).
81
Tex. Util. Code Ann. § 37.056(c).
82
PUCT Subst. R. § 25.101(b)(3)(A).
83
Id. § 25.101(b)(3)(B). otherwise. Id.
84
Tex. Util. Code Ann. § 37.057.
85
PUCT Subst. R. § 25.101(b).
These considerations are tempered where grid reliability or security dictate
16
the reliability of the transmission system must be considered on an expedited basis, with the PUCT issuing a decision within 180 days of receiving a completed application.86 Expedited proceedings are also afforded to transmission lines serving “competitive renewable energy zones” designated by the PUCT87 and to uncontested applications.88
6. CONCLUSION As part of its filing to comply with the nonincumbent developer participation requirements of Order No. 1000, specifically, the elimination of federal ROFR for incumbent transmission owners to construct transmission facilities selected in the regional transmission plan for cost allocation, SPP must be mindful of the requirements and limitations on construction of transmission facilities imposed by state statutes and regulations in the SPP Region. Because FERC expressly indicated that its Order No. 1000 mandate was not intended to affect state or local laws with governing construction, siting, and permitting of transmission facilities, and many states in the SPP Region impose some limitations on construction and siting, SPP should consider consulting with its Regional State Committee in determining the most appropriate approach to complying with the Order No. 1000 nonincumbent transmission developer participation requirement.
86
Id. § 25.101(b)(3)(D).
87
Tex. Util. Code Ann. § 39.203(e).
88
PUCT Subst. R. § 25.101(b)(3)(C). The PUCT must act on an uncontested application that is complete and meets all filing criteria within 80 days of filing.
17
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff the time, and is not intended to affect any rights provided under Existing Contracts or TORs. The CAISO’s forecast of Total Transfer Capability for each Balancing Authority Area Transmission Interface will depend on prevailing conditions for the relevant Trading Day, including, but not limited to, the effects of parallel path (unscheduled) flows and/or other limiting operational conditions. This information will be posted on OASIS in accordance with this CAISO Tariff. The four categories are as follows: (a)
transmission capacity that must be reserved for firm Existing Rights;
(b)
transmission capacity that may be allocated for use as CAISO transmission service (i.e., "new firm uses");
(c)
transmission capacity that may be allocated by the CAISO for conditional firm Existing Rights; and
(d)
transmission capacity that may remain for any other uses, such as non-firm Existing Rights for which the Responsible PTO has no discretion over whether or not to provide such non-firm service.
24.
Comprehensive Transmission Planning Process
24.1
Overview
The CAISO will develop a comprehensive Transmission Plan and approve transmission upgrades or additions using the Transmission Planning Process set forth in this Section 24. The CAISO will analyze the need for transmission upgrades and additions in accordance with the methodologies and criteria set forth in this Section 24, the Transmission Control Agreement, and the applicable Business Practice Manuals. The comprehensive Transmission Plan will identify transmission upgrade or addition projects associated with Approved Project Sponsors that are Merchant Transmission Facilities or are needed: (1) to maintain System Reliability; (2) to satisfy the requirements of a Location Constrained Resource Interconnection Facility; (3) to maintain the simultaneous feasibility of allocated Long-Term CRRs; and (4) as LGIP Network Upgrades identified pursuant to Section 24.4.6.5. The comprehensive Transmission Plan will identify transmission addition and upgrade elements with no approved Project Sponsors needed to (1) meet state and federal policy requirements and directives that are not inconsistent with the Federal Power Act, including renewable portfolio standards policies; and (2) reduce congestion costs, production supply costs, transmission losses, or other electric supply costs resulting from improved access to cost-
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff effective resources. For purposes of this Section 24, the term “the year X/(X+1) planning cycle” will refer to the Transmission Planning Process initiated during year X to complete a comprehensive Transmission Plan in year X+1. 24.1.1
[NOT USED]
24.1.2
[NOT USED]
24.1.3
[NOT USED]
24.1.4
[NOT USED]
24.2
Nature of the Transmission Planning Process
The CAISO will develop the annual comprehensive Transmission Plan and approve transmission upgrades or additions using a shall perform the CAISO’s Transmission Planning Process with three (3) phases. In Phase 1, the CAISO will develop and complete the Unified Planning Assumptions and Study Plan and, in parallel, begin development of a conceptual statewide plan. In Phase 2, the CAISO will complete the comprehensive Transmission Plan. In Phase 3, the CAISO will evaluate proposals to construct and own specific transmission upgrade or addition elements specified in the comprehensive Transmission Plan on an annual cycle in accordance with the terms of this CAISO Tariff, the Transmission Control Agreement, and the Business Practice Manual. The Transmission Planning Process shall, at a minimum: (a)
Coordinate and consolidate in a single plan the transmission needs of the CAISO Balancing Authority Area for into a single plan, which will be assessed on the basis of maintaining the reliability of the CAISO Controlled Grid in accordance with Applicable Reliability Criteria and CAISO Planning Standards, in a manner that promotes the economic efficiency of the CAISO Controlled Grid and considers federal and state environmental and other policies affecting the provision of Energy.
(b)
Reflect a planning horizon covering a minimum of ten (10) years that considers previously approved transmission upgrades and additions transmission enhancements and expansions, Demand Forecasts, Demand-side management,
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff and capacity forecasts relating to generation technology type, additions and retirements, and such other factors as the CAISO determines are relevant. (c)
Seek to avoid unnecessary duplication of facilities and ensure the simultaneous feasibility of the CAISO Transmission Plan and the transmission plans of interconnected Balancing Authority Areas, and otherwise coordinate with regional and sub-regional transmission planning processes and entities, including interconnected Balancing Authority Areas. in accordance with Section 24.8.
(d)
Identify existing and projected limitations of the CAISO Controlled Grid’s physical, economic or operational capability or performance and identify transmission upgrades and additions, including alternatives thereto, deemed needed in accordance with Section 24.1 to address the existing and projected limitations.
(e)
Account for any effects on the CAISO Controlled Grid of the interconnection of Generating Units on the Distribution System under the Wholesale Distribution Access Tariffs of the Participating TOs, including an assessment of the deliverability of such Generating Units in a manner consistent with CAISO interconnection procedures. on a basis comparable to the Deliverability Assessment performed under Appendix U or Appendix Y, as applicable
24.2.1
[NOT USED]
24.2.2
[NOT USED]
24.2.3
[NOT USED]
24.2.4
[NOT USED]
24.2.5
[NOT USED]
24.3
Transmission Planning Process Phase 1
Phase 1 consists of two (2) parallel processes: (1) the development of the Unified Planning Assumptions and Study Plan; and, (2) initiation of the development of the statewide conceptual transmission plan, as discussed in Section 24.4.4. 24.3.1
Inputs to the Unified Planning Assumptions and Study Plan
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff The CAISO will develop Unified Planning Assumptions and a Study Plan using information and data from the approved Transmission Plan developed in the previous planning cycle. The CAISO will consider the following in the development of the Unified Planning Assumptions and Study Plan: (a)
WECC base cases, as may be modified for the relevant planning horizon;
(b)
Transmission upgrades and additions approved by the CAISO in past Transmission Planning Process cycles, including upgrades and additions which the CAISO has determined address transmission elements in comprehensive Transmission Plan developed in the previous planning cycle;
(c)
Category 2 policy-driven transmission upgrade and addition elements from a prior planning cycle as described in Section 24.4.6.6;
(d)
Location Constrained Resource Interconnection Facilities conditionally approved under Section 24.4.6.3;
(e)
Network Upgrades identified pursuant to Section 25, Appendix U, Appendix V, Appendix Y or Appendix Z relating to the CAISO’s Large Generator Interconnection Procedures and Appendices S and T relating to the CAISO’s Small Generator Interconnection Procedures that were not otherwise included in the comprehensive Transmission Plan from the previous annual cycle;
(f)
Operational solutions validated by the CAISO in the Local Capacity Technical Study under Section 40.3.1;
(g)
Policy requirements and directives, as appropriate, including programs initiated by state and federal regulatory agencies;
(h)
Energy Resource Areas or similar resource areas identified by Local Regulatory Authorities;
(i)
Demand response programs that are proposed for inclusion in the base case or assumptions for the comprehensive Transmission Plan;
(j)
Generation and other non-transmission projects that are proposed for inclusion in long-term planning studies as alternatives to transmission additions or upgrades;
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff (k)
Beginning with the 2011/2012 planning cycle, Economic Planning Study requests submitted in comments on the draft Unified Planning Assumptions and Study.
(l) 24.3.2
Planned facilities in interconnected Balancing Authority Areas.
Contents of the Unified Planning Assumptions and Study Plan
The Unified Planning Assumptions and Study Plan shall, at a minimum, provide: (a)
The planning data and assumptions to be used in the Transmission Planning Process cycle, including, but not limited to, those related to Demand Forecasts and distribution, potential generation capacity additions and retirements, and transmission system modifications;
(b)
A description of the computer models, methodology and other criteria used in each technical study performed in the Transmission Planning Process cycle;
(c)
A list of each technical study to be performed in the Transmission Planning Process cycle and a summary of each technical study’s objective or purpose;
(d)
A description of significant modifications to the planning data and assumptions as allowed by Section 24.3.1(a) and consistent with Section 24.3.2;
(e)
The identification of any entities directed to perform a particular technical study or portions of a technical study;
(f)
A proposed schedule for all stakeholder meetings to be held as part of the Transmission Planning Process cycle and the means for notification of any changes thereto, the location on the CAISO Website of information relating to the technical studies performed in the Transmission Planning Process cycle, and the name of a contact person at the CAISO for each technical study performed in the Transmission Planning Process cycle;
(g)
To the maximum extent practicable, and where applicable, appropriate sensitivity analyses, including project or solution alternatives, to be performed as part of technical studies;
(h)
Descriptions of the High Priority Economic Planning Studies as determined by the CAISO under section 24.3.5; and
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff (i)
Identification of state or federal requirements or directives that the CAISO will utilize, pursuant to Section 24.4.6.6, to identify policy-driven transmission elements.
24.3.3
Stakeholder Input - Unified Planning Assumptions/Study Plan (a)
Beginning with the 2011/2012 planning cycle and in accordance with the schedule set forth in the Business Practice Manual, the CAISO will provide a comment period during which Market Participants, electric utility regulatory agencies and all other interested parties may submit the following proposals for consideration in the development of the draft Unified Planning Assumptions and Study Plan: (i)
Demand response programs for inclusion in the base case or assumptions; and
(ii)
Generation and other non-transmission alternatives, consistent with Section 24.3.2(a) proposed as alternatives to transmission additions or upgrades.
(b)
Following review of relevant information, including stakeholder comments submitted pursuant to Section 24.3.3(a), the CAISO will prepare and post on the CAISO Website a draft of the Unified Planning Assumptions and Study Plan. The CAISO will issue a Market Notice announcing the availability of such draft, soliciting comments, and scheduling a public conference(s) as required by Section 24.3.3(c).
(c)
No less than one (1) week subsequent to the posting of the draft Unified Planning Assumptions and Study Plan, the CAISO will conduct a minimum of one (1) public meeting open to Market Participants, electric utility regulatory agencies, and other interested parties to review, discuss, and recommend modifications to the draft Unified Planning Assumptions and Study Plan. Additional meetings, web conferences, or teleconferences may be scheduled as needed. All
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff stakeholder meetings, web conferences, or teleconferences shall be noticed by Market Notice. (d)
Interested parties will be provided a minimum of two (2) weeks following the first public meeting to provide comments on the draft Unified Planning Assumptions and Study Plan. Such comments may include Economic Planning Study requests based on the comprehensive Transmission Plan from the prior cycle. All comments on the draft Unified Planning Assumptions and the Study Plan will be posted by the CAISO to the CAISO Website.
(e)
Following the public conference(s), and under the schedule set forth in the Business Practice Manual, the CAISO will determine and publish to the CAISO Website the final Unified Planning Assumptions and Study Plan in accordance with the procedures set forth in the Business Practice Manual. The CAISO will post the base cases to be used in the technical studies to its secured website as soon as possible after the final Unified Planning Assumptions and Study Plan have been published.
24.3.4
Economic Planning Studies
24.3.4.1
CAISO Assessment of Requests for Economic Planning Studies
Following the submittal of a request for an Economic Planning Study, the CAISO will determine whether the request shall be designated as a High Priority Economic Planning Study for consideration in the development of the comprehensive Transmission Plan. In making the determination, the CAISO will consider: (a)
Whether the requested Economic Planning Study seeks to assess Congestion not identified or identified and not mitigated by the CAISO in previous Transmission Planning Process cycles;
(b)
Whether the requested Economic Planning Study addresses delivery of Generation from Location Constrained Resource Interconnection Generators or network transmission facilities intended to access Generation from an Energy
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff Resource Area or similar resource area assigned a high priority by the CPUC or CEC; (c)
Whether the requested Economic Planning Study is intended to address Local Capacity Area Resource requirements;
(d)
Whether resource and Demand information indicates that Congestion described in the Economic Planning Study request is projected to increase over the planning horizon used in the Transmission Planning Process and the magnitude of that Congestion; or
(e)
Whether the Economic Planning Study is intended to encompass the upgrades necessary to integrate new generation resources or loads on an aggregated or regional basis.
24.3.4.2
Selection of High Priority Economic Planning Studies
In accordance with the schedule and procedures set forth in the Business Practice Manual, the CAISO will post to the CAISO Website the list of selected High Priority Economic Planning Studies to be included in the draft Unified Planning Assumptions and Study Plan. The CAISO may assess requests for Economic Planning Studies individually or in combination where such requests may have common or complementary effects on the CAISO Controlled Grid. As appropriate, the CAISO will perform requested High Priority Economic Planning Studies, up to five (5); however, the CAISO retains discretion to perform more than five (5) High Priority Economic Planning Studies should stakeholder requests or patterns of Congestion or anticipated Congestion so warrant. Market Participants may, consistent with Section 24.3.1 and 24.3.2, conduct Economic Planning Studies that have not been designated as High Priority Economic Planning Studies at their own expense and may submit such studies for consideration in the development of the comprehensive Transmission Plan. 24.4
Transmission Planning Process Phase 2
24.4.1
Conducting Technical Studies (a)
In accordance with the Unified Planning Assumptions and Study Plan and with the procedures and deadlines in the Business Practice Manual, the CAISO will perform, or direct the performance by third parties of, technical studies and other
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff assessments necessary to develop the comprehensive Transmission Plan, including such technical studies and other assessments as are necessary in order to determine whether and how to include elements from the conceptual statewide transmission plan or other alternative elements identified by the CAISO during the Phase 2 studies in the comprehensive Transmission Plan. According to the schedule set forth in the applicable Business Practice Manual, the CAISO will post the preliminary results of its technical studies and proposed mitigation solutions on the CAISO Website. The CAISO’s technical study results and mitigation solutions shall be posted not less than one-hundred and twenty (120) days after the final Unified Planning Assumptions and Study Plan are published, along with the results of the technical studies conducted by Participating TOs or other third parties at the direction of the CAISO. (b)
All technical studies, whether performed by the CAISO, the Participating TOs or other third parties under the direction of the CAISO, must utilize the Unified Planning Assumptions for the particular technical study to the maximum extent practical, and deviations from the Unified Planning Assumptions for the particular technical study must be documented in results of each technical study. The CAISO will measure the results of the studies against Applicable Reliability Criteria, the CAISO Planning Standards, and other criteria established by the Business Practice Manual. After consideration of the comments received on the preliminary results, the CAISO will complete, or direct the completion of, the technical studies and post the final study results on the CAISO Website.
(c)
The CAISO technical study results will identify needs and proposed solutions to meet Applicable Reliability Criteria, CAISO planning standards, and other applicable planning standards. The CAISO and Participating TOs shall coordinate their respective transmission planning responsibilities required for compliance with the NERC Reliability Standards and for the purposes of
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff developing the annual Transmission Plan according to the requirements and time schedules set forth in the Business Practice Manual. 24.4.2
Submission of Reliability Driven Projects
Pursuant to the schedule described in the Business Practice Manual and based on the technical study results, the CAISO, CEC, CPUC, and other interested parties may propose any transmission upgrades or additions deemed necessary to ensure System Reliability consistent with Applicable Reliability Criteria and CAISO Planning Standards through the Phase 2 Request Window. Participating TOs will submit such project proposals through the Phase 2 Request Window within thirty (30) days after the CAISO posts its preliminary technical study results. The substantive description of reliability driven projects is set forth in Section 24.4.6.2. 24.4.3
Phase 2 Request Window (a)
Following publication of the results of the technical studies, and in accordance with the schedule set forth in the Business Practice Manual, the CAISO will open a Request Window during Phase 2 for the submission of proposals for reliabilitydriven projects, Location Constrained Resource Interconnection Facility projects, demand response or generation proposals proposed as alternatives to transmission additions or upgrades to meet reliability needs, and proposals for Merchant Transmission Facility projects and projects needed to maintain the feasibility of long-term CRRs.
(b)
All facilities proposed during the Request Window must use the forms and satisfy the information and technical requirements set forth in the Business Practice Manual. Proposals for these transmission additions or upgrades must be within or connect to the CAISO Balancing Authority Area or CAISO Controlled Grid. The CAISO will determine whether each of these proposals will be considered in the development of the comprehensive Transmission Plan. In accordance with the schedule and procedures set forth in the Business Practice Manual, the CAISO will notify the party submitting the proposal of any deficiencies in the proposal and provide the party an opportunity to correct the deficiencies. A
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff proposal can only be considered in the development of the comprehensive Transmission Plan if the CAISO determines that: (i)
the proposal satisfies the information requirements for the particular type of project submitted as set forth in templates included in the Business Practice Manual;
(ii)
the proposal is not functionally duplicative of transmission upgrades or additions that have previously been approved by the CAISO; and
(iii)
the proposal, if a sub-regional or regional project that affects other interconnected Balancing Authority Areas, has been reviewed by the appropriate sub-regional or regional planning entity, is not inconsistent with such sub-regional or regional planning entity’s preferred solution or project, and has been determined to be appropriate for inclusion in the CAISO Study Plan, rather than, or in addition to, being included in or deferred to the planning process of the sub-regional or regional planning entity.
(c)
The duration of the Request Window will be set forth in the Business Practice Manual.
24.4.4
Comment Period of Conceptual Statewide Plan
Beginning in Phase 1, the CAISO will develop, or, in coordination with other regional or sub-regional transmission planning groups or entities, including interconnected Balancing Authority Areas, will participate in the development of a conceptual statewide transmission plan that, among other things, may identify potential transmission upgrade or addition elements needed to meet state and federal policy requirements and directives. The conceptual statewide transmission plan will be an input into the CAISO’s Transmission Planning Process. The CAISO will post the conceptual statewide transmission plan to the CAISO Website and will issue a Market Notice providing notice of the availability of such plan. In the month immediately following the publication of the conceptual statewide transmission plan, the CAISO will provide an opportunity for interested parties to submit comments and recommend modifications to the conceptual statewide transmission plan and alternative transmission elements,
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff including potential interstate transmission lines and proposals for access to resources located in areas not identified in the conceptual statewide transmission plan, and non-transmission elements. 24.4.5
Determination of Needed Transmission Projects and Elements
To determine which projects and additional elements should be included in the comprehensive Transmission Plan, the CAISO will evaluate the conceptual transmission elements identified in the statewide conceptual transmission plan or other alternative elements identified by the CAISO during the Phase 2 studies, reliability project proposals, LCRIF projects proposals, project proposals required to maintain the feasibility of long term CRRs, proposed Network Upgrades pursuant to Section 24.4.6.5 and the results of Economic Planning Studies or other economic studies the CAISO has performed and will consider potential alternative transmission upgrade and addition elements and non-transmission or generation solutions proposed by interested parties. In determining which projects and additional elements should be included in the comprehensive Transmission Plan, the CAISO will not give undue weight or preference to the conceptual statewide plan or any other input in its planning process. 24.4.6
Categories of Transmission Projects
24.4.6.1
Merchant Transmission Project Proposals
The CAISO may include a transmission addition or upgrade in the comprehensive Transmission Plan if a Project Sponsor proposes a Merchant Transmission Facility and demonstrates to the CAISO the financial capability to pay the full cost of construction and operation of the Merchant Transmission Facility. The Merchant Transmission Facility must mitigate all operational concerns identified by the CAISO to the satisfaction of the CAISO, in consultation with the Participating TO(s) in whose PTO Service Territory the Merchant Transmission Facility will be located, and ensure the continuing feasibility of allocated Long Term CRRs over the length of their terms. To ensure that the Project Sponsor is financially able to pay the construction and operating costs of the Merchant Transmission Facility, and where the Participating TO is not the Project Sponsor and is to construct the Merchant Transmission Facility under Section 24.4.1, the CAISO in cooperation with the Participating TO may require (1) a demonstration of creditworthiness (e.g., an appropriate credit rating), or (2) sufficient security in the form of an unconditional and irrevocable letter of credit or other similar security sufficient to meet its responsibilities and obligations for the full costs of the transmission addition or upgrade.
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff 24.4.6.2
Reliability Driven Projects
The CAISO, in coordination with each Participating TO with a PTO Service Territory will, as part of the Transmission Planning Process and consistent with the procedures set forth in the Business Practice Manual, identify the need for any transmission additions or upgrades required to ensure System Reliability consistent with all Applicable Reliability Criteria and CAISO Planning Standards. In making this determination, the CAISO, in coordination with each Participating TO with a PTO Service Territory and other Market Participants, shall consider lower cost alternatives to the construction of transmission additions or upgrades, such as acceleration or expansion of existing projects, Demand-side management, Remedial Action Schemes, appropriate Generation, interruptible Loads or reactive support. The CAISO shall direct each Participating TO with a PTO Service Area, as a registered Transmission Planner with NERC, to perform the necessary studies, based on the Unified Planning Assumptions and Study Plan and any applicable Interconnection Study, and in accordance with the Business Practice Manual, to determine the facilities needed to meet all Applicable Reliability Criteria and CAISO Planning Standards. The Participating TO with a PTO Service Area shall provide the CAISO and other Market Participants with all information relating to the studies performed under this Section, subject to any limitation provided in Section 20.2 or the applicable LGIP. The Participating TO with a PTO Service Territory in which the transmission upgrade or addition deemed needed under this Section 24 will have the responsibility to construct, own and finance, and maintain such transmission upgrade or addition. 24.4.6.3
LCRIF Projects
24.4.6.3.1
Proposals for LCRIFs
The CAISO, CPUC, CEC, a Participating TO, or any other interested parties may propose a transmission addition as a Location Constrained Resource Interconnection Facility. A proposal shall include the following information, to the extent available: (a)
Information showing that the proposal meets the requirements of Section 24.4.6.3.2; and
(b)
A description of the proposed facility, including the following information: (1)
Transmission studies demonstrating that the proposed facility satisfies Applicable Reliability Criteria and CAISO Planning Standards;
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff (2)
Identification of the most feasible and cost-effective alternative transmission additions, which may include network upgrades, that would accomplish the objective of the proposal;
(3)
A planning level cost estimate for the proposed facility and all proposed alternatives;
(4)
An assessment of the potential for the future connection of further transmission additions that would convert the proposed facility into a network transmission facility, including conceptual plans;
(5)
The estimated in-service date of the proposed facility; and
(6)
A conceptual plan for connecting potential LCRIGs, if known, to the proposed facility.
24.4.6.3.2
Criteria for Qualification as a LCRIF (a)
The CAISO shall conditionally approve a facility as a Location Constrained Resource Interconnection Facility if it determines that the facility is needed and all of the following requirements are met: (1)
The facility is to be constructed for the primary purpose of connecting to the CAISO Controlled Grid two (2) or more Location Constrained Resource Interconnection Generators in an Energy Resource Area, and at least one of the Location Constrained Resource Interconnection Generators is to be owned by an entity(ies) that is not an Affiliate of the owner(s) of another Location Constrained Resource Interconnection Generator in that Energy Resource Area;
(2)
The facility will be a High Voltage Transmission Facility;
(3)
At the time of its in-service date, the facility will not be a network facility and would not be eligible for inclusion in a Participating TO’s TRR other than as an LCRIF; and
(4)
The facility meets Applicable Reliability Criteria and CAISO Planning Standards.
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff (b)
The proponent of a facility that has been determined by the CAISO to meet the requirements of Section 24.4.6.3.2(a) shall provide the CAISO with information concerning the requirements of this subsection not less than ninety (90) days prior to the planned commencement of construction, and the facility shall qualify as a Location Constrained Resource Interconnection Facility if the CAISO determines that both of the following requirements are met: (1)
The addition of the capital cost of the facility to the High Voltage TRR of a Participating TO will not cause the aggregate of the net investment of all LCRIFs (net of the amount of the capital costs of LCRIFs to be recovered from LCRIGs pursuant to Section 26.6) included in the High Voltage TRRs of all Participating TOs to exceed fifteen (15) percent of the aggregate of the net investment of all Participating TOs in all High Voltage Transmission Facilities reflected in their High Voltage TRRs (net of the amount of the capital costs of LCRIFs to be recovered from LCRIGs pursuant to Section 26.6) in effect at the time of the CAISO’s evaluation of the facility; and
(2)
Existing or prospective owners of LCRIGs have demonstrated their interest in connecting LCRIGs to the facility consistent with the requirements of Section 24.4.6.3.4, which establishes the necessary demonstration of interest.
24.4.6.3.3
Responsibilities of Participating Transmission Owner
Each Participating TO shall report annually to the CAISO the amount of its net investment in LCRIFs (net of the amount of the capital costs of LCRIFs to be recovered from LCRIGs pursuant to Section 26.6), and its net investment in High Voltage Transmission Facilities reflected in its High Voltage TRR (net of the amount of the capital costs of LCRIFs to be recovered from LCRIGs pursuant to Section 26.6), to enable the CAISO to make the determination required under Section 24.4.6.3.2(b)(1). 24.4.6.3.4
Demonstration of Interest in a LCRIF
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff A proponent of an LCRIF must demonstrate interest in the LCRIF equal to sixty (60) percent or more of the capacity of the facility in the following manner: (a)
the proponent’s demonstration must include a showing that LCRIGs that would connect to the facility and would have a combined capacity equal to at least twenty-five (25) percent of the capacity of the facility have executed Large Generator Interconnection Agreements or Small Generator Interconnection Agreements, as applicable; and
(b)
to the extent the showing pursuant to Section 24.4.6.3.4(a) does not constitute sixty (60) percent of the capacity of the LCRIF, the proponent’s demonstration of the remainder of the required minimum level of interest must include a showing that additional LCRIGs: (1)
in the case of Large Generating Facilities subject to the LGIP set forth in Appendix Y, have obtained Site Exclusivity or paid the Site Exclusivity Deposit in lieu of Site Exclusivity, provided that any Site Exclusivity Deposit paid pursuant to Section 3.5 of the LGIP set forth in Appendix Y shall satisfy this requirement, or, in the case of Large Generating Facilities subject to the LGIP set forth in Appendix U and Small Generating Facilities, have obtained control over their site or paid a deposit to the CAISO in the amount of $250,000, which deposit shall be refundable if the LCRIF is not approved or is withdrawn by the proponent; and
(2)
have demonstrated interest in the LCRIF by one of the following methods: (i)
executing a firm power sales agreement for the output of the LCRIG for a period of five (5) years or longer; or
(ii)
in the case of Large Generating Facilities subject to the LGIP set forth in Appendix Y, filing an Interconnection Request and paying
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff the Interconnection Study Deposit required by Section 3.5 of the LGIP set forth in Appendix Y; or (iii)
in the case of Large Generating Facilities subject to the LGIP set forth in Appendix U and Small Generating Facilities, being in the CAISO’s interconnection queue and paying a deposit to the CAISO equal to the sum of the minimum deposits required of an Interconnection Customer for all studies performed in accordance with the Large Generator Interconnection Procedures (Appendix U) or Small Generator Interconnection Procedures (Appendix S), as applicable to the LCRIG, less the amount of any deposits actually paid by the LCRIG for such studies. The deposit shall be credited toward such study costs. If the LCRIF is not approved or is withdrawn by the proponent, any deposit paid under this provision shall be refundable to the extent it exceeds costs incurred by the CAISO for such studies; or
(iv)
paying a deposit to the CAISO equal to five (5) percent of the LCRIG’s pro rata share of the capital costs of a proposed LCRIF. The deposit shall be credited toward costs of Interconnection Studies performed in connection with the Large Generator Interconnection Procedures (Appendix U or Appendix Y, as applicable) or Small Generator Interconnection Procedures (Appendix S), whichever is applicable. If the LCRIF is not approved or is withdrawn by the proponent, any deposit paid under this provision shall be refundable to the extent it exceeds the costs incurred by the CAISO for such studies.
24.4.6.3.5
Coordination With Non-Participating TOs
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff In the event that a facility proposed as an LCRIF would connect to LCRIGs in an Energy Resource Area that would also be connected by a transmission facility that is in existence or is proposed to be constructed by an entity that is not a Participating TO and that does not intend to place that facility under the Operational Control of the CAISO, the CAISO shall coordinate with the entity owning or proposing that transmission facility through any regional planning process to avoid the unnecessary construction of duplicative transmission additions to connect the same LCRIGs to the CAISO Controlled Grid. 24.4.6.3.6
Evaluation of LCRIFs
In evaluating whether a proposed LCRIF that meets the requirements of Section 24.4.6.3.2 is needed, and for purposes of ranking and prioritizing LCRIF projects, the CAISO will consider the following factors: (a)
Whether, and if so, the extent to which, the facility meets or exceeds applicable CAISO Planning Standards, including standards that are Applicable Reliability Criteria.
(b)
Whether, and if so, the extent to which, the facility has the capability and flexibility both to interconnect potential LCRIGs in the Energy Resource Area and to be converted in the future to a network transmission facility.
(c)
Whether the projected cost of the facility is reasonable in light of its projected benefits, in comparison to the costs and benefits of other alternatives for connecting Generating Units or otherwise meeting a need identified in the CAISO Transmission Planning Process, including alternatives that are not LCRIFs. In making this determination, the CAISO shall take into account, among other factors, the following: (1)
The potential capacity of LCRIGs and the potential Energy that could be produced by LCRIGs in each Energy Resource Area;
(2)
The capacity of LCRIGs in the CAISO’s interconnection process for each Energy Resource Area;
(3)
The projected cost and in-service date of the facility in comparison with other transmission facilities that could connect LCRIGs to the CAISO Controlled Grid;
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff (4)
Whether, and if so, the extent to which, the facility would provide additional reliability or economic benefits to the CAISO Controlled Grid; and
(5)
Whether, and if so, the extent to which, the facility would create a risk of stranded costs.
24.4.6.4
Projects to Maintain the Feasibility of Long Term CRRs
The CAISO is obligated to ensure the continuing feasibility of Long Term CRRs that are allocated by the CAISO over the length of their terms. In furtherance of this requirement the CAISO shall, as part of its annual Transmission Planning Process cycle, test and evaluate the simultaneous feasibility of allocated Long Term CRRs, including, but not limited to, when acting on the following types of projects: (a) planned or proposed transmission projects; (b) Generating Unit or transmission retirements; (c) Generating Unit interconnections; and (d) the interconnection of new Load. Pursuant to such evaluations, the CAISO shall identify the need for any transmission additions or upgrades required to ensure the continuing feasibility of allocated Long Term CRRs over the length of their terms and shall publish Congestion Data Summary along with the results of the CAISO technical studies. In assessing the need for transmission additions or upgrades to maintain the feasibility of allocated Long Term CRRs, the CAISO, in coordination with the Participating TOs and other Market Participants, shall consider lower cost alternatives to the construction of transmission additions or upgrades, such as acceleration or expansion of existing projects; Demand-side management; Remedial Action Schemes; constrained-on Generation; interruptible Loads; reactive support; or in cases where the infeasible Long Term CRRs involve a small magnitude of megawatts, ensuring against the risk of any potential revenue shortfall using the CRR Balancing Account and uplift mechanism in Section 11.2.4. As part of the CAISO’s Transmission Planning Process, the Participating TOs and Market Participants shall provide the necessary assistance and information to the CAISO to allow it to assess and identify transmission additions or upgrades that may be necessary under Section 24.4.6.4. To the extent a transmission upgrade or addition is deemed needed to maintain the feasibility of allocated Long Term CRRs in accordance with this Section and included in the CAISO’s annual Transmission Plan, the CAISO will designate the Participating TO(s) with a PTO Service Territory in which the transmission upgrade or addition is to be located as the Project Sponsor(s), responsible to
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff construct, own and finance, and maintain such transmission upgrade or addition. 24.4.6.5
LGIP Network Upgrades
Beginning with the 2011/2012 planning cycle, Network Upgrades originally identified during the Phase II Interconnection Study or Interconnection Facilities Study Process of the Large Generation Interconnection Process as set forth in Section 7 of Appendix Y that are not already included in a signed LGIA may be assessed as part of the comprehensive Transmission Plan if these Network Upgrades satisfy the following criteria: (a)
The Network Upgrades consist of new transmission lines 200 kV or above, and have capital costs of $100 million or greater;
(b)
The Network Upgrade is a new 500 kV substation that has capital costs of $100 million or greater; or,
(c)
The Network Upgrades have a capital cost of $200 million or more.
The CAISO will post a list of the Network Upgrades eligible for assessment in the Transmission Planning Process in accordance with the schedule set forth in the applicable Business Practice Manual. Network Upgrades included in the comprehensive Transmission Plan may include additional components not included in the Network Upgrades originally identified during the Phase II Interconnection Study or may be expansions of the Network Upgrades originally identified during the Phase II Interconnection Study if the CAISO determines during the Transmission Planning Process that such components or expansions are needed as additional elements under section 24.1. Network Upgrades identified in the LGIP Phase II studies but not assessed in the Transmission Planning Process will be included in Large Generator Interconnection Agreements, as appropriate. Network Upgrades assessed in the Transmission Planning Process but not modified or replaced will be included in Large Generator Interconnection Agreements, as appropriate. Construction and ownership of Network Upgrades specified in the comprehensive Transmission Plan under this section, including any needed additional components or expansions, will be the responsibility of the Participating TO if the Phase II studies identified the original upgrade as needed and such upgrade has not yet been set forth in an executed Large Generator Interconnection Agreement. If, through the Transmission Planning Process, the CAISO identifies any additional components or expansions of Network Upgrades that result in the need for other upgrades or additions, the responsibility
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff to build and own such additions or upgrades will be determined by this Section 24, according to the category of those other upgrades or additions. Any decision in the Transmission Planning Process to modify Network Upgrades identified in the Large Generator Interconnection Process will not increase the cost responsibility of the Interconnection Customer as described in Appendix Y, Section 7. Category 1 policy-driven elements identified under Section 24.4.6.7 could supplant the need for LGIP Network Upgrades that would be developed in subsequent Generator Interconnection Process cycles. To the extent that a Category 1 policy-driven element eliminates or downsizes the need for a Network Upgrade, the Interconnection Customer’s cost responsibility for such Network Upgrade shall be eliminated or reduced. Any financial security posting shall be adjusted accordingly. 24.4.6.6
Policy-Driven Elements
Once the CAISO has identified projects needed to maintain reliability, LCRIF projects eligible for conditional or final approval, projects needed to maintain long-term CRR feasibility, qualified Merchant Transmission Facility projects, and needed LGIP Network Upgrades as described in Section 24.4.6.5, the CAISO may evaluate transmission upgrade and addition elements needed to meet state or federal policy requirements or directives as specified in the Study Plan pursuant to Section 24.3.2(i). Policy-driven transmission upgrade or addition elements will be either Category 1 or Category 2. Category 1 are those elements which under the criteria of this section are found to be needed elements and are recommended for approval as part of the comprehensive Transmission Plan in the current cycle. Category 2 are those elements that could be needed to achieve state or federal policy requirements or directives but have not been found to be needed in the current planning cycle based on the criteria set forth in this section. Elements identified in this section and not identified in Section 24.4.6.5 as the responsibility of the Participating TO to build will be open for Project Sponsor solicitation during Phase 3. The CAISO will determine the need for, and identify such policy-driven transmission upgrade or addition elements that efficiently and effectively meet applicable policies under alternative resource location and integration assumptions and scenarios, while mitigating the risk of stranded investment. The CAISO will create a baseline scenario reflecting the assumptions about resource locations that are most likely to occur and one or more reasonable stress scenarios that will be compared to the baseline scenario. Any transmission upgrade or addition elements that are included in the baseline scenario and at least a
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff significant percentage of the stress scenarios may be Category 1 elements. Transmission upgrades or additions that are included in the base case, but which are not included in any of the stress scenarios or are included in an insignificant percentage of the stress scenarios, generally will be Category 2 elements, unless the CAISO finds that sufficient analytic justification exists to designate them as Category 1. In such cases, the ISO will make public the analysis upon which it based its justification for designating such facilities as Category 1 rather than Category 2. In this process, the CAISO will consider the following criteria: (a)
commercial interest in the resources in the applicable geographic area (including renewable energy zones) accessed by potential transmission elements as evidenced by signed and approved power purchase agreements and interconnection agreements;
(b)
the results and identified priorities of the California Public Utilities Commission’s or California Local Regulatory Authorities’ resource planning processes;
(c)
the expected planning level cost of the transmission element as compared to the potential planning level costs of other alternative transmission elements;
(d)
the potential capacity (MW) value and energy (MWh) value of resources in particular zones that will meet the policy requirements, as well as the cost supply function of the resources in such zones;
(e)
the environmental evaluation, using best available public data, of the zones that the transmission is interconnecting as well as analysis of the environmental impacts of the transmission elements themselves; the extent to which the transmission element will be needed to meet Applicable Reliability Criteria or to provide additional reliability or economic benefits to the ISO grid;
(f)
potential future connections to other resource areas and transmission elements;
(g)
resource integration requirements and the costs associated with these requirements in particular resource areas designated pursuant to policy initiatives;
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff (h)
the potential for a particular transmission element to provide access to resources needed for integration, such as pumped storage in the case of renewable resources;
(i)
the effect of uncertainty associated with the above criteria, and any other considerations, that could affect the risk of stranded investment; and
(j)
the effects of other additions or upgrades being considered for approval during the planning process.
24.4.6.7
Economic Studies and Mitigation Solutions
Once the CAISO has identified projects needed to maintain reliability, LCRIF projects eligible for conditional or final approval, qualified merchant transmission projects and policy driven elements, the CAISO will conduct the High Priority Economic Planning Studies selected under Section 24.4.4 and any other studies that the CAISO concludes are necessary to determine whether additional transmission upgrades and additions, or modifications to identified transmission projects or elements, are necessary to address: (a)
Congestion identified by the CAISO in the Congestion Data Summary published for the applicable Transmission Planning Process cycle and the magnitude, duration, and frequency of that Congestion;
(b)
Local Capacity Area Resource requirements;
(c)
Congestion projected to increase over the planning horizon used in the Transmission Planning Process and the magnitude of that Congestion; or
(d)
Integration of new generation resources or loads on an aggregated or regional basis.
In determining whether additional elements are needed, the CAISO shall consider the degree to which, if any, the benefits of the solutions outweigh the costs, in accordance with the procedures set forth in the Business Practice Manual. The benefits of the mitigation solutions may include a calculation of any reduction in production costs, Congestion costs, Transmission Losses, capacity or other electric supply costs resulting from improved access to cost-efficient resources. The cost of the mitigation solution must consider any estimated costs identified under Section 24.4.6.4 to maintain the simultaneous feasibility of
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff allocated Long Term CRRs for the length of their term. The CAISO, in determining whether a particular solution is needed, shall also consider the comparative costs and benefits of viable alternatives to the particular transmission element, including: (1) other potential transmission upgrades or additions, including those being considered or proposed during the Transmission Planning Process; (2) acceleration or expansion of any transmission upgrade or addition already approved by the CAISO Governing Board or included in any CAISO annual Transmission Plan, and (3) non-transmission alternatives, including demand-side management. Transmission upgrades and addition elements that are identified under this Section 24.4.6.7, other than reliability-driven projects, LCRIF projects eligible for conditional or final approval and qualified Merchant Transmission Facility projects, will be open for bid and Project Sponsor solicitation in Phase 3. 24.4.6.8
Projects Submitted in Prior Request Windows
During Phase 2 of the 2010/2011 Transmission Planning Cycle, the CAISO will evaluate the specific project proposals submitted during the 2008 and 2009 request windows. If any of these 2008 or 2009 request window proposals is found by the CAISO to be needed as a Category 1 policy-driven or economically-driven element, using the criteria for approval of transmission elements under sections 24.4.6.6 or 24.4.6.7, the project will be included in the comprehensive 2010/2011 Transmission Plan. Upon Board approval of the Transmission Plan, the Project Sponsor that submitted the proposal will be approved to finance, own and construct the approved additions and upgrades provided that Project Sponsor meets the criterion specified in Section 24.5.2.1(c). If a 2008 or 2009 request window proposal is found to be needed as a Category 2 policy-driven element in the 2010-2011 Transmission Planning Cycle, and that Category 2 policy-driven element is reclassified as a Category 1 policy-driven element in the 2011-2012 Transmission Planning Cycle, the Project Sponsor that submitted the proposal will be approved to finance, own and construct the element, provided that Project Sponsor meets the criterion specified in Section 24.5.2.1(c). If competing projects have been submitted by multiple Project Sponsors in the 2008 and 2009 request windows for the same elements in the 2010/2011 comprehensive Transmission Plan, the CAISO will approve one of those Project Sponsors to build and own the project based on the criteria specified in Section 24.5.2.3. To the extent that competing project proposals for the same policy-driven or economically-driven element were submitted in both the 2008 and 2009 request
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff windows, the CAISO will give priority to the proiect proposals submitted in the 2008 request window. 24.4.7
Description of Transmission Elements
The transmission elements identified in the draft and final comprehensive Transmission Plan will provide sufficient engineering detail to permit Project Sponsors to submit complete proposals, under section 24.5.1 to build certain transmission elements. As further described in the Business Practice Manual, such details may include, but are not limited to:
24.4.8
(a)
Minimum Conductor Ampacity;
(b)
Approximate Line impedance required;
(c)
Approximate Series compensation levels;
(d)
Substation bus and breaker configuration;
(e)
Breaker clearing times;
(f)
Transformer characteristics (capacity, impedance, tap range);
(g)
Minimum Shunt capacitor and reactor sizes;
(h)
Minimum FACTS device specifications;
(i)
SPS requirements;
(j)
Planning level cost estimates;
(k)
Projected in-service date.
Additional Contents of Comprehensive Transmission Plan
In addition to the detailed descriptions of specific needed addition and upgrade projects and elements, the draft and final comprehensive Transmission Plan may include: (1) the results of technical studies performed under the Study Plan; (2) determinations and recommendations regarding the need for identified transmission upgrade and addition projects and elements; (3) assessments of transmission upgrades and additions submitted as alternatives to the potential solutions to transmission needs identified by the CAISO and studied during the Transmission Planning Process cycle; (4) results of Economic Planning Studies (except for the 2010/2011 cycle); (5) an update on the status of transmission upgrades or additions previously approved by the CAISO, including identification of mitigation plans, if necessary, to address any potential delay in the anticipated completion of an approved transmission upgrade or addition; and (6) a description of transmission addition and upgrade projects with an
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff estimated capital investment of $50 million or more submitted through the Request Window and for which additional studies are required before being presented to the CAISO Governing Board for approval following completion of the studies; and (7) a description of Category 2 transmission upgrade or addition elements recommended for consideration in future planning cycles. 24.4.9
Phase 2 Stakeholder Process (a)
According to the schedule and procedures set forth in the Business Practice Manual, the CAISO will schedule one (1) public meeting after the CAISO technical study results have been posted and Participating TOs have submitted (i) the results of technical studies conducted at the direction of the CAISO (if applicable); and (ii) reliability-driven projects and mitigation solutions. All stakeholder meetings, web conferences, or teleconferences shall be noticed by Market Notice. Interested parties will be provided a minimum two (2) week period to provide written comments regarding the technical study results and the proposals submitted by the Participating TOs.
(b)
The CAISO will schedule at least one (1) other public meeting before the draft comprehensive Transmission Plan is posted to provide information about any policy-driven element evaluations or economic planning studies that have been completed since the prior public meeting was held, as well as updated information about any studies or evaluations that are still in progress. Notice of such meeting, web conference or teleconference will be provided to stakeholders via Market Notice.
(c)
In accordance with the schedule and procedures in the Business Practice Manual, but not less than one-hundred and twenty (120) days after the results of the CAISO’s technical studies are posted and not less than six (6) weeks after the Request Window closes, the CAISO will post a draft comprehensive Transmission Plan. The CAISO will subsequently conduct a public conference regarding the draft comprehensive Transmission Plan and solicit comments, consistent with the timelines and procedures set forth in the Business Practice
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff Manual. Additional meetings, web conferences, or teleconferences may be scheduled as needed. All stakeholder meetings, web conferences, or teleconferences shall be noticed by Market Notice and such notice shall be posted to the CAISO Website. After consideration of comments, the CAISO will post the revised draft comprehensive Transmission Plan to the CAISO Website. 24.4.10
Transmission Plan Approval Process
The revised draft comprehensive Transmission Plan, along with the stakeholder comments, will be presented to the CAISO Governing Board for consideration and approval. Upon approval of the plan, all needed transmission addition and upgrade projects and elements, net of all transmission and nontransmission alternatives considered in developing the comprehensive Transmission Plan, will be deemed approved by the CAISO Governing Board. Transmission upgrade and addition projects with capital costs of $50 million or less can be approved by CAISO management and may proceed to permitting and construction prior to Governing Board approval of the plan. Following Governing Board approval, the CAISO will post the final comprehensive Transmission Plan to the CAISO website. 24.5
Transmission Planning Process Phase 3
24.5.1
Project Submissions
According to the schedule set forth in the Business Practice Manual, in the month following CAISO Governing Board approval of the comprehensive Transmission Plan, the CAISO will initiate a period of at least two (2) months that will provide an opportunity for Project Sponsors to submit specific transmission project proposals to finance, own, and construct the transmission elements identified in the comprehensive Transmission Plan. Such project proposals must include plan of service details and supporting information as set forth in the Business Practice Manual sufficient to enable the CAISO to determine whether the proposal meets the criteria specified in section 24.5.2.1 and 24.5.2.4. The project proposal will identify the authorized governmental body from which the Project Sponsor will seek siting approval for the project. 24.5.2
Project Selection
At the end of the project submission period, the CAISO will post a list of proposed projects and Project Sponsors to its Website, subject to the confidentiality provisions set forth in Tariff section 20 and as
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff further described in the Business Practice Manual, and will select projects and Approved Project Sponsors pursuant to this section 24.5.2. If the selected project involves an upgrade to or addition on an existing Participating TO facility, the construction or ownership of facilities on a Participating TO’s right-ofway, or the construction or ownership of facilities within an existing Participating TO substation, the Participating TO will construct and own such upgrade or addition facilities unless the Project Sponsor and the Participating TO agree to a different arrangement. 24.5.2.1
Project Sponsor Qualification
The CAISO will evaluate the proposals to finance, own and construct policy-driven transmission elements or transmission elements that are included in the comprehensive Transmission Plan based on the results of Economic Planning Studies or other economic studies conducted by the CAISO under section 24.4.6.7 to determine: (a)
whether the proposed project is consistent with needed transmission elements identified in the comprehensive Transmission Plan;
(b)
whether the proposed project satisfies Applicable Reliability Criteria and CAISO Planning Standards; and
(c)
whether the Project Sponsor and its team is physically, technically, and financially capable of (i) completing the project in a timely and competent manner; and (ii) operating and maintaining the facilities consistent with Good Utility Practice and applicable reliability criteria for the life of the project.
On the CAISO’s request, the Project Sponsor will provide additional information that the CAISO reasonably determines is necessary to conduct its evaluation. 24.5.2.2
Single Project Sponsor
If only one (1) Project Sponsor submits a proposal to finance, own, and construct transmission elements under section 24.5.1, and the CAISO determines that the Project Sponsor is qualified to own and construct the project under the criteria set forth in section 24.5.2.1, the Project Sponsor must seek siting approval, and any other necessary approvals, from the appropriate authority or authorities within onehundred twenty (120) days of CAISO approval. 24.5.2.3
Multiple Project Sponsors
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff (a)
If two (2) or more Project Sponsors submit proposals to own and construct the same transmission element or elements under section 24.5.1 and the CAISO determines that the two (2) or more Project Sponsors are qualified to own and construct the project under the criteria set forth in section 24.5.2.1, the CAISO will, upon request, facilitate an opportunity for the Project Sponsors to collaborate with each other to propose a single project to meet such need. If joint projects are proposed following the collaboration period, the CAISO will revise the list of potential renewable transmission upgrades or additions eligible for selection.
(b)
If the qualified Project Sponsors are unable to collaborate on a joint project and are applying to the same authorized governmental body to approve the project siting, the qualified Project Sponsors must seek siting approval within sixty (60) days and the CAISO will accept the Project Sponsor determination by that authorized governmental authority.
(c)
If the qualified Project Sponsors are unable to collaborate on a joint project and are applying to different authorized governmental bodies for project siting approval, the CAISO will select one approved Project Sponsor based on a comparative analysis of the degree to which each Project Sponsor meets the criteria set forth in sections 24.5.2.1 and a consideration of the factors set forth in 24.5.2.4. The CAISO will engage an expert consultant to assist with the selection of the approved Project Sponsor. Thereafter, the approved Project Sponsor must seek siting approval, and any other necessary approvals, from the appropriate authority or authorities within one-hundred twenty (120) days of CAISO approval.
24.5.2.4
Project Sponsor Selection Factors
In selecting an approved Project Sponsor from among multiple project sponsors, as described in section 24.5.2.3(c), the CAISO shall consider the following criteria, in addition to the criteria set forth in section 24.5.2:
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff (a)
the current and expected capabilities of the Project Sponsor and its team to finance, license, and construct the facility and operate and maintain it for the life of the project;
(b)
the Project Sponsor’s existing rights of way and substations that would contribute to the project in question;
(c)
the experience of the Project Sponsor and its team in acquiring rights of way, and the authority to acquire rights of way by eminent domain, if necessary, that would facilitate approval and construction;
(d)
the proposed schedule for development and completion of the project and demonstrated ability to meet that schedule of the Project Sponsor and its team;
(e)
the financial resources of the Project Sponsor and its team;
(f)
the technical and engineering qualifications and experience of the Project Sponsor and its team;
(g)
if applicable, the previous record regarding construction and maintenance of transmission facilities, including facilities outside the CAISO Controlled Grid of the Project Sponsor and its team;
(h)
demonstrated capability to adhere to standardized construction, maintenance and operating practices;
(i)
demonstrated ability to assume liability for major losses resulting from failure of facilities;
(j)
demonstrated cost containment capability and other advantages the Project Sponsor and its team may have to build the specific project, including any binding agreement by the Project Sponsor and its team to accept a cost cap that would preclude project costs above the cap from being recovered through the CAISO’s Transmission Access Charge.
The information that Project Sponsors must submit to enable the CAISO to conduct its evaluation of these criteria shall be specified in the Business Practice Manual. 24.5.3
Notice to Project Sponsors
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff The CAISO will notify Project Sponsors as to results of the project evaluation process in accordance with the schedule and procedures set forth in the Business Practice Manual. 24.6
Obligation to Construct Transmission Projects
A Participating TO that has a PTO Service Territory in which either terminus of the element or elements being upgraded or added is located shall be obligated to construct all transmission additions and upgrade elements or elements included in the comprehensive Transmission Plan for which there is no Approved Project Sponsor or for which the Project Sponsor is unable to secure all necessary approvals. In cases where the Approved Project Sponsor is subsequently unable or unwilling to build the project, the CAISO may, at its discretion, direct the Participating TO with a PTO Service Territory in which either terminus of the facility being upgraded or added is located to build the element or elements, or open a new solicitation of Project Sponsors to finance, construct and own the element or elements. The Approved Project Sponsor shall not sell, assign or otherwise transfer its rights to finance, construct and own the project before the project has been energized and, if applicable, turned over to the CAISO’s Operational Control unless the CAISO has approved such proposed transfer. The obligations of the Participating TO to construct such transmission additions or upgrades will not alter the rights of any entity to construct and expand transmission facilities as those rights would exist in the absence of a TO’s obligations under this CAISO Tariff or as those rights may be conferred by the CAISO or may arise or exist pursuant to this CAISO Tariff. 24.6.1
[NOT USED]
24.6.2
[NOT USED]
24.6.3
[NOT USED]
24.7
Documentation of Compliance with NERC Reliability Standards
The Transmission Plan and underlying studies, assessments, information and analysis developed during the Transmission Planning Process, regardless of whether performed by CAISO or by Participating TOs or other third parties at the direction of CAISO, shall be used by the CAISO as part of its documentation of compliance with NERC Reliability Standards. 24.8
Additional Planning Information
24.8.1
Information Provided by Participating TOs
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff In addition to any information that must be provided to the CAISO under the NERC Reliability Standards, Participating TOs shall provide the CAISO on an annual or periodic basis in accordance with the schedule and procedures and in the form required by the Business Practice Manual any information and data reasonably required by the CAISO to perform the Transmission Planning Process, including, but not limited to: (1) modeling data for power flow, including reactive power, short-circuit and stability analysis; (2) a description of the total Demand to be served from each substation, including a description of any Energy efficiency programs reflected in the total Demand; (3) the amount of any interruptible Loads included in the total Demand (including conditions under which an interruption can be implemented and any limitations on the duration and frequency of interruptions); (4), a description of Generating Units to be interconnected to the Distribution System of the Participating TO, including generation type and anticipated Commercial Operation Date; (5) detailed power system models of their transmission systems that reflect transmission system changes, including equipment replacement not requiring approval by the CAISO; (6) Distribution System modifications; (7) transmission network information, including line ratings, line length, conductor sizes and lengths, substation equipment ratings, circuits on common towers and with common rights-of-ways and cross-overs, special protection schemes, and protection setting information; and (8) Contingency lists. 24.8.2
Information Provided by Participating Generators
In addition to any information that must be provided to the CAISO under the NERC Reliability Standards, Participating Generators shall provide the CAISO on an annual or periodic basis in accordance with the schedule, procedures and in the form required by the Business Practice Manual any information and data reasonably required by the CAISO to perform the Transmission Planning Process, including, but not limited to: (1) modeling data for short-circuit and stability analysis and (2) data, such as term, and status of any environmental or land use permits or agreements the expiration of which may affect that the operation of the Generating Unit. 24.8.3
Information Requested from Load Serving Entities
In addition to any information that must be provided to the CAISO under the NERC Reliability Standards, the CAISO shall solicit from Load Serving Entities through their Scheduling Coordinators information required by, or anticipated to be useful to, the CAISO in its performance of the Transmission Planning
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff Process, including, but not limited to: (1) long-term resource plans; (2) existing long-term contracts for resources and transmission service outside the CAISO Balancing Authority Area; and (3) Demand Forecasts, including forecasted effect of Energy efficiency and Demand response programs. 24.8.4
Information from Planning Groups, BAAs and Regulators
In accordance with Section 24.8 , the CAISO shall obtain or solicit from interconnected Balancing Authority Areas, regional and sub-regional planning groups within the WECC, the CPUC, the CEC, and Local Regulatory Authorities information required by, or anticipated to be useful to, the CAISO in its performance of the Transmission Planning Process, including, but not limited to: (1) long-term transmission system plans; (2) long-term resource plans; (3) generation interconnection process information; (4) Demand Forecasts; and (5) any other data necessary for the development of power flow, short-circuit, and stability cases over the planning horizon of the CAISO Transmission Planning Process. 24.8.5
Obligation to Provide Updated Information
If material changes to the information provided under Sections 24.8 occur during the annual Transmission Planning Process, the providers of the information must provide notice to the CAISO of the changes. 24.9
Participating TO Study Obligation
The Participating TO constructing or expanding facilities will be directed by the CAISO to coordinate with the Project Sponsor or Participating TO(s) with PTO Service Territories in which the transmission upgrade or addition will be located, neighboring Balancing Authority Areas, as appropriate, and other Market Participants to perform any study or studies necessary, including a Facility Study, to determine the appropriate facilities to be constructed in accordance with the CAISO Transmission Planning Process and the terms set forth in the TO Tariff. 24.10
Operational Review
The CAISO will perform an operational review of all facilities studied as part of the CAISO Transmission Planning Process that are proposed to be connected to, or made part of, the CAISO Controlled Grid to ensure that the proposed facilities provide for acceptable Operational Flexibility and meet all its requirements for proper integration with the CAISO Controlled Grid. If the CAISO finds that such facilities do not provide for acceptable Operational Flexibility or do not adequately integrate with the CAISO Controlled Grid, the CAISO shall coordinate with the Project Sponsor and, if different, the Participating TO
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff with the PTO Service Territory, or the operators of neighboring Balancing Authority Areas, if applicable, in which the facilities will be located to reassess and redesign the facilities required to be constructed. Transmission upgrades or additions that do not provide acceptable Operational Flexibility or do not adequately integrate with the CAISO Controlled Grid cannot be included in the CAISO Transmission Plan or approved by CAISO management or the CAISO Governing Board, as applicable. 24.10.1
[NOT USED]
24.10.2
[NOT USED]
24.10.3
[[NOT USED]
24.10.4
[NOT USED]
24.11
State and Local Approval and Property Rights
24.11.1
PTO Requirement to Seek Necessary Approvals And Rights
The Participating TO obligated to construct facilities under this Section 24 must make a good faith effort to obtain all approvals and property rights under applicable federal, state and local laws that are necessary to complete the construction of the required transmission additions or upgrades. This obligation includes the Participating TO’s use of eminent domain authority, where provided by state law. 24.11.2
Consequences Of PTO Inability To Obtain Approvals And Rights
If the Participating TO cannot secure any such necessary approvals or property rights and consequently is unable to construct a transmission addition or upgrade found to be needed, it shall promptly notify the CAISO and shall comply with its obligations under the TO Tariff to convene a technical meeting to evaluate alternative proposals. The CAISO shall take such action as it reasonably considers appropriate, in coordination with the Participating TO and other affected Market Participants, to facilitate the development and evaluation of alternative proposals including, where possible, conferring on a third party the right to build the transmission addition or upgrade. 24.11.3
Conferral Of Right To Build Facilities On Third Party
Where the conditions of Section 24.11.2 have been satisfied and it is possible for a third party to obtain all approvals and property rights under applicable federal, state and local laws that are necessary to complete the construction of transmission additions or upgrades required to be constructed in accordance with this CAISO Tariff (including the use of eminent domain authority, where provided by state law), the
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff CAISO may confer on a third party the right to build the transmission addition or upgrade, which third party shall, if applicable, enter into the Transmission Control Agreement in relation to such transmission addition or upgrade. 24.12
WECC and Regional Coordination
The Project Sponsor will have responsibility for completing any applicable WECC requirements and rating study requirements to ensure that a proposed transmission addition or upgrade meets regional planning requirements. The Project Sponsor may request the Participating TO to perform this coordination on behalf of the Project Sponsor at the Project Sponsor's expense. 24.13
Regional and Sub-Regional Planning Process
The CAISO will be a member of the WECC and other applicable regional or sub-regional organizations and participate in WECC’s operation and planning committees, and in other applicable regional and subregional coordinated planning processes. 24.13.1
Scope of Regional or Sub-Regional Planning Participation
The CAISO will collaborate with adjacent transmission providers and existing sub-regional planning organizations through existing processes. This collaboration involves a reciprocal exchange of information, to the maximum extent possible and subject to applicable confidentiality restrictions, in order to ensure the simultaneous feasibility of respective Transmission Plans, the identification of potential areas for increased efficiency, and the consistent use of common assumptions whenever possible. The details of the CAISO’s participation in regional and sub-regional planning processes are set forth in the Business Practice Manual. At a minimum, the CAISO shall be required to: (a)
solicit the participation, whether through sub-regional planning groups or individually, of all interconnected Balancing Authority Areas in the development of the Unified Planning Assumptions and Study Plan and in reviewing the results of technical studies performed as part of the CAISO’s Transmission Planning Process in order to: (i)
coordinate, to the maximum extent practicable, planning assumptions, data and methodologies utilized by the CAISO, regional and sub-regional planning groups or interconnected Balancing Authority Areas;
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff (ii)
ensure transmission expansion plans of the CAISO, regional and subregional planning groups or interconnected Balancing Authority Areas are simultaneously feasible and seek to avoid duplication of facilities.
(b)
coordinate with regional and sub-regional planning groups regarding the entity to perform requests for Economic Planning Studies or other Congestion related studies;
(c)
transmit to applicable regional and sub-regional planning groups or interconnected Balancing Authority Areas information on technical studies performed as part of the CAISO Transmission Planning Process;
(d)
post on the CAISO Website links to the planning activities of applicable regional and sub-regional planning groups or interconnected Balancing Authority Areas.
24.13.2
Limitation on Regional Activities
Neither the CAISO nor any Participating TO nor any Market Participant shall take any position before the WECC or a regional organization that is inconsistent with a binding decision reached through an arbitration proceeding pursuant to Section 13, in which the Participating TO or Market Participant voluntarily participated. 24.14
Cost Responsibility for Transmission Additions or Upgrades
Cost responsibility for transmission additions or upgrades constructed pursuant to this Section 24 (including the responsibility for any costs incurred under Section 24.11) shall be determined as follows: 24.14.1
Project Sponsor Commitment to Pay Full Cost
Where a Project Sponsor commits to pay the full cost of a transmission addition or upgrade as set forth in subsection (2) of Section 24.4.6.1, the full costs shall be borne by the Project Sponsor. 24.14.2
Cost of Needed Addition or Upgrade to be Borne by PTO
Where the need for a transmission addition or upgrade is determined by the CAISO, the cost of the transmission addition or upgrade shall be borne by the Participating TO that will be the owner of the transmission addition or upgrade and shall be reflected in its Transmission Revenue Requirement. 24.14.3
CRR Entitlement for Project Sponsors Not Recovering Costs
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff Provided that the CAISO has Operational Control of the Merchant Transmission Facility, a Project Sponsor that does not recover the investment cost under a FERC-approved rate through the Access Charge or a reimbursement or direct payment from a Participating TO shall be entitled to receive Merchant CRRs as provided in Section 36.11. The full amount of capacity added to the system by such transmission upgrades or additions will be as determined through the regional reliability council process of the Western Electricity Coordinating Council or its successor. 24.14.3.1
Western Path 15
Pursuant to its Project Sponsor status as specified in Section 4.3.1.3, consistent with FERC’s findings in Docket Nos. EL04-133-001, ER04-1198-000, and ER04-1198-001, issued on May 16, 2006 (115 FERC ¶ 61,178), Western Path 15 shall receive compensation associated with transmission usage rights modeled for Western Path 15. In the event that Western Path 15 has an approved rate schedule that returns excess revenue from any compensation obtained from the CAISO associated with the transmission usage rights for Western Path 15, such revenue shall be returned to the CAISO through a procedure established by the CAISO and the Western Area Power Administration for that purpose. 24.14.3.2
FPL Energy, LLC
Pursuant to its Project Sponsor status, consistent with FERC’s findings in Docket No. ER03-407, issued on June 15, 2006 (115 FERC ¶ 61, 329), FPL Energy, LLC shall receive Merchant CRRs associated with transmission usage rights modeled for the Blythe Path 59 upgrade, such Merchant CRRs to be in effect for a period of thirty (30) years, or the pre-specified intended life of the Merchant Transmission Facility, whichever is less, from the date Blythe Path 59 was energized. For the purpose of allocating Merchant CRRs to FPL Energy, LLC over the Blythe Path 59 upgrade, the allocation of CRR Options in the import (east to west, from the Blythe Scheduling Point to the 230 kV side of the 161 kV to 230 kV transformer at the Eagle Mountain substation) as well as of CRR Options in the export (west to east) direction will be based on 57.1 percent of the total upgrade (96 MW out of the 168 MW), which is FPL Energy, LLC’s share of the total upgrade as approved by FERC in the letter order issued by FERC on June 15, 2006 in Docket No. ER03-407 (115 FERC ¶ 61,329). 24.14.4
Treatment Of New High Voltage Facilities Costs In HVAC
Once a New Participating TO has executed the Transmission Control Agreement and it has become
October 21, 2011
California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff effective, the cost for New High Voltage Facilities for all Participating TOs shall be included in the CAISO Grid-wide component of the High Voltage Access Charge in accordance with Schedule 3 of Appendix F, unless and with respect to Western Path 15 only, cost recovery is provided in Section 24.14.3. The Participating TO who is supporting the cost of the New High Voltage Facility shall include such costs in its High Voltage Transmission Revenue Requirement, regardless of which TAC Area the facility is geographically located. 24.15
Ownership of and Charges for Expansion Facilities
24.15.1
Transmission Additions and Upgrades under TCA
All transmission additions and upgrades constructed by Participating TOs in accordance with this Section 24 that form part of the CAISO Controlled Grid shall be operated and maintained by a Participating TO in accordance with the Transmission Control Agreement. Where such transmission additions and upgrades are jointly developed by Participating TOs and non-Participating TOs, nothing herein shall be construed to require that the non-Participating TO transfer its portion of the transmission additions or upgrades to the CAISO’s Operational Control or place such facilities within the CAISO’s Balancing Authority Area. 24.15.2
Access and Charges for Transmission Additions and Upgrades
Each Participating TO that owns or operates transmission additions and upgrades constructed in accordance with this Section 24 shall provide access to them and charge for their use in accordance with this CAISO Tariff and its TO Tariff. 24.16
Expansion by Local Furnishing Participating TOs
Notwithstanding any other provision of this CAISO Tariff, a Local Furnishing Participating TO shall not be obligated to construct or expand facilities (including interconnection facilities as described in Section 8 of the TO Tariff), unless the CAISO or Project Sponsor has tendered an application under FPA Section 211 that requests FERC to issue an order directing the Local Furnishing Participating TO to construct such facilities pursuant to Section 24. The Local Furnishing Participating TO shall, within ten (10) days of receiving a copy of the Section 211 application, waive its right to a request for service under FPA Section 213(a) and to the issuance of a proposed order under FPA Section 212(c). Upon receipt of a final order from FERC that is no longer subject to rehearing or appeal, such Local Furnishing Participating TO shall construct such facilities in accordance with this Section 24.
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ERCOT Planning Guide Section 4: Transmission Planning Criteria September 1, 2011
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TABLE OF CONTENTS: SECTION 4
4
TRANSMISSION PLANNING CRITERIA .................................................................................................. 93 4.1 INTRODUCTION .............................................................................................................................................. 93 4.1.1 Reliability Criteria ............................................................................................................................... 94 4.1.1.1 Planning Assumptions ..................................................................................................................................... 94 4.1.1.2 Performance Requirements for Credible Single Contingencies for Transmission Planning............................ 94 4.1.1.3 Voltage Stability Margin ................................................................................................................................. 94
4.1.2
ERCOT Application of NERC Standards for System Assessments ...................................................... 95
4.1.2.1 Category C ...................................................................................................................................................... 95 4.1.2.2 Category D ...................................................................................................................................................... 96
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4 4.1
TRANSMISSION PLANNING CRITERIA Introduction
(1)
ERCOT employs both reliability criteria and economic criteria in evaluating the need for transmission system improvements. The economic criteria are included in Protocol Section 3.11.2, Planning Criteria (See below for Section 3.11 of the Protocol). This Planning Guide provides the reliability criteria.
(2)
The ERCOT System consists of those generation and Transmission Facilities (60 kV and higher voltages) that are controlled by individual Market Participants and that function as part of an integrated and coordinated system.
(3)
To maintain reliable operation of the ERCOT System, it is necessary that all stakeholders observe and subscribe to certain minimum planning criteria. The criteria set forth herein, combined with the applicable North American Electric Reliability Corporation (NERC) Reliability Standards, constitute the aforementioned minimum planning criteria. Tests outlined herein shall be performed to determine conformance to these minimum criteria; however, ERCOT recognizes that events more severe than those outlined in these criteria could cause grid separation and other tests may also be performed.
(4)
The complexity and uncertainty inherent in the planning and operation of the ERCOT System make exhaustive studies impracticable; therefore, to gain maximum benefit from the limited number of tests performed, the selection of the specific tests and the frequency of their performance will be made solely upon the basis of the expected value of the reliability information obtainable from the test.
(5)
It is the responsibility of each Transmission Service Provider (TSP) to perform steadystate, short circuit and dynamic tests appropriate to ensure the reliability of its Transmission Facilities and implement appropriate solutions. Further, the TSP may recommend additional studies be performed by ERCOT or through the Reliability and Operations Subcommittee (ROS). Additional tests which may affect multiple TSPs or the ERCOT System as a whole may be studied. Upon consideration of such recommendations, ERCOT and the ROS shall coordinate the performance of such studies, as necessary, to assess the reliability of the planned ERCOT System.
(6)
ERCOT in coordination with the TSPs shall determine and demonstrate the need for any static and/or dynamic Reactive Power capability in excess of the explicit requirements of the Protocols and Operating Guides that is necessary to ensure compliance with the planning criteria. ERCOT shall establish specific TSP responsibility for any associated facility additions.
(7)
The base cases created by the Steady-State Working Group (SSWG), System Protection Working Group (SPWG), and ERCOT are available for use by Market Participants.
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SECTION 4: TRANSMISSION PLANNING CRITERIA
(8)
If a TSP has its own planning criteria in addition to those defined in this Planning Guide, the TSP shall provide documentation of those criteria to ERCOT. ERCOT shall post the documentation on the Planning and Operations Information website. The TSP shall notify ERCOT of any changes to their planning criteria and provide revised documentation within 30 days of such change.
4.1.1
Reliability Criteria
4.1.1.1
Planning Assumptions
The Credible Single Contingency for Transmission Planning studies will be performed for reasonable variations of Load level, generation schedules, planned transmission line Maintenance Outages, and anticipated power transfers. At a minimum, this should include projected Loads for the upcoming summer and winter seasons and a five-year planning horizon. The TSPs involved should plan to resolve any unacceptable study results through the provision of Transmission Facilities, the temporary alteration of operating procedures (i.e., Remedial Action Plans (RAPs)), Special Protection Systems (SPSs), or other means as appropriate. 4.1.1.2
Performance Requirements for Credible Single Contingencies for Transmission Planning
Credible Single Contingencies for Transmission Planning as defined in Section 2.1, Definitions, of this Planning Guide, shall not result in the following: (a)
Cascading or uncontrolled Outages;
(b)
Instability of Generation Resources at multiple plant locations; or
(c)
Interruption of service to firm demand or generation other than that isolated by the Credible Single Contingency for Transmission Planning, following the execution of all automatic operating actions such as relaying and SPSs. Furthermore, the loss should result in no damage to or failure of equipment and, following the execution of specific non-automatic predefined operator-directed actions (i.e., RAPs), such as generation schedule changes or curtailment of interruptible Load, should not result in applicable voltage limits or thermal ratings associated with the Transmission Facility being exceeded.
4.1.1.3
Voltage Stability Margin
Voltage stability margin shall be sufficient to maintain post-transient voltage stability under the following study conditions for each ERCOT or TSP-defined areas: (a)
A 5% increase in Load above expected peak supplied from resources external to the ERCOT or TSP-defined areas; and NERC Category A or B operating conditions; and
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SECTION 4: TRANSMISSION PLANNING CRITERIA
(b)
4.1.2
A 2.5% increase in Load above expected peak supplied from resources external to the ERCOT or TSP-defined areas and NERC Category C operating conditions. ERCOT Application of NERC Standards for System Assessments
4.1.2.1
Category C
(1)
Bus Section Definition - "Bus Section" shall be interpreted to mean any section of bus work, which would be isolated by normal relay/breaker operation when faulted.
(2)
Manual System Adjustments Definition - "Manual System Adjustments" shall be interpreted to include only operator actions that: (a)
Would be made no later than one hour after clearing of the first fault;
(b)
Are made using remote control capability or communications with other operators having such capability;
(c)
Include circuit switching, changes in the schedules of Generation Resources operating at clearing of the first fault, and changes in the schedules of other Generation Resources that can contribute within one hour; and
(d)
Exclude the physical repair or replacement of damaged equipment and the starting of any Generation Resource that cannot contribute within one hour.
(3)
Planned Loss of Demand or Curtailed Firm Transfer Definition - All Load interruption, generator tripping, or generation schedule changes must be either automatic or prearranged with associated written operating procedures. Actions must be executable in time to avoid any equipment damage or safety violations, but in any case within 30 minutes of fault clearing.
(4)
Cascading Outage Definition - Cascading Outages are defined as the uncontrolled loss of any system facilities or load, whether because of thermal overload, voltage collapse, or loss of synchronism, except those occurring as a result of fault isolation.
(5)
Implementation Guidelines - Evaluation of all the possible combination of facility Outages under Category C is not required. Each TSP with bulk Transmission Facilities will evaluate one or more Category C contingencies annually. The contingencies selected may be based on the results of related studies or actual events. In either case, the selected contingencies must indicate more severe results or impacts based on the engineering judgment of the facility owner, ERCOT or any TSP. An explanation of why any remaining contingencies would produce less severe system results shall be available as supporting information.
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4.1.2.2
Category D
(1)
For the purpose of evaluating the consequences resulting from a Category D event, a Large Load or Major Load Center is an electrical demand of between 50 and 500 MW. This may be a large single Load or a group of electrically close Loads. The loss of this demand will not include any other system elements other than those directly connected.
(2)
Evaluations of Category D contingencies are not required to be performed annually. Evaluations should be performed for the following: (a)
Contingencies previously studied for which the conditions assumed in the study have changed significantly and which may adversely affect the results of the study; and
(b)
Contingencies not previously studied that, based on the results of related studies or actual events may in the engineering judgment of the facility owner, ERCOT or any TSP, have unacceptable consequences.
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Section 3: Management Activities for the ERCOT System
ERCOT Nodal Protocols Section 3: Management Activities for the ERCOT System
November 1, 2011 ______________________________________________________________________________ TABLE OF CONTENTS SECTION 3 3.11 TRANSMISSION PLANNING 3.11.1 Overview 3.11.2 Planning Criteria 3.11.3 Regional Planning Group Regional Planning Group Project Review Process 3.11.4
3.11.4.1 Project Submission 3.11.4.2 Project Comment Process 3.11.4.3 Categorization of Proposed Transmission Projects 3.11.4.4 Tier 4 3.11.4.5 Tier 3 3.11.4.6 Tier 2 3.11.4.7 Tier 1 3.11.4.8 Determine Designated Providers of Transmission Additions 3.11.4.9 Regional Planning Group Acceptance and ERCOT Endorsement 3.11.4.10 Modifications to ERCOT Endorsed Projects
3.11.5 3.11.6
3.11 3.11.1 (1)
Assessment of Chronic Congestion GENERATION INTERCONNECTION PROCESS
TRANSMISSION PLANNING Overview Any stakeholder, regardless if it is a Transmission Service Provider (TSP) and/or Distribution Service Provider (DSP), may develop and submit proposed projects to the Regional Planning Groups (RPGs), and review projects developed and proposed by the RPGs. Broad participation in the process will result in a thorough development of
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Section 3: Management Activities for the ERCOT System
projects. However, confidentiality provisions prevent participation of non-TSPs and/or DSPs in the studies leading to interconnection agreements with generators until they become public. (2)
3.11.2
Project endorsement through the ERCOT Regional Planning process is intended to support, to the extent applicable, a finding by the Public Utility Commission of Texas (PUCT) that a project is necessary for the service, accommodation, convenience, or safety of the public within the meaning of Public Utility Regulatory Act, TEX. UTIL. CODE ANN. § 37.056 (Vernon 1998 and Supp. 2007) (PURA) and P.U.C. SUBST. R. 25.101, Certification Criteria. Planning Criteria
(1)
ERCOT and TSPs shall evaluate the need for transmission system improvements and shall evaluate the relative value of alternative improvements based on established technical and economic criteria.
(2)
The technical reliability criteria are established by the Planning Guide, Operating Guides, and the North American Electric Reliability Corporation (NERC) Reliability Standards. ERCOT and TSPs shall strongly endeavor to meet these criteria, identify current and future violations thereof and initiate solutions necessary to ensure continual compliance.
(3)
ERCOT shall attempt to meet these reliability criteria as economically as possible and shall actively identify economic projects to meet this goal.
(4)
For economic projects, the net economic benefit of a proposed project, or set of projects, will first be assessed over the project’s life based on the net societal benefit that is reasonably expected to accrue from the project. The project will be recommended if it is reasonably expected to result in positive net societal benefits. If the proposed project is not expected to provide positive net societal benefits, then the net consumer benefit of the project will be assessed, and the project will be recommended if the net consumer benefits are reasonably expected to be positive.
(5)
To determine the societal benefit of a proposed project, the revenue requirement of the capital cost of the project is compared to the expected savings in system production costs resulting from the project over the expected life of the project. Indirect benefits and costs associated with the project should be considered as well, where appropriate. The current set of financial assumptions upon which the revenue requirement calculations is based will be posted on the Market Information System (MIS) Secure Area. The expected production costs are based on a chronological simulation of the security-constrained unit commitment and economic dispatch of the generators connected to the ERCOT Transmission Grid to serve the expected ERCOT System Load over the planning horizon. This market simulation is intended to provide a reasonable representation of how the ERCOT System is expected to be operated over the simulated time period. From a practical standpoint, it is not feasible to perform this production cost simulation for the entire 30 to 40 year expected life of the project. Therefore, the production costs are
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projected over the period for which a simulation is feasible and a qualitative assessment is made of whether the factors driving the production cost savings due to the project can reasonably be expected to continue. If so, the levelized annual production cost savings over the period for which the simulation is feasible is calculated and compared to the first year annual revenue requirement of the transmission project. If this production cost savings exceeds this annual revenue requirement for the project, the project is economic from a societal perspective and will be recommended. (6)
For projects that do not provide sufficient societal benefit to be recommended, the net consumer benefit of the proposed project will be calculated. Outputs from the same market simulation described in paragraph (5) above will be used to provide an estimate of the expected reduction in total system generator revenues due to the project, which is a reasonable indication in the ERCOT market of the impact on consumer costs due to the project. Expected above-market generator revenues not included in the simulation, such as Reliability Must-Run (RMR) payments as prescribed in Section 6.6.6.2, RMR Payment for Energy, may need to be included in this evaluation. If the levelized generator revenue reduction exceeds the first year annual revenue requirement for the project, the project is economic from the consumer benefit perspective and will be recommended.
(7)
Other indicators based on analyses of ERCOT System operations may be considered as appropriate in the determination of consumer benefits. In order for such an alternate indicator to be considered, the costs must be reasonably expected to be on-going and be adequately quantifiable and unavoidable given the physical limitation of the transmission system. These alternate indicators include:
(a)
Reliability Unit Commitment (RUC) Settlement for unit operations;
(b)
Visible ERCOT market indicators such as clearing prices of Congestion Revenue Rights (CRRs); and (c)
3.11.3
Actual Locational Marginal Prices (LMPs) and observed congestion. Regional Planning Group
ERCOT shall lead and facilitate a Regional Planning Group (RPG) to consider and review proposed projects to address transmission constraints and other ERCOT System needs. The RPG will be a non-voting, consensus-based organization focused on identifying needs, identifying potential solutions, communicating varying viewpoints and reviewing analyses related to the ERCOT Transmission Grid in the planning horizon. Participation in the RPG is required of all TSPs and is open to all Market Participants, consumers, other stakeholders, and PUCT Staff.
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3.11.4
Regional Planning Group Project Review Process
3.11.4.1
Project Submission
(1)
Any stakeholder may initiate an RPG Project Review through the submission of a document describing the scope of the proposed project to ERCOT. Projects should be submitted with sufficient lead-time to allow the RPG Project Review to be completed prior to the date on which the project must be initiated by the designated TSP.
(2)
Stakeholders may submit projects for RPG Project Review within any project Tier. All transmission projects in Tiers 1, 2 and 3 should be submitted. TSPs are not required to submit Tier 4 projects for RPG review, but should include any Tier 4 projects that are known in advance in the cases used for development of the Five-Year Transmission Plan.
(3)
All system improvements that are necessary for the project to achieve the system performance improvement, or to correct the system performance deficiency, for which the project is intended should be included into a single project submission.
3.11.4.2
Project Comment Process
ERCOT shall conduct a comment process which is open to the stakeholders for all proposed Tier 1, 2 and 3 projects. The proposer of the project will have a reasonable period of time, as established by ERCOT, to answer questions and respond to comments submitted during this process. The Planning Guide provides details of this process. 3.11.4.3
Categorization of Proposed Transmission Projects
(1)
ERCOT classifies all proposed transmission projects into one of four categories (or Tiers). Each Tier is defined so that projects with a similar cost and impact on reliability and the ERCOT market are grouped into the same Tier. The criteria used to classify a specific project into the appropriate Tier are described in Section 3.11.4.4, Tier 4, through Section 3.11.4.7, Tier 1, in increasing order of the level of review to which the projects within the Tier are subjected.
(2)
ERCOT may use its reasonable judgment to increase the level of review of a proposed project (e.g., from Tier 3 to Tier 2) from that which would be strictly indicated by these criteria, based on stakeholder comments, ERCOT analysis or the system impacts of the project.
(3)
Any project that would be built by an Entity that is exempt (e.g., a Municipally Owned Utility (MOU)) from getting a Certificate of Convenience and Necessity (CCN) for transmission projects but would require a CCN if it were to be built by a regulated Entity will be treated as if the project would require a CCN for the purpose of defining the Tier of the project.
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3.11.4.4
Tier 4
(1)
This category consists of small system upgrades with estimated capital cost less than or equal to $15,000,000 and that do not require a CCN, as well as certain “Neutral” projects. Neutral projects are:
(a)
The addition of or upgrades to radial transmission lines; the addition of equipment that does not affect the transfer capability of a line;
(b)
Repair and replacement-in-kind projects;
(c)
Projects that are directly associated with the interconnection of new generation; and
(d)
The addition of static reactive devices.
(2)
A project, irrespective of estimated capital cost, to serve a new Load is considered to be a Neutral project even if a CCN is required, unless such project would create a new transmission line connection between two stations (other than looping an existing line into the new Load-serving station).
3.11.4.5
Tier 3
This category consists of projects with estimated capital costs between $15,000,000 and $50,000,000 not requiring a CCN. (a)
ERCOT shall accept a Tier 3 project if no concerns, questions or objections are provided during the project comment process;
(b)
If reasonable ERCOT or stakeholder concerns about a Tier 3 project cannot be resolved during the time period allotted by ERCOT, the project may be processed as a Tier 2 project, unless ERCOT assesses that reasonable progress is being made toward resolving these concerns; and
(c)
Projects that are required to meet an individual TSP’s Planning Criteria and that are not required by the NERC Reliability Standards or ERCOT Planning Criteria shall also be processed in this Tier, and shall be reclassified as a Tier 4 Neutral project if comments are resolved.
3.11.4.6
Tier 2
This category consists of projects with estimated capital costs less than $50,000,000 requiring a CCN. ERCOT shall conduct an independent review of the submitted Tier 2 project to include the following: (a)
ERCOT’s independent review shall consist of studies and analyses necessary for ERCOT to make its assessment of whether the proposed project is needed and whether the
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Section 3: Management Activities for the ERCOT System
proposed project is the preferred solution to the identified system performance deficiency that the project is intended to resolve; (b)
ERCOT shall consider all comments received during the project comment process and factor reasonable comments into its independent review of the project;
(c)
ERCOT will attempt to complete its independent review for a project in 90 days or less. If ERCOT is unable to complete their independent review based on RPG input within 90 days, ERCOT shall provide the project submitter a reason for the delay and expected completion time;
(d)
ERCOT may, at its discretion, discuss submitted transmission projects at meetings of the RPG in order to obtain additional input into its independent review; and
(e)
ERCOT shall prepare a written report documenting the results of its independent review and recommendation on the project and shall distribute this report to the RPG.
3.11.4.7
Tier 1
(1)
This category is for all projects whose estimated capital cost is $50,000,000 or greater. ERCOT shall conduct an independent review of the submitted Tier 1 project to include the following:
(a)
ERCOT’s independent review will consist of studies and analyses necessary for ERCOT to make its assessment of whether the proposed project is needed and whether the proposed project is the preferred solution to the identified system performance deficiency that the project is intended to resolve;
(b)
ERCOT will consider all comments received during the project comment process and factor reasonable comments into its independent review of the project;
(c)
ERCOT will attempt to complete its independent review for a project in 90 days or less. If ERCOT is unable to complete their independent review based on RPG input within 90 days, ERCOT shall provide the project submitter a reason for the delay and expected completion time;
(d)
ERCOT may, at its discretion, discuss submitted transmission projects at meetings of the RPG in order to obtain additional input into its independent review; and
(e)
ERCOT shall prepare a written report documenting the results of its independent review and recommendation on the project and shall distribute this report to the RPG.
(2)
Tier 1 Projects require ERCOT Board endorsement.
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3.11.4.8
Determine Designated Providers of Transmission Additions
Upon completion of the RPG Project Review, ERCOT shall determine designated providers for the recommended transmission projects. The default TSPs will be those TSPs that own the end 13points of the new projects. Those TSPs can agree to provide or delegate the new facilities. If different TSPs own the two ends of the recommended project, ERCOT will designate them as co-providers of the recommended project, and they can decide between themselves what parts of the recommended project they will each provide. If they cannot agree, ERCOT will determine their responsibility following a meeting with the parties. If a designated TSP agrees to provide a project and that designated TSP does not diligently pursue the project (during the time frame before a CCN is filed, if required) in a manner that will meet the required in-service date, then upon concurrence of the ERCOT Board, ERCOT will solicit interest from TSPs through the RPG and will designate an alternate TSP. 3.11.4.9
Regional Planning Group Acceptance and ERCOT Endorsement
(1)
For Tier 3 projects, successful resolution of all comments received from ERCOT and stakeholders during the project comment process will result in RPG acceptance of the proposed project. A RPG acceptance letter shall be sent to the designated TSP for the project, the project submitter (if different from the designated TSP), and copied to the RPG. For Tier 2 projects, ERCOT’s recommendation as a result of its independent review of the proposed project will constitute ERCOT endorsement of the project. For Tier 1 projects, ERCOT’s endorsement is obtained upon affirmative vote of the ERCOT Board. An ERCOT endorsement letter shall be sent to the designated TSP for the project, the project submitter (if different from the designated TSP), the PUCT and copied to the RPG upon receipt of ERCOT’s endorsement for Tier 1 and Tier 2 projects.
(2)
Following the completion of its independent review, ERCOT shall present all Tier 1 projects to the ERCOT Board with its recommendation as to whether the project should be endorsed by the ERCOT Board. Prior to presenting the project to the ERCOT Board, ERCOT shall present the project to the Technical Advisory Committee (TAC) for review and comment. Comments from TAC shall be included in the presentation to the ERCOT Board. ERCOT will make a reasonable effort to make these presentations to TAC and the ERCOT Board at the next regularly scheduled meetings following completion of its independent review of the project.
3.11.4.10
Modifications to ERCOT Endorsed Projects
If the designated TSP for an ERCOT-endorsed project determines a need to make a significant change to the facilities included in the project (such as the line endpoint(s), number of circuits, voltage level, decrease in rating or similar major aspect of the project) prior to filing a CCN application (if required) for the project (or prior to beginning the final design of the project, if no CCN is required), the TSP shall notify ERCOT in a timely manner of the details of that change. If ERCOT concurs that the proposed change is significant, the change shall be processed as a Tier 3 project. ERCOT Nodal Protocols – November 1, 2011 PUBLIC
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3.11.5
Assessment of Chronic Congestion
(1)
ERCOT shall monitor the differences in LMPs from the Security-Constrained Economic Dispatch (SCED) process to identify geographic areas potentially experiencing chronic congestion. On determination of chronic congestion, ERCOT shall:
(a)
Validate with the TSP that the data from the Network Operating Model and the Updated Network Model are correct. If the models are valid, ERCOT shall use the planning criteria in the transmission planning process, through the RPG, to develop recommendations for resolution, if applicable.
(b)
Post all the results from this process on the MIS Secure Area and provide them to the PUCT Staff, the Independent Market Monitor (IMM), the appropriate TAC subcommittee(s), and the ERCOT Board.
(2)
ERCOT shall provide specific interval data for Load and generation to TSPs and/or DSPs, upon request, in accordance with confidentiality as defined in Section 1.3, Confidentiality.
(a)
The TSP’s and/or DSP’s request for interval data shall identify the reason for requesting the information in regards to impact to the planning process (e.g. build power flow cases, conduct a specific study, etc.).
(b)
ERCOT shall evaluate the TSP and/or DSP request and validate reasons provided.
(c)
Upon ERCOT validation of the TSP and/or DSP request, the data provided shall include meter data measured at points of injection and points of delivery which will measurably impact the TSP’s and/or DSP’s planning and operations as determined by ERCOT (e.g., determination of the TSP’s and/or DSP’s system Load or power flows).
(d)
If ERCOT determines that the request is invalid and denies it, ERCOT shall provide the reasoning for denying the request.
3.11.6
Generation Interconnection Process
The generation interconnection process facilitates the interconnection of new generation units in the ERCOT Region by assessing the transmission upgrades necessary for new generating units to operate reliably. The process to study interconnecting new generation or modifying an existing generation interconnection to the ERCOT Transmission Grid is covered in the Planning Guide. The generation interconnection study process primarily addresses the direct connection of generation Facilities to the ERCOT Transmission Grid and directly-related projects. Projects that are identified through this process and are regional in nature may be reviewed through the RPG Project Review process upon recommendation by the TSP or ERCOT, subject to the confidentiality provisions of the generation interconnection procedure. ERCOT shall perform an independent economic analysis of the transmission projects that are identified through this process that are expected to cost more than $25,000,000. This economic analysis is performed ERCOT Nodal Protocols – November 1, 2011 PUBLIC
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only for informational purposes; as such, no ERCOT endorsement will be provided. The results of the economic analysis shall be included in the interconnection study posting. Additional upgrades to the ERCOT Transmission Grid that might be cost-effective as a result of new or modified generation may be initiated by any stakeholder through the RPG Project Review procedure described in Section 3.11.4, Regional Planning Group Project Review Process, at the appropriate time, subject to the confidentiality provisions of the generation interconnection procedure.
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FERC Order No. 1000 Transmission Developer Qualifications
White Paper Published by: SPP Legal/Regulatory For the SPP Strategic Planning Committee
10/06/2011
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TABLE OF CONTENTS 1. HISTORY AND BACKGROUND ........................................................................................... 3 2. DEFINITIONS ........................................................................................................................... 3 3. ORDER NO. 1000 REQUIREMENTS REGARDING NONINCUMBENT PARTICIPATION IN REGIONAL TRANSMISSION PLANNING ....................................... 4 4. EXISTING SPP TARIFF AND BUSINESS PRACTICES....................................................... 5 4.1 SPP OATT........................................................................................................................ 6 4.2 SPP Business Practices..................................................................................................... 7 4.3 SPP Due Diligence Review Process for Novations ......................................................... 8 5. CONCLUSION .......................................................................................................................... 8
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1. HISTORY AND BACKGROUND On July 21, 2011, the Federal Energy Regulatory Commission (“FERC”) issued Order No. 1000, Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities.1 Among other things, Order No. 1000 requires all public utility transmission providers to facilitate nonincumbent transmission developer participation in regional transmission planning by removing from FERC-approved tariffs and agreements any language creating a federal right of first refusal (“ROFR”) for an incumbent transmission provider to construct transmission facilities selected in a regional transmission plan for cost allocation.2 As part of this requirement, Order No. 1000 also directs public utility transmission providers to adopt other provisions to facilitate “nonincumbent transmission developer participation” in regional transmission planning to ensure that the regional transmission planning processes are not unduly discriminatory, resulting in unjust and unreasonable rates. Compliance filings to address this requirement are due October 11, 2012. During its August 30, 2011 meeting, the Strategic Planning Committee (“SPC”) directed Southwest Power Pool, Inc. (“SPP”) staff to develop a series of white papers examining the various compliance requirements of Order No. 1000 and proposing possible modifications to the SPP Open Access Transmission Tariff (“OATT”) and other SPP documents and processes to comply with Order No. 1000. This white paper specifically addresses the requirement that each public utility transmission provider revise its OATT to demonstrate that the regional transmission planning process in which it participates has established appropriate qualification criteria for determining a transmission developer’s eligibility to propose transmission projects for selection in the regional transmission plan for purposes of cost allocation.3
2. DEFINITIONS Order No. 1000 uses the following terminology relevant to this white paper: Incumbent transmission developer/provider: An entity that develops a transmission project within its own retail distribution service territory or footprint. Nonincumbent transmission developer: An entity that either: (1) does not have a retail distribution service territory or footprint; or (2) is a public utility transmission provider that proposes a transmission project outside of its existing retail distribution service territory or footprint, where it is not the “incumbent” for purposes of the project. 1
136 FERC ¶ 61,051 (FERC Docket No. RM10-23-000).
2
Order No. 1000 indicates that the elimination of federal ROFR from FERC-approved tariffs and agreements does not: (1) apply to transmission facilities not selected in a regional transmission plan for purposes of cost allocation; (2) apply to upgrades to existing transmission facilities, such as tower change outs or reconductoring; (3) affect existing rights-of-way; and (4) affect state or local laws or regulations regarding the construction or siting of transmission facilities.
3
This requirement is set forth in paragraphs 323-324 of Order No. 1000.
3
Transmission facility selected in a regional transmission plan for purposes of cost allocation: A transmission facility that has been selected, pursuant to a Commission-approved regional transmission planning process, as a more efficient or cost-effective solution to regional transmission needs. This term does not include: (1) facilities planned by local planning processes that are “rolled-up” into regional plans; (2) facilities for which the sponsor does not intend to seek cost allocation under the regional cost allocation methodology (i.e., merchant transmission facilities). Transmission planning region: The region in which a public utility transmission provider, in consultation with stakeholders and affected states, has agreed to participate for purposes of regional transmission planning and development of a single regional transmission plan. For Regional Transmission Organization (“RTO”) members, the transmission planning region is the RTO region.
3. ORDER NO. 1000 NONINCUMBENT TRANSMISSION DEVELOPER PARTICIPATION REQUIREMENTS As part of its requirement that public utility transmission providers remove federal rights of first refusal from FERC-approved tariffs and agreements, Order No. 1000 requires each public utility transmission provider to revise its OATT to demonstrate that the regional transmission planning process in which it participates has established: (1)
Appropriate qualification criteria for determining an entity’s eligibility to propose a transmission project for selection in the regional transmission plan for purposes of cost allocation, regardless of whether the entity is an incumbent transmission provider or a nonincumbent transmission developer;
(2)
Requirements for the information that must be submitted in support of a proposed transmission project and the date by which project proposals must be submitted;
(3)
A transparent process for evaluating whether to select a proposed transmission facility in the regional transmission plan for purposes of cost allocation which is not unduly discriminatory; and
(4)
Cost allocation provisions that provide nonincumbent transmission developers the same eligibility as incumbent transmission providers to use the regional cost allocation method(s) for any transmission facility selected in the regional transmission plan for purposes of cost allocation.
This white paper focuses on the first of these requirements – that each public utility transmission provider participate in a regional transmission planning process that has established appropriate qualification criteria for determining an entity’s eligibility to propose a transmission project for
4
selection in the regional transmission plan for purposes of cost allocation, whether the entity is an incumbent transmission provider or a nonincumbent transmission developer. These criteria must not be unduly discriminatory or preferential, and should be fair and not unreasonably stringent when applied to either the incumbent transmission provider or nonincumbent transmission developers.4 The qualification criteria also must provide each potential transmission developer the opportunity to demonstrate that it has the necessary financial resources and technical expertise to develop, construct, own, operate, and maintain transmission facilities.5 However, beyond these general requirements, Order No. 1000 leaves it to each region to develop qualification criteria that are workable for the region, including procedures for timely notifying transmission developers of whether they satisfy the region’s qualification criteria and opportunities to mitigate any deficiencies. Order No. 1000 anticipates that, in some regions, existing procedures allowing for stakeholders to offer potential solutions may provide a foundation for implementing the nonincumbent transmission developer participation requirements, including the qualification criteria. The qualification criteria are intended to apply only to entities that propose transmission projects and intend to develop the proposed transmission project if selected. Stakeholders that do not intend to develop transmission projects may continue to propose transmission projects for consideration in the regional transmission plan without being required to demonstrate compliance with the qualification criteria. As part of this nonincumbent transmission developer participation requirement, Order No. 1000 requires public utility transmission providers to develop and include in their OATTs language establishing procedures for timely notifying prospective transmission developers of whether they satisfy the qualification criteria, as well as a time period for the prospective transmission developer to mitigate any deficiencies in its qualifications.
4. EXISTING SPP OATT AND BUSINESS PRACTICES As discussed above, Order No. 1000 envisions the possibility that existing practices in regional transmission planning processes may serve as a foundation for implementing the nonincumbent transmission developer participation requirements of Order No. 1000. SPP previously has adopted provisions in both its OATT and Business Practices that govern the qualification and selection of alternate entities seeking to build transmission projects that a Designated Transmission Owner is unable or unwilling to build. SPP staff recommends that the SPC consider these existing provisions when developing the qualification criteria that SPP will propose in its Order No. 1000 compliance filing. 4
Order No. 1000 indicates that the qualification criteria should allow for the possibility that existing public utility transmission providers already satisfy the criteria and should allow any transmission developer the opportunity to remedy any deficiency in its qualifications.
5
Order No. 1000 states that “nothing in the qualifications requirements of this Final Rule is intended to change any existing RTO procedure or practice regarding the operation of existing transmission facilities.” Order No. 1000 at P 324 n.303.
5
4.1 SPP OATT Attachment O of the SPP OATT, which governs SPP’s Integrated Transmission Plan (“ITP”) process, requires that if a Designated Transmission Owner for a transmission project does not provide an acceptable written commitment to construct a project within 90 days of receipt of a Notification to Construct, SPP must solicit and evaluate proposals for the project from other entities and select a replacement builder for the project. To be considered, a prospective replacement builder must meet several general legal, regulatory, technical, financial, and managerial qualifications specified in Section IV.6 of Attachment O. Specifically, the prospective replacement builder must: (i)
Have obtained all state regulatory authority necessary to construct, own and operate transmission facilities within the state(s) where the project will be located;
(ii)
Meet SPP’s creditworthiness requirements set forth in Attachment X of the SPP OATT;
(iii)
Sign or being capable and willing to sign the SPP Membership Agreement as a Transmission Owner upon selection of its proposal to construct and own the project; and
(iv)
Meet other technical, financial, and managerial qualifications as are specified in the SPP Business Practices.
These criteria currently apply only to entities that wish to be selected as an alternate builder when a Designated Transmission Owner is unable or unwilling to accept a Notification to Construct; however, they could form the basis for SPP’s adoption of the qualification criteria required by Order No. 1000. To be acceptable, these criteria would need to apply to any entity that wishes to propose transmission projects for consideration in the SPP regional planning process, including both incumbent SPP Transmission Owners and nonincumbent transmission developers. SPP could amend Attachment O to apply these criteria to all entities that seek to build transmission facilities and recover their costs under the SPP OATT. While these criteria provide a foundation for SPP’s compliance with Order No. 1000’s qualification criteria requirement, they are not sufficiently detailed to “provide each potential transmission developer the opportunity to demonstrate that it has the necessary financial resources and technical expertise to develop, construct, own, operate and maintain transmission facilities” as Order No. 1000 requires.6 Specifically, SPP will need to include in its OATT the specific technical, financial, and managerial qualification criteria that entities will need to satisfy before being eligible to build transmission facilities identified in the SPP regional planning process, as well as guidance specifying how SPP will determine whether an entity satisfies the qualification criteria.
6
Order No. 1000 at P 323.
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4.2 SPP Business Practices As part of the effort to develop a process for selection of alternative builders as required by Attachment O, SPP’s Transmission Owner Selection Task Force published in January 2010 a Transmission Owner Selection Process document (“Process Document”). The Process Document outlined SPP’s procedures for establishing a Transmission Owner Selection Committee to conduct Request for Information (“RFI”) and Request for Proposal (“RFP”) processes to identify an alternate builder when a Designated Transmission Owner is unable or unwilling to commit to construct a transmission project. The Process Document listed several requirements for RFP bids, many of which relate to the bidder’s qualifications to develop, construct, own, operate, and maintain transmission facilities. The procedures outlined in the Process Document were subsequently incorporated into SPP Business Practice 1.16. Specifically, Appendix 3 of Business Practice 1.16 lists the requirements for submitting an RFP. Additionally, Appendix 4 of Business Practice 1.16 sets forth the factors SPP utilizes in its process to select among entities that respond to an RFP. Several of the RFP requirements and selection factors could form the basis for SPP’s qualification criteria, including: Managerial qualifications. Financial Qualifications: demonstration of financing and ability to finance new transmission construction in SPP, ability to meet SPP creditworthiness requirements, statement of cost recovery, and demonstration of revenue requirement calculations. Transmission Project Construction Expertise: engineering, permitting, environmental, right-of-way acquisition, procurement, project management, construction, commissioning, technology content, demonstration of applicable qualifications and certifications to construct in the state(s) in which construction is required; demonstration of past transmission construction experience; equipment acquisition process; description of applicable right-of-way and real estate acquisition process; description of routing process; description of permitting processes; eminent domain status; process for obtaining easements; surveying responsibility. Safety Qualifications: internal safety program, contractor safety program, safety performance record (program execution). Operations Expertise: demonstration of control center operations (staffing, etc.), demonstration of NERC compliance process and compliance history, demonstration of registration or ability to register for compliance with applicable NERC Reliability Standards, storm/outage response plan, past reliability performance, statement of which entity will be operating and maintaining completed transmission facilities, staffing, equipment, and crew training.
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Maintenance Qualifications: staffing, maintenance plans, equipment, crew training, record of maintenance performance, maintenance expertise, NERC compliance process and history. Identification of major partners, contractors, and associated contracts. Ability to comply with Good Utility Practice, SPP criteria, industry standards, and applicable local, state, and federal requirements. While these categories may provide a basis for SPP to develop qualification criteria to comply with Order No. 1000, SPP will need to define what it determines to be acceptable to satisfy each of the qualification criteria it adopts and include such information in its OATT. 4.3 SPP Due Diligence Review Process for Novations In reviewing requested novation agreements, SPP has engaged in due diligence reviews of proposed replacement builders on an ad hoc basis. While the SPP OATT does not address the novation process nor the due diligence review, some of the characteristics SPP has reviewed in determining whether to approve a replacement builder and grant a novation include: staffing levels; engineering expertise; expertise in permitting (including environmental and cultural requirements); real estate acquisition and condemnation experience, including right-of-way and easement acquisition; procurement staffing; project management staffing, tools, and process; construction expertise and contracting; commissioning expertise; and operations center, field operations, and maintenance experience. SPP could use its due diligence review process as a basis for developing qualification criteria to adopt in its OATT to comply with Order No. 1000; however, as discussed above, SPP will need to define what it determines to be acceptable to satisfy each of the qualification criteria and include such information in its OATT.
5. CONCLUSION As part of its filing to comply with the nonincumbent transmission developer participation requirements of Order No. 1000, SPP must develop qualification criteria for entities seeking to propose and develop projects to be considered in the SPP ITP process. The qualification criteria must apply both to incumbent SPP Transmission Owners and nonincumbent transmission developers seeking to qualify to propose and develop transmission facilities in the SPP regional transmission planning process. Existing SPP OATT and Business Practice language and SPP’s existing experience with evaluating potential replacement builders in its novation agreement process may provide a basis for the categories of qualification criteria that SPP could consider to fulfill this requirement. However, SPP will need to develop the qualification criteria further to provide clear standards or guidelines regarding the characteristics of a prospective transmission developer that would satisfy or fail to satisfy the qualification criteria. SPP will also need to establish procedures for timely notifying prospective transmission developers of whether they satisfy the qualification criteria, as well as a time period for the prospective transmission developer to mitigate any deficiencies in its qualifications.
8
Below is a recommended list of qualification criteria. This list provides the general qualification criteria that SPP staff proposes be adopted for entities seeking to propose and construct transmission facilities in the SPP planning process. If the SPC agrees with these proposed criteria, SPP Staff will further define the specific qualification criteria. The Staff recommended qualification criteria is: (i)
Threshold eligibility criteria a. The developer must have obtained all state regulatory authority necessary to construct, own, and operate transmission facilities within the state(s) where the project will be located. b. The developer must sign or be capable and willing to sign the SPP Membership Agreement as a Transmission Owner upon selection of its proposal to construct and own the project.
(ii)
Financial criteria a. The developer must meet SPP’s creditworthiness requirements set forth in Attachment X of the SPP OATT. b. The developer must demonstrate the ability to finance new transmission construction in SPP.
(iii)
Managerial criteria a. The developer must demonstrate the ability to site the project. This requires: i. Expertise in permitting, environmental compliance, and right-of-way; and ii. Description of applicable right-of-way and real estate acquisition processes, routing process, permitting processes, eminent domain status, process for obtaining easements; and surveying responsibility. b. The developer must demonstrate the ability to construct the project. This requires: i. Demonstration of applicable qualifications and certifications to construct in the state(s) in which construction is required; ii. Expertise in engineering, procurement and equipment acquisition process, project management, construction; and iii. If the developer plans to engage a contractor to construct the project, the developer must demonstrate how the contractor satisfies the above criteria. c. The developer must demonstrate the ability to operate and maintain the project. This requires: i. Demonstration of the ability to manage the operation and maintenance of electric transmission facilities including, if applicable, experience in managing the operation and maintenance of existing transmission facilities. ii. Demonstration of the ability to operate and maintain the project safely, including a description of the developer’s internal safety program,
9
contractor safety program, and safety performance record and program execution. iii. Expertise in operations, which includes demonstration of control center operations, a description of control center staffing, and facilities, communications and SCADA expertise, demonstration of NERC compliance process and description of NERC compliance history, demonstration of registration or ability to register for compliance with applicable NERC Reliability Standards, demonstration of a storm/outage response plan, description of past reliability performance, a statement specifying which entity will be operating and maintaining completed transmission facilities, equipment, including plans for maintaining spare parts, and crew training. SPP also must develop a process for incumbent/nonincumbent transmission developers to submit the information necessary for SPP to evaluate whether they satisfy the qualification criteria. SPP staff proposes to establish the following process in the OATT: (1)
Prior to being eligible to propose transmission projects in the SPP regional planning process, transmission developers (including incumbent transmission owners and nonincumbent transmission developers) are required submit an application demonstrating their satisfaction of the qualification criteria to SPP;
(2)
The application can be submitted at any time, but must be submitted at least 120 days before the developer plans to submit a project for consideration in the SPP planning process;
(3)
SPP will review the transmission developer’s application to determine whether it satisfies the qualification criteria and inform the applicant of its determination within 90 days of receipt of the application; and
(4)
If SPP determines that the transmission developer fails to meet one or more of the qualification criteria, SPP will inform the transmission developers of such deficiency and the transmission developer will have 30 days to cure the deficiency.
Once SPP has determined that a transmission developer satisfies the qualification criteria, the transmission developer will be deemed qualified to propose projects in the SPP planning process and will not be required to demonstrate its qualifications in any subsequent planning process cycle or with respect to any subsequent transmission project proposal. However, all transmission developers that have been deemed qualified will be required to inform SPP if, at any time, there is any change to the information provided in their application, so that SPP may determine whether to satisfy the qualification criteria. If any change occurs, SPP will have the option to:
10
(1)
Determine that the change does not affect the transmission developer’s qualification to propose and construct projects;
(2)
Determine that the transmission developer no longer qualifies to propose and construct projects;
(3)
Suspend the transmission developer’s eligibility to propose and construct projects until the transmission developer has cured any deficiency in its qualifications to SPP’s satisfaction; or
(4)
Allow the transmission developer to continue to participate in the proposal and construction process for a limited time period while it cures the deficiency to SPP’s satisfaction.
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FERC Order No. 1000 Transmission Developer Selection Process
White Paper Published by: SPP Legal/Regulatory For the SPP Strategic Planning Committee Task Force on Order No. 1000
DRAFT 11/04/2011
1
TABLE OF CONTENTS 1. HISTORY AND BACKGROUND ........................................................................................... 3 2. DEFINITIONS ........................................................................................................................... 4 3. OPTIONS FOR SELECTING AMONG COMPETING TRANSMISSION DEVELOPERS.. 4 3.1 Sponsorship Model........................................................................................................... 4 3.2 Competitive Solicitation................................................................................................... 5 3.3 Other ................................................................................................................................. 6 4. CONCLUSION .......................................................................................................................... 6
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1. HISTORY AND BACKGROUND On July 21, 2011, the Federal Energy Regulatory Commission (“FERC”) issued Order No. 1000,1 which requires all public utility transmission providers to (among other things) facilitate nonincumbent transmission developer participation in regional transmission planning by removing from FERC-approved tariffs and agreements any language creating a federal right of first refusal (“ROFR”) for an incumbent transmission provider to construct transmission facilities selected in a regional transmission plan for cost allocation.2 Implicit in the requirement to eliminate federal ROFR for incumbent transmission providers is that the regional planning process develop procedures for selecting which entity will construct each project selected in the regional transmission plan for purposes of cost allocation. This white paper sets forth several options for transmission developer selection processes that SPP staff has identified to comply with the Order No. 1000 requirement to eliminate federal ROFR and allow participation by nonincumbent transmission developers on a nondiscriminatory basis. SPP Staff believes that the options specified below, if implemented on a nondiscriminatory basis and in compliance with the transmission planning requirements of Order Nos. 8903 and 1000, may be acceptable to FERC. SPP has identified several potential options for transmission developer selection, as discussed in more detail in Section 3 of this white paper: (1) Project Sponsorship Model: Projects will be assigned to the entity that proposed or “sponsored” the project in the SPP planning process; (2) Competitive Solicitation: Each project selected in the SPP planning process will be subject to competitive bidding by qualified entities, with the winner to be selected by SPP on the basis of criteria set forth in the SPP Tariff and business practices; or (3) Other: SPP and its stakeholders develop a different process for selecting which entity will construct each project selected in the SPP planning process.
1
Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, III FERC Stats. & Regs., Regs. Preambles ¶ 31,323 (2011).
2
Order No. 1000 indicates that the elimination of federal ROFR from FERC-approved tariffs and agreements does not: (1) apply to transmission facilities not selected in a regional transmission plan for purposes of cost allocation; (2) apply to upgrades to existing transmission facilities, such as tower change outs or reconductoring; (3) affect existing rights-of-way; and (4) affect state or local laws or regulations regarding the construction or siting of transmission facilities.
3
Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 2006-2007 FERC Stats. & Regs., Regs. Preambles ¶ 31,241, order on reh’g, Order No. 890-A, 2006-2007 FERC Stats. & Regs., Regs. Preambles ¶ 31,261 (2007), order on reh’g and clarification, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g and clarification, Order No. 890-C, 126 FERC ¶ 61,228 (2009), order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).
3
2. DEFINITIONS Order No. 1000 uses the following terminology relevant to this white paper: Incumbent transmission developer/provider: An entity that develops a transmission project within its own retail distribution service territory or footprint. Nonincumbent transmission developer: An entity that either: (1) does not have a retail distribution service territory or footprint; or (2) is a public utility transmission provider that proposes a transmission project outside of its existing retail distribution service territory or footprint, where it is not the “incumbent” for purposes of the project. Transmission facility selected in a regional transmission plan for purposes of cost allocation: A transmission facility that has been selected, pursuant to a Commission-approved regional transmission planning process, as a more efficient or cost-effective solution to regional transmission needs. This term does not include: (1) facilities planned by local planning processes that are “rolled-up” into regional plans; (2) facilities for which the sponsor does not intend to seek cost allocation under the regional cost allocation methodology (i.e., merchant transmission facilities). Transmission planning region: The region in which a public utility transmission provider, in consultation with stakeholders and affected states, has agreed to participate for purposes of regional transmission planning and development of a single regional transmission plan. For Regional Transmission Organization (“RTO”) members, the transmission planning region is the RTO region.
3. OPTIONS FOR SELECTING AMONG COMPETING TRANSMISSION DEVELOPERS 3.1 Sponsorship Model In the Notice of Proposed Rulemaking that resulted in Order No. 1000, FERC expressly proposed that an entity that proposes or “sponsors” a project in the regional planning process would be granted the right to build the project if it is selected in the regional transmission plan.4 In Order No. 1000, FERC decided not to adopt its proposal that would give a project sponsor the federal right to construct and own a transmission facility it sponsored in the regional planning process.5 However, while Order No. 1000 did not mandate a sponsorship model, neither did it 4
See, e.g., Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Notice of Proposed Rulemaking, IV FERC Stats. & Regs., Proposed Regs. ¶ 32,660, at P 93 (2010) (“We also propose to require that each public utility transmission provider to amend its OATT to describe how the regional transmission planning process in which it participates provides for the sponsor (whether an incumbent transmission provider or nonincumbent transmission developer) of a facility that is selected through the regional transmission planning process for inclusion in the regional transmission plan to have a right, consistent with state or local laws or regulations, to construct and own that facility.”).
5
See, e.g., Order No. 1000 at PP 334, 338.
4
prohibit such an approach to determining which entity will construct a project in the regional transmission plan for purposes of cost allocation. In fact, throughout Order No. 1000, FERC repeatedly refers to project “sponsors,”6 suggesting that a nondiscriminatory sponsorship model may satisfy the requirements of Order No. 1000. Under a sponsorship model, an entity seeking to construct transmission projects in the SPP planning process would first need to demonstrate its eligibility to participate in the SPP planning process by satisfying a series of qualification criteria set forth in the SPP Tariff. Order No. 1000 requires each regional planning process to develop qualification criteria “for determining an entity’s eligibility to propose a transmission project for selection in the regional transmission plan for purposes of cost allocation, whether that entity is an incumbent transmission provider or a nonincumbent transmission developer.”7 SPP can tailor the qualification criteria to ensure that only qualified entities are permitted to propose projects and be designated as the Designated Transmission Owner if the project is selected in the SPP planning process. If SPP opts for a sponsorship approach, SPP will need to develop a process for what to do if a selected project is modified from its original proposal, two sponsored projects are combined into a single project, or SPP selects a project that does not have a sponsor in the planning process. 3.2 Competitive Solicitation Throughout Order No. 1000, FERC indicated that transmission planning regions may adopt a competitive solicitation process to identify transmission projects and developers to build those projects.8 While Order No. 1000 provided very little guidance on the design of a competitive solicitation process for selecting transmission projects and developers, SPP could use as a basis for this approach its current process set forth in Section VI.6 of Attachment O of the SPP Tariff for selecting an alternate entity to build a transmission facility if the Designated Transmission Owner is unable or unwilling to construct an assigned transmission facility. Any entity seeking to bid on a project in the SPP planning process would be required to satisfy the qualification criteria required by Order No. 1000.9
6
See, e.g., id. at P 267 (“The Commission recognizes that there may be circumstances when an incumbent transmission provider may be called upon to complete a transmission project that it did not sponsor. . . . There also may be situations in which an incumbent transmission provider has an obligation to build a project that is selected in the regional transmission plan for purposes of cost allocation but has not been sponsored by another transmission developer.”); id. at P 332 (“The Commission also requires that a nonincumbent transmission developer must have the same eligibility as an incumbent transmission developer to use a regional cost allocation method or methods for any sponsored transmission facility selected in the regional transmission plan for purposes of cost allocation.”) (emphasis added).
7
Id. at PP 323.
8
Id. at P 321 (“For example, this Final Rule permits a region to use or retain an existing mechanism that relies on competitive solicitation to identify preferred solutions to regional transmission needs.”) (emphasis added); see also id. at P 336 (“This mechanism could be, for example, a non-discriminatory competitive bidding process.”) (emphasis added).
9
See supra note 7 and accompanying text.
5
3.3 Other SPP Staff does not believe that the two options identified above are the only options to address the issue of transmission construction and ownership assignment in the SPP planning process. It is possible that SPP and its stakeholders could establish a process that combines elements of the sponsorship and competitive solicitation models or some different process altogether. In any event, whichever option SPP selects will need to provide comparable and nondiscriminatory treatment to incumbent transmission owners and nonincumbent transmission developers.
4. CONCLUSION As part of its filing to comply Order No. 1000, SPP will need to develop a process for determining which entity will construct each project selected in the SPP planning process for cost allocation. SPP staff believes that a properly-structured project sponsorship model or competitive bidding process may satisfy the requirements of Order No. 1000 to facilitate nonincumbent participation in the SPP planning process. However, SPP and its stakeholders could develop an alternative to these approaches, provided it is not unduly discriminatory and complies with the planning requirements of Order Nos. 890 and 1000.
6
FERC Order No. 1000 Project Proposal Information Submission Requirements, Project Evaluation, and Project Re-evaluation Criteria
White Paper Published by: Special Studies & Engineering Support For the SPP Strategic Planning Committee
Draft 10/6/2011
Southwest Power Pool Transmission Developer Submission Requirements Approved by :
September 30, 2010
Table of Contents Background 1. Proposal Submission Requirements ITP Near-Term and ITP 10: ITP 20 required information: 2. Project Evaluation 3. Plan Re-evaluation
3 3 3 4 4 5
2
Southwest Power Pool Transmission Developer Submission Requirements
Background The Federal Energy Regulatory Commission (FERC) issued Order No. 1000 which amended the transmission planning and cost allocation requirements established in Order No. 890. FERC Order No. 1000 reforms are intended to improve transmission planning processes and cost allocation mechanisms under the pro forma Open Access Transmission Tariff (OATT) to ensure that the rates, terms and conditions of service provided by public utility transmission providers are just and reasonable and not unduly discriminatory or preferential. Each public utility transmission provider is required to have a coordinated, open, and transparent regional transmission planning process. This whitepaper establishes SPPs processes to comply with requirements resulting from FERC Order No. 1000. These requirements relate to transmission project proposal submission by a transmission developer, project evaluation, and project re-evaluation criteria for projects proposed to SPP’s regional planning process. SPP’s regional planning process is named the Integrated Transmission Planning (ITP) process. The ITP consists of three (3) horizons for which the transmission system is planned. These three (3) horizons are the ITP Near-Term (ITPNT) (years 1-6), ITP10 (years 6-10), and ITP20 (year 20). 1.
Project Proposal Submission Requirements A qualified transmission developer entity submitting proposals for transmission projects to SPP during the ITP process must provide sufficient information to facilitate SPP’s evaluation of such proposed transmission projects. This information should confirm that the proposed transmission project(s), at a minimum, mitigates an issue that was observed in the ITP NearTerm or ITP 10 reliability assessment and was reported to SPP stakeholders as part of the ITP process. SPP will provide models used in these reliability assessments to support this information submission requirement. Proposal submission information requirements differ for the ITP20 planning horizon which does not require a reliability assessment. For the ITP20 planning horizon, SPP will provide a generic set of models and economics data. Proposal submission information guidelines for the ITP planning horizons are listed below.
ITPNT and ITP10 Information required: Description of the issue(s) identified in the ITP Process to be addressed by the proposed project Notification of any changes in modeling assumptions from those used in the current ITP Process Transmission project analysis Power System Simulator for Engineering (PSSE) cases Results of any transmission project economic analysis Summary of economic modeling assumptions (if different from those used by SPP in the current ITP process) Full description of project o Required current ampacity (capacity) of project
3
Southwest Power Pool Transmission Developer Submission Requirements
o Estimated mileage of project o Any known environmental impacts caused by the addition of the project Additional information not required, but preferred, if available include the following: Summary of any stability analysis conducted (steady-state and dynamic)
ITP20 Information required: Description of issue identified in the ITP Process to be addressed by the proposed project Notification of any changes in modeling assumptions from those used in the current ITP Process Results of all transmission project economic analysis Summary of economic modeling assumptions (if different from those used by SPP in the current ITP process) Full description of project o Required current ampacity (capacity) of project o Estimated mileage of project o Any known environmental impacts caused by the addition of the project Additional information not required, but preferred, if available include the following: Transmission project analysis PSSE cases Summary of any stability analysis conducted (steady-state and dynamic) All transmission project proposals and required information supporting such proposals must be submitted to SPP within 60 days following the appropriate Transmission Planning Summit. 2.
Project Evaluation All proposed transmission projects identified by SPP staff or submitted by qualified developers and stakeholders that meet the established proposal submission information requirements will be evaluated in the ITP process. The evaluation will include a preliminary screening process to determine the most viable transmission projects. This screening process will include, but not be limited to a reliability assessment relative to the SPP planning criteria for the ITPNT and ITP10 planning horizons. This screening process may also include, but not be limited to Adjusted Production Cost (APC) economic analysis for ITP10 and ITP20 planning horizons. Transmission projects remaining after the screening process will undergo a detailed cost analysis. Also, an evaluation of a number of benefit metrics developed and outlined by the Economic Studies Working Group (ESWG) will be performed. The final transmission solution set selected in each ITP horizon will be based on the benefit metrics most relevant to each ITP horizon as well as feedback from SPP stakeholders. For further detail on the ITP transmission project evaluation process, please refer to the ITP manual: ITP Manual.
4
Southwest Power Pool Transmission Developer Submission Requirements
Upon conclusion of the ITP process SPP will provide a final report that discusses the final set of transmission projects selected and the rationale supporting the project selections. Costs of transmission projects submitted by qualified developers and stakeholders that are selected in the ITP process will be allocated using SPP’s Highway Bi-way cost allocation methodology. 3.
Plan Re-evaluation In the event a transmission project selected in the ITP process is delayed, SPP will review the project to determine whether its delay, if not mitigated, adversely impacts transmission system reliability or existing service obligations. SPP will notify stakeholders when SPP determines a need to re-evaluate the ITP transmission plan. SPP’s review of the need to reevaluate the ITP transmission plan will be based on the following: Reliability Impact If SPP determines that the transmission project delay would result in the violation of SPP’s planning criteria, a mitigation plan must be developed to resolve the violation for the duration of the project delay. SPP staff and the affected Transmission Owner(s) will meet to determine a mitigation plan for the violation. The mitigation plan may be transmission or non-transmission based and will affect the decision to re-evaluate the ITP transmission plan as follows. Non-transmission based mitigations Mitigation plans that do not require upgrades to the transmission system (i.e. generation redispatch or operating guides) shall not require re-evaluation of the ITP transmission plan prior to being implemented.
Transmission based mitigations Mitigation plans that require upgrades to the transmission system will require a reevaluation of the ITP transmission plan prior to being implemented. Under this reevaluation, qualified developers and stakeholders will be allowed 30 days from the date SPP issues a notification of the re-evaluation determination to submit proposals and supporting information for transmission projects to resolve the identified issue(s) resulting from the project delay. All projects submitted by qualified developers and stakeholders meeting the information submittal requirements will be re-evaluated consistent with the ITP project evaluation process. Service Obligation Impact If SPP determines that the transmission project delay would result in the inability to honor a transmission service obligation, a mitigation plan must be developed to resolve the violation for the duration of the project delay. SPP staff, along with the affected customer(s) and Transmission Owner(s) will meet to determine a mitigation plan for the issue. The mitigation
5
Southwest Power Pool Transmission Developer Submission Requirements
plan may be transmission or non-transmission based and will affect the decision to reevaluate the ITP transmission plan as follows; Non-transmission based mitigations Mitigation plans that do not require upgrades to the transmission system (i.e. generation redispatch or operating guides) shall not require re-evaluation of the regional transmission plan prior to being implemented. Transmission based mitigations Mitigation plans that require upgrades to the transmission system will require a re-evaluation of the ITP transmission plan prior to being implemented. Under this re-evaluation, qualified developers and stakeholders will be allowed 30 days from the date SPP issues a notification of the re-evaluation determination to submit proposals and supporting information for transmission projects to resolve the identified issue(s) resulting from the project delay. All projects submitted by qualified developers and stakeholders meeting the information submittal requirements will be re-evaluated consistent with the ITP project evaluation process.
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MEMORANDUM To:
SPP Strategic Planning Committee Task Force on Order No. 1000
From:
Paul Suskie General Counsel & Senior Vice President–Regulatory Policy Southwest Power Pool, Inc. Matt Binette Wright & Talisman, P.C. Counsel for Southwest Power Pool, Inc.
Date:
December 8, 2011
Re:
Federal Right of First Refusal in SPP Governing Documents
In Order No. 1000, 1 the Federal Energy Regulatory Commission (“FERC”) directed all public utility transmission providers to (among other things) eliminate from their FERCjurisdictional tariffs and agreements any provisions “that establish a federal right of first refusal (“ROFR”) for an incumbent transmission provider with respect to transmission facilities selected in a regional transmission plan for purposes of cost allocation.” 2 The current SPP Membership Agreement and Attachment O of the SPP Tariff contain a federal ROFR for incumbent transmission owners. Because both the SPP Tariff and Membership Agreement are FERCjurisdictional agreements, SPP must modify them to remove the federal ROFR for incumbent transmission owners. 3 I.
SPP MEMBERSHIP AGREEMENT A.
Construction Provisions of the SPP Membership Agreement
Section 3.3 of the SPP Membership Agreement, which governs construction of transmission facilities in SPP, contains federal ROFR language that will need to be modified to comply with Order No. 1000. Specifically, Section 3.3(b) of the SPP Membership Agreement indicates:
1
Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, III FERC Stats. & Regs., Regs. Preambles ¶ 31,323 (2011) (“Order No. 1000”).
2
Id. at P 313. Order No. 1000 continues to permit an incumbent transmission provider to meet its reliability needs or service obligations by choosing to build new transmission facilities that are located solely within its retail distribution service territory or footprint and that are not included in the regional transmission plan or subject to the regional cost allocation methodology. Id. at P 262.
3
It should be noted that SPP may retain the ROFR language for transmission projects that are not selected in the regional plan for cost allocation, such as local transmission facilities (as defined in Order No. 1000), upgrades to existing facilities, or facilities constructed along existing rights-of-way. See Order No. 1000 at PP 63, 318-19.
1
After a new transmission project has received the required approvals and been approved by SPP, SPP will direct the appropriate Transmission Owner(s) to begin implementation of the project. If the project forms a connection between the facilities of a single Transmission Owner, that Transmission Owner will be designated to provide the new facilities. If the project forms a connection between facilities owned by multiple parties, all parties will be designated to provide the respective new facilities. The parties will agree among themselves as to how much of the project will be provided by each entity. If agreement cannot be reached, SPP will facilitate the ownership determination process. 4 Thus, under the language of Section 3.3(b), SPP is obligated to designate a Transmission Owner to construct new transmission facilities. Furthermore, Section 3.3(c) of the SPP Membership Agreement states: A designated provider for a project can elect to arrange for a new entity or another Transmission Owner to build and/or own the project in its place. If the designated provider(s) does not or cannot agree to implement the project in a timely manner, SPP will solicit and evaluate proposals for the project from other entities and select a replacement. 5 This language provides an option for the designated Transmission Owner to assign the project to another entity or to decline to “implement the project” (i.e., “refuse” to build the project). When read together, Sections 3.3(b) and 3.3(c) provide incumbent Transmission Owners a federal ROFR over transmission projects approved for construction by SPP. SPP is required to assign the construction obligations for new transmission facilities to incumbent Transmission Owners that own the existing facilities to which a new transmission facility will interconnect. Once a new transmission facility is assigned, the designated Transmission Owner(s) have the option either to construct the project, assign the project to another entity, or decline to construct the project. 6 SPP will need to modify this section to comply with Order No. 1000. B.
Definition of “Transmission Owner”
SPP modified the Membership Agreement definition of “Transmission Owner” in Docket No. ER11-2101 as follows (changes are in blackline): A signatory to this Agreement which: (1) transfers functional control of Tariff Facilities related to the rates, terms and conditions of the OATT to SPP by executing this Agreement; or (2) appoints SPP under another agreement to 4
SPP Membership Agreement § 3.3(b) (emphasis added). Membership Agreement.
5
Id.§ 3.3(c) (emphasis added).
6
The SPP Membership Agreement also contains a requirement that Transmission Owners “use due diligence to construct transmission facilities as directed by SPP.” Id. § 3.3(a). This language requires a designated Transmission Owner to retain its responsibility to construct a transmission facility if SPP is unable to select a replacement.
2
The term “party” is not defined in the
provide service under the Transmission Tariff over Tariff Facilities which it owns or controls; or (3) is assigned by SPP to construct and accepts the obligation to construct new Tariff Facilities; or (4) undertakes another Transmission Owner’s obligation to construct Tariff Facilities in accordance with Section 3.3(c) of this Agreement and Attachment O of the SPP OATT. 7 This language was added primarily to address situations where either: (1) the designated Transmission Owner for a project assigns its construction obligations to an entity that is not currently an SPP Transmission Owner; or (2) the designated Transmission Owner declines to build the project and SPP is required under Section 3.3(c) to select a replacement entity to build the project. 8 While the additional language broadens the definition of “Transmission Owner” beyond those entities that have transferred functional control over facilities to SPP, the language does not modify the manner through which SPP assigns construction obligations. SPP remains obligated under Section 3.3(b) of the SPP Membership Agreement to assign the construction responsibility for a new transmission facility to the existing, incumbent Transmission Owner(s) that own the facilities to which the new transmission facility will interconnect. II.
SPP TARIFF A.
Attachment O
SPP’s Transmission Expansion Plan (“STEP”) and Integrated Transmission Plan (“ITP”) processes set forth in Attachment O contain similar provisions to the Membership Agreement related to assignment of construction obligations and ROFR. Specifically, Section VI of Attachment O, which governs the construction of transmission facilities, contains several provisions that address the manner in which SPP assigns the responsibility to construct transmission facilities in the STEP: Section VI(1): The Transmission Provider, with input from the Transmission Owners and other stakeholders, shall designate in a timely manner within the SPP Transmission Expansion Plan (“STEP”) one or more Transmission Owners to construct, own, and/or finance each project in the plan. 9 Section VI(4): After a new transmission project is (i) approved under the SPP Transmission Expansion Plan or (ii) required pursuant to a Service Agreement or (iii) required by a generation interconnection agreement to be constructed by a Transmission Owner(s) other than the Transmission Owner that is a party to the generation interconnection agreement, the Transmission Provider shall direct the appropriate Transmission Owner(s) to begin implementation of the project for which financial commitment is required prior to the approval of the next update of 7
See Submission of Membership Agreement Revisions to Modify Transmission Owner Definition of Southwest Power Pool, Inc., Docket No. ER11-2101-000 (Nov. 12, 2010) (“MA Definition Filing”). FERC accepted the MA Definition Filing on January 7, 2011, to be effective on January 12, 2011. Sw. Power Pool, Inc., Letter Order, Docket Nos. ER11-2101-000 and ER11-2103-000 (Jan. 7, 2011) (“January 2011 Letter Order”).
8
See id. at 4-5.
9
SPP Tariff, Attachment O § VI(1) (emphasis added).
3
the SPP Transmission Expansion Plan. . . . If the project forms a connection with facilities of a single Transmission Owner, that Transmission Owner shall be designated to construct the project. If the project forms a connection with facilities owned by multiple Transmission Owners, the applicable Transmission Owners will be designated to provide their respective new facilities. If there is more than one Transmission Owner designated to construct a project, the Designated Transmission Owners will agree among themselves which part of the project will be provided by each entity. If the Designated Transmission Owners cannot come to a mutual agreement regarding the assignment and ownership of the project the Transmission Provider will facilitate their discussion. . . . 10 Like Section 3.3(b) of the SPP Membership Agreement, Section VI of Attachment O requires SPP to assign construction and ownership responsibilities for transmission facilities to the incumbent Transmission Owner(s) to whose existing facilities a new transmission facility will interconnect. Section VI of Attachment O also contains language permitting the designated Transmission Owner to assign its construction responsibilities to another entity or to decline to construct a transmission facility. Specifically, Section VI(6) indicates: In order to maintain its right to construct the project, the Designated Transmission Owner shall respond within ninety (90) days after the receipt of the Notification to Construct with a written commitment to construct the project as specified in the Notification to Construct or a proposal for a different project schedule and/or alternative specifications in its written commitment to construct (“Designated Transmission Owner’s proposal”). . . . If a Designated Transmission Owner does not provide an acceptable written commitment to construct within the ninety (90) day period, the Transmission Provider shall solicit and evaluate proposals for the project from other entities and select a replacement designated provider. 11 Therefore, by not providing “an acceptable written commitment to construct,” a designated Transmission Owner (i.e., the incumbent Transmission Owner(s) that own(s) facilities to which the new transmission facility will connect) has the option of declining to construct a facility. 12 Read together, these provisions of Section VI of Attachment O create a federal ROFR for incumbent Transmission Owners that will need to be modified to comply with Order No. 1000. 13 10
Id. § VI(4) (emphasis added).
11
Id. § VI(6) (emphasis added).
12
Attachment O also contains a requirement that the designated Transmission Owner retains “its obligation to construct an upgrade . . . in the event that no other qualified entity can be found to construct the project.” Id.
13
FERC previously has determined that the language of Attachment O establishes a federal ROFR for incumbent transmission owners in SPP. See Sw. Power Pool, Inc., 127 FERC ¶ 61,171, at PP 42-43 (2009) (“We find SPP’s clarification regarding its proposed right of first refusal in section VIII of its Attachment O complies with the requirements of the SPP Planning Order. . . . SPP’s proposed revisions address the ambiguity the Commission was concerned about by clarifying the application of the right of first refusal (continued. . . )
4
B.
Definition of “Transmission Owner”
In a companion filing to its MA Definition Filing, SPP submitted revisions in Docket No. ER11-2103-000 to modify the definition of “Transmission Owner” under the Tariff as follows (revisions in blackline): Each Member of SPP: (i) whose transmission Tariff facilities (in whole or in part) make up the Transmission System or who has accepted from SPP an assignment (notification to construct pursuant to Attachment O) to build and own transmission facilities but does not yet own transmission facilities under SPP’s functional control; and (ii) has executed an SPP mMembership aAgreement as a Transmission Owner. 14 Like the revisions to the definition of Transmission Owner in the MA Definition Filing, 15 SPP submitted these revisions primarily to address situations where either SPP or the designated Transmission Owner selected an entity to build a transmission facility in place of the designated Transmission Owner. 16 These revisions did not modify the existence of a federal ROFR in Attachment O. III.
SPP BYLAWS
The SPP Bylaws do not contain any provisions establishing a federal ROFR for incumbent Transmission Owners. IV.
CONCLUSION
The SPP Membership Agreement and Attachment O of the SPP Tariff contain language establishing a federal ROFR for incumbent Transmission Owners. SPP will need to modify these provisions to remove such a federal ROFR as part of its compliance with Order No. 1000.
(. . . continued) and further limiting it by imposing the 90-day deadline. . . . While we are accepting SPP’s right of first refusal here, the Commission will explore at the technical conferences later this year the impact that such rights of first refusal have on transmission development.”). SPP also acknowledged that its governing documents contain a federal ROFR in its comments in the rulemaking proceeding that culminated in Order No. 1000. See Comments of Southwest Power Pool, Inc. Docket No. RM10-23-000, at 15 (Sept. 29, 2010) (“This limited right of first refusal for incumbent SPP Transmission Owners enables such Transmission Owners to ensure that they have an opportunity to build facilities necessary to satisfy their obligation to build and to serve customers.”). 14
See Submission of Tariff Revisions to Modify Transmission Owner Definition of Southwest Power Pool, Inc., Docket No. ER11-2103-000 (Nov. 12, 2010) (“Tariff Definition Filing”). FERC accepted the Tariff Definition Filing on January 7, 2011, to be effective on January 12, 2011. See January 2011 Letter Order.
15
See supra Section I.B.
16
See Tariff Definition Filing, Transmittal Letter at 4-6.
5
