RM08-19-003 Final Rule on Rehearing, FERC-725A Issued July 15, 2010
RIN No. 1902-AD76
Supporting Statement for
FERC‑725A, Mandatory Reliability Standards for the Bulk-Power System
As Proposed in Docket No. RM08-19-003, RIN No. 1902-AD76
(Final Rule on Rehearing Issued July 15, 2010)
The Federal Energy Regulatory Commission (Commission) (FERC) is submitting a Final Rule on Rehearing that affects the requirements under the following information collection: FERC‑725A, Mandatory Reliability Standards for the Bulk Power System. FERC-725A (Control No. 1902-0244) is a Commission data collection, (filing requirements), as contained in 18 Code of Federal Regulations, Part 40. FERC-725A is currently approved through 3/31/2013. This Order on Rehearing clarifies the requirements in order to more clearly state the obligations imposed in Order No. 729 (see ICR 200912-1902-005 and below) but does not substantively alter those requirements.
Background
On August 8, 2005, The Electricity Modernization Act of 2005, which is Title XII of the Energy Policy Act of 2005 (EPAct 2005), was enacted into law.1 EPAct 2005 added a new section 215 to the FPA and requires a FERC-certified Electric Reliability Organization (ERO) to develop mandatory and enforceable Reliability Standards, which are subject to Commission review and approval. Once approved, the Reliability Standards may be enforced by the ERO, subject to Commission oversight.
As the ERO, NERC worked with industry to develop Reliability Standards improving consistency and transparency of available transfer capability calculation methodologies.2 On April 4, 2006, as modified on August 28, 2006, NERC submitted to the Commission a petition seeking approval of 107 proposed Reliability Standards, including 23 Reliability Standards pertaining to Modeling, Data and Analysis (MOD). The MOD group of Reliability Standards is intended to standardize methodologies and system data needed for traditional transmission system operation and expansion planning, reliability assessment and the calculation of available transfer capability in an open access environment.
Before NERC was formed, reliability of the interconnected electric grid was managed by
the planning and operating criteria, guidelines, and policies of individual electric utilities
and groups of interconnected utilities. Operating policies were then expanded to larger
areas and international scale under the auspices of the North American Power Systems
Interconnected Committee, which was formed in 1962, and ultimately merged with
NERC in 1980.
Shortly after the Northeast Blackout of 1965, Regional Reliability Organizations (RRO)
started to form in the Northeastern United States and Ontario, Canada. In 1968, the electric utility industry established NERC to coordinate the RROs’ activities and to ensure reliability of the electricity supply in North America. By the mid-1990s, NERC began to develop planning standards through a committee system of industry representatives. During this transition, utilities continued to use and maintain their planning policies in conjunction with the development of standards by NERC. In June 2002, the NERC Board of Trustees approved adoption of an open stakeholder process for the development of reliability standards and NERC was accredited by the
American National Standards Institute (ANSI) in March of 2003. NERC planned to revise or develop each standard individually using the ANSI process. However, with the occurrence of the August 2003 blackout, NERC accelerated its efforts and developed as a group the Version 0 standards as a translation of many of NERC’s existing operating policies, planning standards and compliance templates.
On August 14, 2003, an electrical outage in Ohio precipitated a cascading blackout across
seven other states and as far north as Ontario, leaving more than 50 million people without power. The August 2003 blackout was the largest blackout in the history of the United States, leaving some parts of the nation without power for up to four days and costing between $4 billion and $10 billion. The 2003 blackout was the eighth major blackout experienced in North America since the 1965 Northeast Blackout.
On August 15, 2003, President George W. Bush and then-Prime Minister Jean Chrétien
directed the creation of a Joint U.S.-Canada Power System Outage Task Force to investigate the causes of the blackout and ways to reduce the possibility of future outages. The U.S.-Canada Task Force convened, investigated the causes of this blackout, and recommended actions to prevent future widespread outages. The Task Force issued a final Blackout Report in April 2004 with 46 specific recommendations to address the primary causes to help prevent or minimize the scale of future blackouts. These included a recommendation to “make reliability standards
mandatory and enforceable, with penalties for noncompliance,” as well as specific
recommendations to change some existing reliability standards.
In addition, the Blackout Report identified eight factors that were common to some of the
eight major outage occurrences from the 1965 Northeast Blackout through the 2003 Blackout. They were as follows:
(1) conductor contact with trees;
(2) overestimation of dynamic reactive output of system generators;
(3) inability of system operators or coordinators to visualize events on the entire system; (4) failure to ensure that system operation was within safe limits;
(5) lack of coordination on system protection;
(6) ineffective communication;
(7) lack of “safety nets;” and
(8) inadequate training of operating personnel.
The Modeling, Data, and Analysis group (MOD) of the current reliability standards consists of 23 standards aimed at RROs, Transmission Service Providers, Transmission Owners,
Transmission Planners, Generation Owners, Resource Planners, Planning Authorities,
and Load-Serving Entities. The standards can be grouped into four distinct categories.
The first category covers documentation, review, and validation of Total Transfer
Capacity (TTC), Available Transfer Capacity (ATC), Capacity Benefit Margin (CBM),
and Transmission Reliability Margin (TRM) calculations and is applicable to the RROs. The second category covers steady-state and dynamics data and models and is applicable to Transmission Owners, Transmission Planners, Generation Owners, Resource Planners, and the RROs. The third category covers actual and forecast demand data and is applicable to the RROs, Transmission Planners, Planning Authorities, Load-Serving Entities, and Resource Planners.131 The fourth category covers the verification of generator real and reactive power capability and is applicable to the RROs and Generation Owners.
Good data and system models are essential for accurately simulating the performance of
the Bulk Electric System for use in planning, operations planning, real-time operations
and after-the-fact analysis of disturbances. The Blackout Report states that “[t]he after-the-
fact models developed to simulate August 14 conditions and events found that the dynamic modeling assumptions for generator and load power factors in regional planning and operating models were frequently inaccurate. In particular, the assumptions of load power factor were overly optimistic – loads were absorbing much more reactive power than the pre-August 14 models indicated.” To address this deficiency, Recommendation Number 24 of the Blackout Report states the need to “[i]mprove quality of system modeling data and data exchange practices.” In describing the work required, the Blackout Report states that “[p]ower flow and transient stability simulations should be periodically benchmarked with actual system events to validate model data.” While the standards require that steady state and dynamics data be submitted and that steady state and dynamic system models are prepared, there are no requirements to validate these models through periodic benchmarking and appropriately modify them against actual system events in accordance with Recommendation Number 24 of the
Blackout Report.
Order No. 890.
On February 16, 2007, the Commission issued Order No. 890 (see 1902-0233, which addressed and remedied opportunities for undue discrimination under the pro forma Open Access Transmission Tariff (OATT) adopted in Order No. 888. Among other things, the Commission required industry-wide consistency and transparency of all the components of available transfer capability calculation plus certain definitions, data and modeling assumptions. The Commission concluded that the lack of industry-wide standards for the consistent calculation of available transfer capability poses a threat to the reliable operation of the Bulk-Power System, particularly with respect to the inability of one transmission service provider to know with certainty its neighbors’ system conditions affecting its own available transfer capability values. As a result of this reliability concern, the Commission asserted that the proposed available transfer capability reforms were also supported by FPA section 215, through which the Commission has the authority to direct the ERO to submit a Reliability Standard that addresses a specific matter.3 Thus, the Commission in Order No. 890 directed industry to develop Reliability Standards, using the ERO’s Reliability Standards development procedures that provide for consistency and transparency in the methodologies used by transmission owners to calculate available transfer capability.
The Commission stated in Order No. 890 that the available transfer capability-related Reliability Standards should, at a minimum, provide a framework for available transfer capability, total transfer capability and existing transmission commitments calculations. The Commission did not require a single computational process for calculating available transfer capability because among other things, it found that the potential for discrimination and decline in the reliability level does not lie primarily in the choice of an available transfer capability calculation methodology, but rather in the consistent application of its components, input and exchange data, and modeling assumptions.4 The Commission found that, if all of the available transfer capability components, and certain data inputs and assumptions are consistent, the three available transfer capability calculation methodologies would produce predictable and sufficiently accurate, consistent, equivalent and replicable results.5
Order No. 693
On March 16, 2007, the Commission issued Order No. 693, approving 83 of the 107 Reliability Standards filed by NERC in April 2006.6 Of the 83 approved Reliability Standards, the Commission approved ten MOD Reliability Standards.7 However, the Commission directed NERC to prospectively modify nine of the ten approved MOD Reliability Standards to be consistent with the requirements of Order No. 890.8 The Commission reiterated the requirement from Order No. 890 that all available transfer capability components (i.e., total transfer capability, existing transmission commitments, capacity benefit margin, and transmission reliability margin) and certain data input, data exchange, and assumptions be consistent and that the number of industry-wide available transfer capability calculation formulas be few in number, transparent and produce equivalent results.9 The Commission directed public utilities, working through the NERC Reliability Standards and NAESB business practices development processes, to produce workable solutions to implement the available transfer capability-related reforms adopted by the Commission. The Commission also deferred action on 24 proposed Reliability Standards, which did not contain sufficient information to enable the Commission to propose a disposition.10
RM08-19-000 Final Rule, Order No. 729
On November 19, 2009 the Commission issued a Final Rule approving and also directing modifications to six Reliability Standards submitted to it for approval by NERC. The six Reliability Standards pertain to MOD Reliability Standards that contain methodologies for the
consistent and transparent calculation of available transfer capability or available flowgate capability. The Commission in accordance with section 215(d)(5) of the FPA and section 39.5(f) of its regulations, also directed NERC to retire the existing MOD Reliability Standards replaced by the versions proposed in the Final Rule along with a related Facilities Design, Connections and Maintenance (FAC) Reliability Standard. The retirement of these Reliability Standards was to be effective upon the effective date of the revised MOD Reliability Standards.
On the same date, the Commission issued Order No. 676-E, which revised the Commission’s regulations to incorporate by reference in its regulations the latest version (Version 002.1) of certain business practice standards adopted by the Wholesale Electric Quadrant (WEQ) of NAESB (see below). In addition, the Commission directed public utilities to file any necessary tariff revisions, including any revisions to Attachment C to their Open Access Transmission Tariff (OATT), at least ninety days before the prescribed date of compliance with the revised business practice standards, which was meant to be coincident with the implementation date for compliance with the MOD Reliability Standards approved in Order No. 729.
RM05-5-013 Final Rule Order No. 676-E
On November 19, 2009 the Commission amended its regulations to incorporate by reference the latest version (Version 002.1) of business practice standards adopted by the Wholesale Electric Quadrant (WEQ) of the North American Energy Standards Board (NAESB). These revised standards updated an earlier version of the standards that the Commission previously incorporated by reference into its regulations at 18 CFR 38.2 in Order No. 676-C.11
The new and revised standards that NAESB adopted in Version 002.1 enables public utilities to implement requirements of Order Nos. 890, 890-A, and 890-B.12 In addition, these standards modify the Commercial Timing Table (WEQ-004 Appendix D) and Transmission Loading Relief Standards (WEQ-008) to provide clarity and align NAESB’s business practice standards with the reliability standards adopted by the North American Electric Reliability Corporation (NERC), and amend certain ancillary services definitions appearing in the Open Access Same-Time Information Systems (OASIS) Standards (WEQ-001) relating to the inclusion of demand response resources as potential providers of ancillary services.13
RM08-19-003 Final Rule on Rehearing, Order No. 729-B
On July 15, 2010 the Commission issued a Final Rule on Rehearing, granting requests for rehearing of Order No. 729-A, which, inter alia, provided clarification of the implementation timeline for the six Modeling Data, and Analysis Reliability Standards submitted by the North American Electric Reliability Corporation and approved by the Commission in Order No. 729. In addition, the Commission is revising the implementation deadline for compliance with the related North American Energy Standards Board business practice standards incorporated by reference in Order No. 676-E, so that the deadlines for compliance with the requirements of Order Nos. 729 and 676-E remain consistent.
In Order No. 729, the Commission directed that the Reliability Standards become effective according to the schedule proposed by the ERO.14 Thus, the Commission stated that the MOD Reliability Standards are to take effect on the first calendar quarter that is twelve months beyond the date that the Reliability Standards are approved “by all applicable regulatory authorities.”15 The Commission found that this implementation schedule struck a reasonable balance between the need for timely reform and the needs of transmission service providers and transmission operators to make adjustments to their calculations of available transfer capability, capacity benefit margin and transfer reserve margin. In response to comments on its notice of proposed rulemaking, the Commission clarified that, under this plan, the Reliability Standards shall become effective on the first day of the first quarter occurring 365 days after approval by all applicable regulatory authorities. Approval by the Commission would be effective 60 days after the date of publication of the Final Rule in the Federal Register.16
Order No. 676-E set the implementation date for compliance with the NAESB business practice standards coincident with the implementation date of the MOD Reliability Standards approved in Order No. 729. Accordingly, public utilities subject to the NAESB business practice standards were directed to comply with these Version 002.1 business practice standards as of the first day of the first quarter occurring 365 days after approval of the MOD Reliability Standards by all applicable regulatory authorities. Implementation of some of the NAESB business standards will require tariff revisions. The Commission also directed public utilities to submit necessary tariff revisions, including any revisions to Attachment C of their OATT, at least ninety days before the prescribed date for compliance with the revised standards.
A. Justification
1. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY
EPAct 2005 added as noted above, a new section 215 to the FPA, which provides for a system of mandatory and enforceable Reliability Standards. Section 215(d)(1) of the FPA provides that the ERO must file each Reliability Standard or modification to a Reliability Standard that it proposes to be made effective, i.e., mandatory and enforceable, with the Commission. The ERO submitted on April 4, 2006, and as later modified and supplemented, 107 Reliability Standards for Commission approval pursuant to section 215(d) of the FPA.
Section 215(d)(2) of the FPA provides that the Commission may approve, by rule or order, a proposed Reliability Standard or modification to a proposed Reliability Standard if it meets the statutory standard for approval, giving due weight to the technical expertise of the ERO. Alternatively, the Commission may remand a Reliability Standard pursuant to section 215(d)(4) of the FPA. Further, the Commission may order the ERO to submit to the Commission a proposed Reliability Standard or a modification to a Reliability Standard that addresses a specific matter if the Commission considers such a new or modified Reliability Standard appropriate to “carry out” section 215 of the FPA.17 The Commission’s action in this NOPR is based on its authority pursuant to section 215 of the FPA.
In April 1996, as part of its statutory obligation under sections 205 and 206 of the FPA18 to remedy undue discrimination, the Commission adopted Order No. 888 prohibiting public utilities from using their monopoly power over transmission to unduly discriminate against others.19 In that order, the Commission required all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to file open access non-discriminatory transmission tariffs that contained minimum terms and conditions of non-discriminatory service. It also obligated such public utilities to “functionally unbundle” their generation and transmission services. This meant that public utilities had to take transmission service (including ancillary services) for their own new wholesale sales and purchases of electric energy under the open access tariffs, and to separately state their rates for wholesale generation, transmission and ancillary services.20 Each public utility was required to file the pro forma OATT included in Order No. 888 without any deviation (except a limited number of terms and conditions that reflect regional practices).21 After their OATTs became effective, public utilities were allowed to file, pursuant to section 205 of the FPA, deviations that were consistent with or superior to the pro forma OATT’s terms and conditions. (See FERC-516, 1902-0096)
On the same day that it issued Order No. 888, the Commission issued a companion order, Order No. 889,22 addressing the separation of vertically integrated utilities’ transmission and merchant functions, the information transmission service providers were required to make public, and the electronic means they were required to use to do so. Order No. 889 imposed Standards of Conduct governing the separation of, and communications between, the utility’s transmission and wholesale power functions, to prevent the utility from giving its merchant arm preferential access to transmission information. All public utilities that owned, controlled or operated facilities used in the transmission of electric energy in interstate commerce were required to create or participate in an Open Access Same-Time Information System (OASIS) that was to provide existing and potential transmission customers the same access to transmission information. (See FERC-717, 1902-0173)
Among the information public utilities were required to post on their OASIS was the transmission service provider’s calculation of available transfer capability. Though the Commission acknowledged that before-the-fact measurement of the availability of transmission service is “difficult,” the Commission concluded that it was important to give potential transmission customers “an easy-to-understand indicator of service availability.”23 Because formal methods did not then exist to calculate available transfer capability and total transfer capability, the Commission encouraged industry efforts to develop consistent methods for calculating available transfer capability and total transfer capability.24 Order No. 889 ultimately required transmission service providers to base their calculations on “current industry practices, standards and criteria” and to describe their methodology in an Attachment C to their tariffs.25 The Commission noted that the requirement that transmission service providers purchase only available transfer capability that is posted as available “should create an adequate incentive for them to calculate available transfer capability and total transfer capability as accurately and as uniformly as possible.”26
Although Order No. 888 obligated each public utility to calculate the amount of transfer capability on its system available for sale to third parties, the Commission did not standardize the methodology for calculating available transfer capability, nor did it impose any specific requirements regarding the disclosure of the methodologies used by each transmission service provider.27 As a result, a variety of available transfer capability calculation methodologies have been used with very few clear rules governing their use. Moreover, there was often very little transparency about the nature of these calculations, given that many transmission service providers historically filed only summary explanations of their available transfer capability methodologies in Attachment C to their OATTs.
The Available Transmission System Capability Reliability Standard (MOD-001-1) serves as an “umbrella” Reliability Standard that requires each applicable entity to select and implement one or more of the three available transfer capability methodologies found in MOD-028-1, MOD-029-1, or MOD-030-2. MOD-004-1 and MOD-008-1 provide for the calculation of capacity benefit margin and transmission reliability margin, which are inputs into the available transfer capability calculation. NERC stated in its filing these standards wholly address eight of the 24 Reliability Standards that the Commission did not approve in Order No. 693 because further information was needed.
NERC contended that these Reliability Standards will have no undue negative effect on competition, nor will they unreasonably restrict available transfer capability on the Bulk-Power System beyond any restriction necessary for reliability and do not limit the use of the Bulk-Power System in an unduly preferential manner. NERC contends that the increased rigor and transparency introduced in the development of available transfer capability and available flowgate capability calculations serves to mitigate the potential for undue advantages of one competitor over another. Under these Reliability Standards, applicable entities are prohibited from making transmission capability available on a more conservative basis for commercial purposes than for either planning for native load or to use in actual operations, thereby mitigating the potential for differing treatment of native load customers and transmission service customers. NERC stated that data exchange, which has been until now voluntary, is now mandatory and NERC is requiring that the data be used in the available transfer capability/available flowgate capability calculations. None of these requirements existed in the prior available transfer capability-related Reliability Standards. NERC contended that these improvements help the Commission achieve many of the primary objectives of Order No. 890 regarding transparency, standardization and consistency.
2. HOW, BY WHOM, AND FOR WHAT PURPOSE THE INFORMATION IS TO BE USED AND THE CONSEQUENCES OF NOT COLLECTING THE INFORMATION
Prior to enactment of section 215, the Commission had acted primarily as an economic regulator of wholesale power markets and the interstate transmission grid. In this regard, the Commission acted to promote a more reliable electric system by promoting regional coordination and planning of the interstate grid through regional independent system operators (ISOs) and regional transmission organizations (RTOs), adopting transmission pricing policies that provide price signals for the most reliable and efficient operation and expansion of the grid, and providing pricing incentives at the wholesale level for investment in grid improvements and assuring recovery of costs in wholesale transmission rates.
As part of the Commission’s efforts to promote grid reliability, it created a new Office of Electric Reliability. One task of this office has been to participate in NERC’s Reliability readiness reviews of balancing authorities, transmission operators and reliability coordinators in North America to determine their readiness to maintain safe and reliable operations. The Office of Reliability has also been engaged in studies and other activities to assess the longer-term and strategic needs and issues related to power grid reliability.
Sufficient supplies of energy and a reliable way to transport those supplies to customers
are necessary to assure reliable energy availability and to enable competitive markets. Reasonable supply relative to demand is essential for competitive markets to work. Without sufficient delivery infrastructure, some suppliers will not be able to enter the market, customer choices will be limited, and prices will be needlessly volatile. The Commission assists in creating a more reliable electric system by:
• Fostering regional coordination and planning of the interstate grid through independent system operators and regional transmission organizations;
• Adopting transmission policies that provide price signals for the most reliable and efficient operation and expansion of the grid; and
• Providing pricing incentives at the wholesale level for investment in grid improvements and ensuring opportunities for cost recovery in wholesale transmission rates.
The passage of the Electricity Modernization Act of 2005 added to the Commission’s efforts identified above, by giving it the authority to strengthen the reliability of the interstate grid through the grant of new authority pursuant to section 215 of the FPA which provides for a system of mandatory Reliability Standards developed by the ERO, established by FERC, and enforced by the ERO and Regional Entities.
Collectively, the six MOD reliability standards approved by the Commission require transmission service providers and transmission operators to prepare and keep current implementation documents that contain certain information specified in the reliability standards. The Available Transfer Capability implementation documents must describe the Available Transfer Capability methodology in such detail that the results of their calculations can be validated.
These Reliability Standards enhance transparency in the calculation of available transfer capability by requiring transmission operators and transmission service providers to calculate available transfer capability using a specific methodology that is both explicitly documented and available to reliability entities who request it.28 The Reliability Standards also require documentation of the detailed representations of the various components that comprise the available transfer capability equation, including the specification of modeling and risk assumptions and the disclosure of outage processing rules to other reliability entities. These actions make the processes to calculate available transfer capability and its various components more transparent, which in turn will allow the Commission and others to ensure consistency in their application.
NERC submitted Available Transmission System Capability Reliability Standard (MOD-001-1) as part of a set of Reliability Standards designed to work together to support a common reliability goal: to ensure that transmission service providers maintain awareness of available system capability and future flows on their own systems as well as those of their neighbors. NERC stated that, historically, differences in implementation of available transfer capability methodologies and a lack of coordination between transmission service providers have resulted in cases where available transfer capability has been overestimated. As a result, systems have been oversold, resulting in potential or actual system operating limits and interconnection reliability operating limits being exceeded. NERC stated that MOD-001-1 is the foundational Reliability Standard that obliges entities to select a methodology and then calculate available transfer capability or available flowgate capability using that methodology, thereby ensuring that the determination of available transfer capability is accurate and consistent across North America and that the transmission system is neither oversubscribed nor underutilized.
In addition, NERC stated that, unlike the prior set of voluntary available transfer capability standards, MOD-001-1 requires adherence to a specific documented and transparent methodology. NERC stated that it requires applicable entities to calculate available transfer capability on a consistent schedule and for specific timeframes. According to NERC, MOD-001-1 requires users, owners and operators to disclose counterflow assumptions and outage processing rules to other reliability entities. NERC stated that this Reliability Standard prohibits applicable entities from making transmission capability available on a more conservative basis for commercial purposes than the system’s capability in actual operations. NERC’s MOD-001-1 also requires entities, for the first time, to exchange and use available transfer capability data. NERC stated that the Reliability Standard reflects industry’s consensus best practices for determining available transfer capability.
MOD-001-1 also requires several record keeping and information sharing requirements for transmission service providers. Requirement R3 requires each transmission service provider to keep an available transfer capability implementation document that explains the implementation of its chosen methodology(ies), its use of counterflows, the identities of entities with which it exchanges information for coordination purposes, any capacity allocation processes, and the manner in which it considers outages. Requirement R4 requires transmission service providers to keep specific reliability entities advised regarding changes to the available transfer capability implementation document.29 Requirement R5 requires the transmission service provider to make the available transfer capability implementation document available to those same reliability entities.30 Finally, Requirement R9 allows a transmission service provider thirty calendar days to begin to respond to a request from any other transmission service provider, planning coordinator, reliability coordinator or transmission operator for certain data to be used in the requestor’s available transfer capability or available flowgate capability calculations.
As implemented, the Transmission Reliability Margin Methodology Reliability Standard (MOD-008-1) provides for the calculation of transmission reliability margin, which describes the reliability aspects of determining and maintaining a transmission reliability margin and the components of uncertainty that may be considered when making that determination. The purpose of this Reliability Standard is to promote the consistent and reliable calculation, verification, preservation, and use of transmission reliability margin to support analysis and system operations. Transmission reliability margin is transmission transfer capability set aside to mitigate risks to operations, such as deviations in dispatch, load forecast, outages, and similar such conditions. It is distinctly different from capacity benefit margin, which is transmission transfer capability set aside to allow for the import of generation upon the occurrence of a generation capacity deficiency.
Consistent with Order No. 890, NERC proposed three methodologies for calculating available transfer capability as detailed in the following Reliability Standards: MOD-028-1, MOD-029-1 and MOD-030-2. NERC contends that these three methodologies meet the requirements established by the Commission in Order No. 890, as well as those established in Order No. 693.
MOD-028-1 describes the area interchange methodology (previously referred to as the network response available transfer capability methodology) for determining available transfer capability. NERC intends to use the Area Interchange Methodology Reliability Standard to increase consistency and reliability in the development and documentation of transfer capability calculation for short-term use performed by entities using the area interchange methodology to support analysis and system operations.
MOD-029-1 describes the rated system path methodology for determining available transfer capability. NERC intends to use this Reliability Standard to increase consistency and reliability in the development and documentation of transfer capability calculations for short-term use performed by entities using the rated system path methodology to support analysis and system operations.
The flowgate methodology is characterized by identification of key facilities as flowgates. Total flowgate capabilities are determined based on facility ratings and voltage and stability limits. The impacts of existing transmission commitments are determined by simulation. To determine the available flowgate commitments, the transmission service provider or operator must subtract the impacts of existing transmission commitments, capacity benefit margin, and transmission reliability margin, and add the impacts of postbacks and counterflows. Available flowgate capability can be used to determine available transfer capability. MOD-030-2 describes the flowgate methodology (previously referred to as the flowgate network response available transfer capability methodology) for determining available transfer capability. NERC stated that the purpose of the Flowgate Methodology Reliability Standard is to increase consistency and reliability in the development and documentation of transfer capability calculations for short-term use performed by entities using the flowgate methodology to support analysis and system operations.
3. DESCRIBE ANY CONSIDERATION OF THE USE OF IMPROVED TECHNOLOGY TO REDUCE BURDEN AND TECHNICAL OR LEGAL OBSTACLES TO REDUCING BURDEN.
The Commission has developed the capability for electronic filing of all major submissions to the Commission. In Order No. 619, the Commission established an electronic filing initiative that permits over 40 qualified types of documents to be filed over the Internet to its website. This includes the ability to submit standard forms using software that is readily available and easy to use. Electronic filing, combined with electronic posting and service over the web site, permits staff and the public to obtain filings in a faster and more efficient manner. The Commission is working to expand the qualified types of documents that can be filed over the Internet.
In order that the Commission is able to perform its oversight function with regard to Reliability Standards that are proposed by the ERO and established by the Commission, it is essential that the Commission receive timely information regarding all or potential violations of Reliability Standards. While section 215 of the FPA contemplates the filing of the record of an ERO or Regional Entity enforcement action, FERC needs information regarding violations and potential violations at or near the time of occurrence. Therefore, it will work with the ERO and regional reliability organizations to be able to use the electronic filing of information so the Commission receives timely information.
The regulations established in Order No. 693 also require that each Reliability Standard that is approved by the Commission will be maintained on the ERO’s Internet website for public inspection.
4. DESCRIBE EFFORTS TO IDENTIFY DUPLICATION AND SHOW SPECIFICALLY WHY ANY SIMILAR INFORMATION ALREADY AVAILABLE CANNOT BE USED OR MODIFIED FOR USE FOR THE PURPOSE(S) DESCRIBED IN INSTRUCTION NO. 2
Filing requirements are periodically reviewed as OMB review dates arise or as the Commission may deem necessary in carrying out its responsibilities under the FPA in order to eliminate duplication and ensure that filing burden is minimized. There are no similar sources of information available that can be used or modified for these reporting purposes. The filing requirements contained in FERC-725A will incorporate NERC’s requirements. However, all reliability requirements will be subject to FERC approval along with the requirements developed by Regional Entities and Regional Advisory Bodies and the ERO.
5. METHODS USED TO MINIMIZE BURDEN IN COLLECTION OF INFORMATION INVOLVING SMALL ENTITIES
FERC-725A is a filing requirement concerning the implementation of reliability standards by the Electric Reliability Organization and its responsibilities as well as those of Regional Entities and Regional Advisory Bodies in the development of Reliability Standards. The Electricity Modernization Act specifies that the ERO and Regional Entities are not departments, agencies or instrumentalities of the United States government and will not be like most other businesses, profit or not-for–profit. Congress created the concept of the ERO and Regional Entities as select, special purpose entities that will transition the oversight of the Bulk-Power System reliability from voluntary, industry organizations to independent organizations subject to Commission jurisdiction.
Section 215(b) of the FPA requires all users, owners and operators of the Bulk-Power System to comply with Commission-approved Reliability Standards. Each proposed Reliability Standard submitted for approval by NERC applies to some subset of users, owners and operators.
The MOD Reliability Standards apply to transmission service providers and transmission operators, most of which do not fall within the definition of small entities.31 Out of the total universe of entities subject to compliance with the Reliability Standards, approximately 137 entities will be responsible for compliance with the three new Reliability Standards. Of these only six, or less than five percent, have output of four million MWh or less per year.32 The Commission does not consider this a substantial number.
6. CONSEQUENCE TO FEDERAL PROGRAM IF COLLECTION WERE CONDUCTED LESS FREQUENTLY
The Electric Reliability Organization conducts periodic assessments of the reliability and adequacy of the Bulk-Power System in North America and reports its findings to the Commission, the Secretary of Energy, Regional Entities, and Regional Advisory Bodies annually or more frequently if so ordered by the Commission. The ERO and Regional Entities will report to FERC on their enforcement actions and associated penalties and to the Secretary of Energy, relevant Regional entities and relevant Regional Advisory Bodies annually or quarterly in a manner to be prescribed by the Commission. If the information were conducted less frequently or discontinued, the Commission would be placed at a disadvantage in not having the data necessary for monitoring its mandated obligations.
7. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION COLLECTION
FERC-725A is a filing requirement necessary to comply with the applicable provisions of the Electricity Modernization Act of 2005 and section 215 of the Federal Power Act.
In accordance with section 40.2(a) of the Commission’s regulations, each user, owner, or operator of the Bulk-Power System must comply with Commission-approved Reliability Standards developed by the ERO.
The ERO in accordance with section 39.5 of the Commission’s regulations must file each Reliability Standard or a modification to a Reliability Standard with the Commission. The filing is to include a concise statement of the basis and purpose of the proposed Reliability Standard, either a summary of the Reliability development proceedings conducted by the ERO or a summary of the Reliability Standard development proceedings conducted by a Regional Entity together with a summary of the Reliability Standard review proceedings of the ERO and a demonstration that the proposed Reliability Standard is “just, reasonable, not unduly discriminatory or preferential, and in the public interest.
The ERO in accordance with section 40.3 of the Commission’s regulations must make each effective Reliability Standard available on its Internet website. Copies of the effective Reliability Standards will be available from the Commission’s Public Reference Room.
The Commission requires electronic submission of the proposed Reliability Standard or for the modification to a proposed Reliability Standard that is being filed. This comports with the OMB guidelines in 5 CFR 1320.5(d) (2) (iii).
However, it should be noted that individual reliability standards may have records retention schedules that exceed OMB guidelines in 5 CFR 1320.5(d)(2)(iv) of not retaining records for no longer than three years. The Commission is not prescribing a set data retention period to apply to all Reliability Standards.
8. DESCRIBE EFFORTS TO CONSULT OUTSIDE THE AGENCY: SUMMARIZE PUBLIC COMMENTS AND THE AGENCY'S RESPONSE TO THESE COMMENTS
Each Commission rulemaking (both NOPRs and Final Rules) are published in the Federal Register, thereby affording all public utilities and licensees, state commissions, Federal agencies, and other interested parties an opportunity to submit data, views, comments or suggestions concerning the proposed collection of data. The notice procedures also allow for public conferences to be held as required. The Commission has held several workshops and technical conferences to address reliability issues including transition to the NERC reliability standards, operator tools, and reactive power.
Stakeholders in the electric utility industry have also participated in dialogues on the international implications of the ERO and Cross-Boarder Regional Entities during three public bilateral workshops held in the United States and Canada.
As noted above, NERC in response to the requirements of Order No. 890 and the related directives of Order NO. 693, submitted for Commission approval five MOD Reliability Standards on August 29, 2008. On November 21, 2008, NERC submitted for Commission approval a sixth MOD Reliability Standard: MOD-004-1 - Capacity Benefit Margin (hereinafter Capacity Benefit Margin Methodology). On March 6, 2009, NERC submitted for Commission approval: MOD-030-2 – a revised Flowgate Methodology Reliability Standard and withdrew its request for approval of MOD-030-1.
NERC proposed that the Available Transmission System Capability Reliability Standard and the three methodology Reliability Standards become effective the first day of the first quarter no sooner than one calendar year after approval of all of these four Reliability Standards by all appropriate regulatory authorities where approval is required or is otherwise effective in those jurisdictions where approval is not explicitly required. According to NERC, since the three methodology Reliability Standards require information from neighboring reliability entities for use in the development of its available transfer capability and available flowgate capability values that is compulsory under Requirement R9 of the Available Transmission System Capability Reliability Standard (MOD-001-1), none of the methodology Reliability Standards can be effectively implemented unless and until that Reliability Standard has been implemented by all entities in all jurisdictions.
Several petitioners requested rehearing of the clarified implementation schedule. Bonneville Power Administration (Bonneville), the Large Public Power Council (LPPC), Southwest Area Transmission Subregional Planning Group (SWAT), and WestConnect requested a July 1, 2011, implementation date. Bonneville suggested that the Commission do this by clarifying that the effective date of the MOD Reliability Standards as the first day of the first quarter occurring 365 days after publication of Order No. 729-A in the Federal Register, i.e., July 1, 2011. By contrast, LPPC and WestConnect argued that their members reasonably presumed a July 1, 2011, implementation date when the Canadian authorities failed to approve the MOD Reliability Standards within three months of the Commission’s approval and have been acting in reliance of that date. SWAT simply stated that a July 1, 2011, effective date is consistent with the notice given to industry in Order No. 729 and that for the sake of the reliable operation of the Bulk-Power System and efficient and orderly implementation of the new MOD Reliability Standards, the effective date in the United States should be set as July 1, 2011. If the Commission rejects the proposed July 1, 2011, effective date, all of these petitioners request, in the alternative, that the Commission set the effective date no earlier than April 1, 2011, which is the first day of the first quarter occurring 365 days after Commission approval of the MOD Reliability Standards.
Other petitioners advocate for an April 1, 2011, effective date. Midwest Independent Transmission System Operation, Inc. (MISO), NorthWestern Corp. (NorthWestern), PJM Interconnection, L.L.C. (PJM) and Southwest Power Pool, Inc. (SPP) argue that they have relied upon April 1, 2011, as the earliest possible effective date of the MOD Reliability Standards. MISO argues that Order No. 729-A’s acceleration of the Order No. 729 compliance deadline is unexpected, unnecessary, and likely to impose unreasonable burdens on responsible entities who planned for compliance no earlier than April 1, 2011. PJM also contends that it has expended resources in reliance upon an April 1, 2011, effective date and that an accelerated effective date creates a substantial hardship for PJM. Accordingly, these petitioners urge the Commission to grant rehearing and set April 1, 2011, as the effective date for the MOD Reliability Standards.
Commission’s Response
Upon further consideration, the Commission has determined that the implementation schedule of the MOD Reliability Standards should be keyed to the date of approval of the Reliability Standards, as originally contemplated in Order No. 729, and not the date of publication of Order No. 729 in the Federal Register. Accordingly, the Commission grants rehearing of its determination in Order No. 729-A and directs that the MOD Reliability Standards shall become effective within the United States as of the first day of the first quarter occurring 365 days after their approval by the Commission, i.e., April 1, 2011.
The Commission is rejecting arguments raised by Bonneville, LPPC, SWAT and WestConnect that the implementation of the MOD Reliability Standards should be delayed because the original implementation plan contemplated approval of all applicable regulatory authorities, including certain Canadian provinces, and those entities did not act within the same quarter as the Commission. It is unclear whether and when the Canadian provinces will act on these MOD Reliability Standards. This uncertainty is the reason why the Commission granted clarification in Order No. 729-A. Although the Commission appreciates that industry acted in reliance of the original implementation plan, the Commission believes that the most reasonable clarification of the Commission’s directive in Order No. 729 is to make the MOD Reliability Standards effective within the United States on the first day of the first quarter occurring 365 days following approval by the Commission, i.e., April 1, 2011.
When the Commission issued Order No. 676-E, it purposely set an implementation timeline for compliance with the NAESB business practice standards that was identical to the one prescribed in Order No. 729 for the related NERC reliability standards.33 In this order and in Order No. 729-A, the Commission has modified the compliance schedule for the MOD Reliability Standards such that it no longer matches the compliance schedule for the WEQ Version 002.1 Business Practice Standards that the Commission incorporated by reference in Order No. 676-E. Thus, to maintain the consistency that the Commission determined was appropriate in Order Nos. 676-E and 729, we will modify the compliance deadline that we prescribed in Order No. 676-E to match the compliance deadline that we are prescribing for the MOD Reliability Standards within the continental United States.34 Thus, the NAESB business practice standards shall become effective on the same date as the MOD Reliability Standards.
Consistent with the Commission’s determination in Order No. 676-E, public utilities are to file any necessary tariff revisions, including any revisions to Attachment C of their OATT, at least ninety days before the prescribed date for compliance with the revised NAESB business practice standards.35 Consistent with the Commission’s prior practice, if a public utility fails to file the required tariff revisions prior to the compliance date, it nonetheless must abide by the NAESB Version 002.1 WEQ standards even before it has updated its tariff to incorporate these changes.
9. EXPLAIN ANY PAYMENT OR GIFTS TO RESPONDENTS
No payments or gifts have been made to respondents.
10. DESCRIBE ANY ASSURANCE OF CONFIDENTIALITY PROVIDED TO RESPONDENTS
The Commission generally does not consider the data filed to be confidential. However,
certain standards may have confidentiality provisions in the standard.
Section 215(e) of the FPA as well as section 39.7(d) of the Commission’s regulations regarding enforcement of Reliability Standards provides for public notice and opportunity for a hearing with respect to both the ERO (or Regional Entity) enforcement proceedings and proceedings before the Commission involving review of a proposed penalty for violation of a reliability standard. Section 39.7(b)(4) provides a limited exception to this notice requirement and allow non-public proceedings for enforcement actions that involve a Cybersecurity Incident,36 unless FERC determines on a case-by-case basis that such protection is not necessary. The Commission has in place procedures to prevent the disclosure of sensitive information, such as the use of protective orders and rules establishing critical energy infrastructure information (CEII). NERC’s Rules of Procedures, specifically section 1500 provides detailed rules for the protection of confidential information. In addition, additional information provided with a filing may be submitted with a specific request for confidential treatment to the extent permitted by law and considered pursuant to 18 C.F.R. 388.112 of FERC's regulations.
11. PROVIDE ADDITIONAL JUSTIFICATION FOR ANY QUESTIONS OF A SENSITIVE NATURE THAT ARE CONSIDERED PRIVATE.
There are no questions of a sensitive nature that are considered private.
12. ESTIMATED BURDEN OF COLLECTION OF INFORMATION
As stated above, the Commission previously approved, in Order No. 693, each of the Reliability Standards that are the subject of the current rulemaking. The MOD Reliability Standards apply to transmission service providers and transmission operators. Out of the total universe of entities subject to the Reliability Standards, approximately 137 entities will be responsible for compliance with the new Reliability Standards. This order on rehearing does not substantively change the requirements and the Commission will retain the estimates currently reported in OMB’s inventory.
Data Collection |
Number of Respondents |
Number of Responses |
Hours per Response |
Total Annual Hours |
Mandatory data exchanges |
137 |
1 |
80 |
10,960 |
Explanation of change of ATC values |
137 |
1 |
100 |
13,700 |
Recordkeeping |
137 |
1 |
30 |
3,480 |
Total Annual Hrs for Collection: Reporting + recordkeeping hrs = 3,480 + 24,660 = 28,140hrs. .
Current OMB Inventory
Data Collection |
Respondents |
Responses |
Hours Per Resp. |
Total Hours |
FERC-725A |
1,439 |
1,439 |
890.5142 |
1,281,450 |
13. ESTIMATE OF THE TOTAL ANNUAL COST BURDEN TO RESPONDENTS
As noted in item no. 12 above, this order on rehearing does not substantively alter the requirements and the Commission will retain the estimated costs previously reported for the Final Rule.
Information Collection Costs:
Cost to Comply:
Reporting = $129,823,200 + $2,811,240 = $132,634,440
Recordkeeping = $1,935,960 + $196,595 = $ 2,132,555
Total Costs: Reporting ($132,634,440) + Recordkeeping ($2,132,555 = $134,766,995.
(Labor rates: Reporting: $114 an hour (average cost of attorney ($200 per hour), consultant ($150), technical ($80), and administrative support ($25)); Recordkeeping: (file/record clerk @ $17 an hour), Storage 137 respondents @ 8,000 sq. ft. x $925 (off site storage))
14. ESTIMATED ANNUALIZED COST TO FEDERAL GOVERNMENT
The estimate of the cost to the Federal Government is based on salaries for professional
and clerical support, as well as direct and indirect overhead costs. Direct costs include all costs directly attributable to providing this information, such as administrative costs and the cost for information technology. Indirect or overhead costs are costs incurred by an organization in support of its mission. These costs apply to activities which benefit the whole organization rather than anyone particular function or activity. The Commission has gained some experience since the adoption of the Reliability Standards instituted in Order No. 693. However, when those Reliability Standards were adopted, the review process was only in the preliminary stages and so the Commission could only provide initial estimates for its review and analysis of the Reliability Standards. The Commission revised its initial estimates in the final rule submission to the following: 2.52 FTEs or a total cost of $323,308. (2.52 x $128,297). The Commission is now updating the FTE cost to reflect the average FTE cost as reflected in the Commission’s FY 2010 Budget submission.37
Data Collection |
Previous Federal |
Final Rule Cost |
Per Resp. |
Total/New Costs |
FERC-725A |
$1,055,889 |
$347,442 |
890.0764 |
$1,403,331 |
15. REASONS FOR CHANGES IN BURDEN INCLUDING THE NEED FOR ANY INCREASE
There are no changes to the reporting burden. The revisions to the information collection requirements for transmission service providers and transmission operators were adopted in Order No. 729 and approved by OMB. This order on rehearing clarifies these requirements in order to more clearly state the obligations imposed in Order No. 729, but does not substantively alter those requirements.
16. TIME SCHEDULE FOR THE PUBLICATION OF DATA
The filed Reliability Standards are available on the Commission’s eLibrary document retrieval system in Docket No. RM06-16-000 (Order No. 693) and the Commission required that all Commission-approved Reliability Standards be available on the ERO’s website, with an effective date (http://www.nerc.com/~filez/nerc_filings_ferc.html).
Copies of the filings are made available to the public within two days of submission to FERC via the Commission's web site. There are no other publications or tabulations of the information.
17. DISPLAY OF THE EXPIRATION DATE
It is not appropriate to display the expiration date for OMB approval of the information collected. The information will not be collected on a standard, preprinted form which would avail itself to that display. Rather the Electric Reliability Organization must prepare and submit filings that reflect unique or specific circumstances related to the Reliability Standard. In addition, the information contains a mixture of narrative descriptions and empirical support that varies depending on the nature of the transaction.
18. EXCEPTIONS TO THE CERTIFICATION STATEMENT
Item No. 19(g) (vi) see Instruction No. 17 above for further elaboration. In addition, the data collected for this reporting requirement is not used for statistical purposes. Therefore, the Commission does not use as stated in item no. 19(i) "effective and efficient statistical survey methodology." The information collected is case specific to each Reliability Standard.
B. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS.
This is not a collection of information employing statistical methods.
1 The Energy Policy Act of 2005, Pub. L. No 109-58, Title XII, Subtitle A, 119 Stat. 594, 941 (2005), codified at 16 U.S.C. 824o (2000).
2 NERC defines “Available Transfer Capability” as “a measure of the transfer capability (ability of interconnected electric systems to move or transfer power in a reliable manner from one area to another over all transmission lines between those areas under specified conditions) remaining in the physical transmission network for further commercial activity over and above already committed uses”.
3 FPA section 215(d)(5). 16 U.S.C. 824o(d)(5).
4 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 1029.
5 Id. P 1030.
6 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16416 (Apr. 4, 2007), FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).
7 Id. P 1010.
8 Id.
9 Id. P 1029-30; see also Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 207.
10 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 287-303. Some of these Reliability Standards required the regional reliability organizations to develop criteria for use by users, owners or operators within each region. The Commission set aside such Reliability Standards and directed NERC to provide additional details prior to considering them for approval. Id. P 287-303.
11 Standards for Business Practices and Communication Protocols for Public Utilities, Order No. 676-C, FERC Stats. & Regs., ¶ 31,274 (2008), order on clarification and reh’g, Order No. 676-D, 124 FERC ¶ 61,317 (2008).
12 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241 (2007); order on reh’g, Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007); order on reh’g and clarification, Order No. 890-B, 123 FERC ¶ 61,299 (2008).
13 The Version 002.1 Standards also revise the Manual Time Error Correction Standards (WEQ-006) to maintain consistency with revised NERC Standard BAL-004, but we are not incorporating this standard by reference because the Commission’s consideration of the revised BAL-004 is still pending. Thus, the earlier version of WEQ-006 will remain in force.
14 Order No. 729, 129 FERC ¶ 61,155 at P 95.
15 Id.
16 Id.
17 See 16 U.S.C. 824o(d)(5) (2006).
18 16 U.S.C. 824d, 824e.
19 Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996), order on reh’g, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ¶ 31,048 (1997), order on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002).
20 This is known as “functional unbundling” because the transmission element of a wholesale sale is separated or unbundled from the generation element of that sale, although the public utility may provide both functions.
21 See Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,769-70 (noting that the pro forma OATT expressly identified certain non-rate terms and conditions, such as the time deadlines for determining available transfer capability in section 18.4 or scheduling changes in sections 13.8 and 14.6, that may be modified to account for regional practices if such practices are reasonable, generally accepted in the region, and consistently adhered to by the transmission service provider).
22 Open Access Same-Time Information System (Formerly Real-Time Information Networks) and Standards of Conduct, Order No. 889, 61 FR 21737 (May 10, 1996), FERC Stats. & Regs. ¶ 31,035 (1996), order on reh’g, Order No. 889-A, FERC Stats. & Regs. ¶ 31,049 (1997), order on reh’g, Order No. 889-B, 81 FERC ¶ 61,253 (1997).
23 Order No. 889, FERC Stats. & Regs. ¶ 31,035 at 21749.
24 Id. at 21750.
25 Id.
26 Id.
27 Order No. 888, FERC Stats. & Regs. ¶ 31,036 n.610.
28 Reliability entities include: transmission service providers, planning coordinators, reliability coordinators, and transmission operators as those entities are defined in the NERC Glossary. Standards adopted by the North American Energy Standards Board (NAESB) govern disclosure of this information to other entities. The Commission addressed the NAESB business practices in a separate Final Rule (Docket No. RM05-5-013) issued concurrently. See Standards for Business Practices and Communication Protocols for Public Utilities, 74FR 63288 (2009).
29 These include: each planning coordinator, reliability coordinator, and transmission operator associated with the transmission service provider’s area; and each planning coordinator, reliability coordinator, and transmission service provider adjacent to the transmission service provider’s area.
30 Although the Reliability Standards only require the transmission service provider to make the available transfer capability implementation document available to certain reliability entities, the NAESB standard on OASIS posting requirements (Standard 001-13.1.5) requires transmission service providers to provide a link to the document on OASIS.
31 The definition of “small entity” under the Regulatory Flexibility Act refers to the definition provided in the Small Business Act, which defines a “small business concern” as a business that is independently owned and operated and that is not dominant in its field of operation. See 15 U.S.C. 632 (2000).
32 Id.
33 See Order No. 676-E, FERC Stats. & Regs. ¶ 31,299 at P 126; Order No. 729 at P 95.
34 In contrast to the compliance dates the Commission is establishing for the NERC MOD Reliability Standards, the compliance date for the WEQ Version 002.1 Business Practice Standards do not establish a separate compliance date for transactions outside of the continental United States.
35 Order No. 676-E, FERC Stats. & Regs. ¶ 31,299 at P 128.
36 The term “Cybersecurity Incident” is defined as a malicious act or suspicious event that disrupts, or was an attempt to disrupt, the operation of those programmable electronic devices and communications networks including hardware, software and data that are essential to the Reliable Operation of the Bulk-Power System.
37 An FTE = Full Time Employee. The $137,874 “cost” consists of approximately $110,299.64 in salaries and benefits and $27,574.61 in overhead. The Cost estimate is based on the actual annual allocated cost per Commission employee for Fiscal Year 2010.
| File Type | application/msword |
| Author | Michael Miller |
| Last Modified By | michael miller |
| File Modified | 2010-07-23 |
| File Created | 2010-07-19 |