RM08-19-000 Final Rule, FERC-725A Issued November 19, 2009
Supporting Statement for
FERC‑725A, Mandatory Reliability Standards for the Bulk-Power System
As Proposed in Docket No. RM08-19-000
(Final Rule Issued November 19, 2009)
The Federal Energy Regulatory Commission (Commission) (FERC) is submitting a Final Rule 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 10/31/2011.
In 2007 the Commission created a new information collection FERC-725A, implementing mandatory reliability standards that were previously part of a voluntary program. The Commission is informing OMB that there are changes to several of the Mandatory Reliability Standards, specifically the Modeling, Data and Analysis Standards (MOD) and the proposed changes in this Final Rule will result in revisions to the estimates currently reported on OMB’s inventory.
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. Below is a summary of the provisions of Subtitle A of the Electricity Modernization Act of 2005.
In the aftermath of the 1965 Blackout in the northeast United States, the electric industry established the North American Electric Reliability Council (NERC), a voluntary reliability organization. Since its inception, NERC has developed Operating Policies and Planning Standards that provided voluntary guidelines for operating and planning the North American bulk-power system. In April 2005, NERC adopted “Version O” reliability standards that translated the NERC Operating Policies, Planning Standards and compliance requirements into a comprehensible set of measurable standards. While NERC developed a compliance enforcement program to ensure compliance with the reliability standards it developed, industry compliance was voluntary and not subject to mandatory enforcement penalties. Although NERC’s efforts have been important in maintaining the reliability of the nation’s bulk-power system, NERC itself recognized the need for mandatory, enforceable reliability standards and was a proponent of legislation to establish a FERC-jurisdictional ERO that would propose and enforce mandatory reliability standards. (A reliability standard defines obligations or requirements of utilities and other entities that operate, plan and use the bulk power system in North America. Meeting these requirements helps ensure the reliable planning and operation of the bulk power system. Each NERC Reliability Standard details the purpose of the standard, the entities that must comply, the specific actions that constitute compliance and how the standard will be measured).
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.
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 NOPR
On March 19, 2009 the Commission issued a NOPR proposing to approve, and direct modification 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 flowgate11 capability. In addition, the Commission proposed to retire the existing MOD Reliability Standards and replace them with the version as proposed in the NOPR. The retirement of the existing MOD Reliability Standards will be effective upon the effective date of the proposed MOD Reliability Standards.
As noted above, in Order No. 890, the Commission found that the lack of a consistent and transparent methodology for calculating available transfer capability is a significant problem because the calculations of available transfer capability, which varies greatly depending on the criteria and assumptions used, may allow the transmission service provider to discriminate in subtle ways against its competitors.12 The calculation of available transfer capability is one of the most critical functions under the open access transmission tariff (OATT) because it determines whether transmission customers can access alternative power supplies. Improving transparency and consistency of available transfer capability calculation methodologies will eliminate transmission service providers’ wide discretion in calculating available transfer capability and ensure that customers are treated fairly in seeking alternative power supplies. The Commission believes that the Reliability Standards approved in the NOPR address the potential for undue discrimination by requiring industry-wide transparency and increased consistency regarding all components of the available transfer capability calculation methodology and certain definitions, data, and modeling assumptions.
RM08-19-000 Final Rule
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 will be effective upon the effective date of the revised MOD Reliability 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.13 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 FPA14 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.15 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.16 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).17 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. 889,18 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.”19 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.20 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.21 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.”22
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.23 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. If approved, NERC stated that its filing wholly addresses eight of the 24 Reliability Standards that the Commission did not approve in Order No. 693 because further information was needed.
NERC contends that these proposed 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 the proposed 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 current available transfer capability-related Reliability Standards. NERC contends 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.
The proposed Reliability Standards will enhance transparency in the calculation of available transfer capability, 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.24 The proposed 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 will 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 proposed the Available Transmission System Capability Reliability Standard (MOD-001-1) as part of a set of Reliability Standards which are 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 current 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.25 Requirement R5 requires the transmission service provider to make the available transfer capability implementation document available to those same reliability entities.26 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.27 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.28 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 an original and seven copies of the proposed Reliability Standard or for the modification to a proposed Reliability Standard to be filed. This exceeds the OMB guidelines in 5 CFR 1320.5(d) (2) (iii) because of the number of divisions within the Commission that must analyze the standard and corresponding reports in order to carry out the regulatory process. The original is docketed, imaged through e-Library and filed as a permanent record for the Commission. The remaining copies are distributed to the necessary offices of the Commission with one being placed immediately in the Commission’s Public Reference Room for public use. Since the time frame for responses to the request is very limited, the multiple hard copies are necessary for the various offices to review, analyze and prepare the final order at the same time. The electronic filing initiative at FERC, may in the near future, allow for relief of the number of copies, but at this time, the program turn around time for docketing, imaging and retrieval does not permit sufficient time to review the filings and to prepare the necessary documents for the processing of these filings.
In addition, 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.
As noted above, on March 19, 2009, the Commission issued its Notice of Proposed Rulemaking (NOPR) proposing to approve the six MOD Reliability Standards.29 The Commission also proposed to direct NERC to retire the currently effective MOD Reliability Standards along with one FAC Reliability Standard. In response to the NOPR, comments were filed by 37 interested parties. Appendix A of the Final Rule lists the entities that filed comments on the NOPR. Comments were due 60 days after publication of the NOPR in the Federal Register.
Many commenters support the Commission’s proposed approval of the proposed MOD Reliability Standards.30 For example, FirstEnergy contends that the MOD Reliability Standards, as proposed, completely address the calculation of ATC and its corresponding TTC values. Others agree that the Reliability Standards represent a step forward in eliminating the broad discretion previously afforded transmission service providers in the calculation of available transfer capability.31 In addition, several commenters stated that the proposed MOD Reliability Standards will provide greater transparency and consistency in the calculation of available transfer capability, available flowgate capability, capacity benefit margins and transmission reliability margins within the transmission service industry.32
NRU, Pacific Northwest, the Public Power Council and Snohomish agree with the Commission that the use of the proposed Reliability Standards, indeed the use of any one standard, may not produce identical results when applied to a different transmission system. They also agree that, even when the same methodology is used by transmission service providers on either side of an interface, unique system differences or differences in risk assumptions can lead to variations in available transmission capability values. They stated that they agree with the Commission that this will occur and is an acceptable result. They contend that each transmission provider must retain sufficient discretion to make assumptions and represent its system in the calculation such that its system reliability is assured.
To the extent that there are any outstanding issues not addressed in NERC’s filing, APPA, the Georgia Companies and the Joint Municipals contend that the Commission should allow industry to address such issues through the NERC Reliability Standards development process. The Joint Municipals state that, imperfect though it is the Reliability Standards development process is unequalled in its ability to secure industry input, cooperation and often consensus in the development of industry-wide protocols.
Midwest ISO concurs that multiple available transfer capability methodologies should be permitted but disagreed that a different Reliability Standard should be developed for each methodology. Midwest ISO contends that notwithstanding the use of an umbrella Reliability Standards, imposing a separate standard for each methodology, and corresponding risks of non-compliance therewith, could create a deterrent to using the methodology that provides the greatest benefits to reliability, where that methodology has higher compliance risks.
Commission’s Response
The Commission is adopting the NOPR proposal and approving the MOD Reliability Standards and related additions to the NERC Glossary, to be effective as proposed by NERC, as just, reasonable, not unduly discriminatory or preferential, and in the public interest. By promoting consistency, standardization and transparency, these Reliability Standards enhance the reliability of the Bulk-Power System.
The MOD Reliability Standards also represent a step forward in eliminating the broad discretion previously afforded transmission service providers in the calculation of available transfer capability. As the Commission explained in Order No. 890, excessive discretion in the calculation of available transfer capability gives transmission service providers the opportunity to discriminate in subtle ways in the provision of open access transmission service.33 On systems where transmission capacity is constrained, a lack of transparency and consistency in the calculation of available transfer capability has led to recurring disputes over whether transmission service providers have performed those calculations in a way that discriminates against competitors.
The Commission acted in Order No. 890 to limit this remaining opportunity for discrimination by directing public utilities, working through NERC, to develop Reliability Standards to govern the consistent and transparent calculation of available transfer capability by transmission service providers. In Order No. 693, the Commission implemented that directive by requiring NERC to prospectively modify the MOD Reliability Standards it filed in April 2006 to address the requirements of Order No. 890. The proposed Reliability Standards satisfy the Commission’s requirements by enhancing transparency and consistency in the calculation of available transfer capability, mandating that transmission service providers and transmission operators perform their calculations in accordance with methodologies that are both explicitly documented and available to reliability entities who request them. The proposed Reliability Standards also require documentation of the detailed representations of the various components that comprise the available transfer capability equation, and require transmission service providers and transmission operators to specify modeling and risk assumptions and disclosure of outage processing rules to other reliability entities. These actions will 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 that those calculations are performed consistently.
The Commission disagrees with Midwest ISO’s concerns that the structure of the Reliability Standards is misplaced. NERC, working through its Reliability Standards development process, developed the six Reliability Standards approved in the Final Rule. The Commission believes that each Reliability Standard adequately ensures the reliable operation of the Bulk-Power System and, thus, sees no basis for limiting which methodology is chosen to calculate available transfer or flowgate capability. The Commission believes that Midwest ISO’s remaining concerns, including variation in relative compliance burdens or risks among the three methodologies are best considered through NERC’s enforcement and compliance program.
The Commission has concerns regarding several of the substantive requirements of the proposed Reliability Standards. To address these concerns, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of its regulations, the Commission is directing the ERO to develop modifications to the Reliability Standards to address discrete issues involving: the availability of each transmission service provider’s implementation documents; the consistent treatment of assumptions in the calculation of available transfer capability; the calculation, allocation, and use of capacity benefit margin; the calculation of total transfer capability under the Rated System Path Methodology; and the treatment of network resource designations in the calculation of available transfer capability.
EEI contends that the implementation date is ambiguous. EEI stated that the implementation timeline could be understood to mean that the effective date of the Reliability Standards is either on the first day of the first quarter occurring 365 days after approval of the Reliability Standards or on January 1 of the year following a full calendar year after approval. Accordingly, EEI asked the Commission to clarify the intended implementation timeline.
Bonneville contends that a one-year implementation timeframe is unrealistic for certain portions of the proposed MOD Reliability Standards. Bonneville stated that it has been preparing to comply with the flowgate methodology approach set forth in MOD-030-2. Bonneville stated that, to date, it has identified twelve adjacent transmission service providers from which it will likely need to request data to determine the impacts on Bonneville’s network flow based system of the existing network integration transmission service, point-to-point transmission service, and grandfathered commitments reserved on those providers’ systems as required by Requirements R6 and R7 of MOD-030-2. Although Bonneville can request its adjacent transmission service providers to provide that data in aggregate form pursuant to Requirement R9 of MOD-001-1, Bonneville contends that, to obtain sufficiently detailed data, it will have to coordinate separate data exchange arrangements with each adjacent transmission service provider. Bonneville stated that it is unlikely that it will be able to accomplish this, along with the necessary software changes, associated testing, and possible tariff filings that would be required to comply with the proposed Reliability Standard, within one year. Accordingly, Bonneville asked that the Commission establish a two-year implementation compliance timeframe or, in the alternative, allow entities to request extensions on a case-by-case basis.
In contrast, EPSA contends that the Commission should advance the implementation schedule. EPSA stated that NERC provided no support for why it will take a full year from Commission approval to implement MOD-001-1. EPSA contends that transmission service providers have long known that Order No. 890’s available transfer capability reform was coming. EPSA further contends that much of what is proposed in the MOD NOPR could be accomplished during the MOD NOPR’s development, if not before. EPSA questioned whether the documentation process and accompanying software changes will require a full year. Absent compelling reasons, EPSA argued that the Commission should reject the proposed implementation timeline and set a new timeline that accommodates actual implementation issues so as not to defer any longer the benefits of Order No. 890.
Commission’s Response
As approved, the Reliability Standards are to become effective on the first day of the first calendar quarter that is twelve months beyond the date that the Reliability Standards are approved by all applicable regulatory authorities. The Commission finds that the approved implementation schedule strikes 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 reliability margin. To the extent necessary, the Commission clarifies in the Final Rule 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 will be effective 60 days after the date of publication of the Final Rule in the Federal Register. If a transmission service provider or transmission operator is unable to implement the Reliability Standards within the time allowed, requests for extension are to be considered through NERC’s enforcement and compliance program.
Many commenters expressed concern that the Commission’s proposal to direct NERC to conduct audits of the available transfer capability, capacity benefit margin and transfer reliability margin implementation documents would be an inappropriate use of the Commission’s authority under section 215 of the FPA.34 They contend that the proposed audits would engage NERC in the Commission’s market oversight functions, and expand the scope of the ERO’s delegated responsibilities beyond its statutory duty to develop and enforce Reliability Standards to ensure the reliability of the Bulk-Power System.
NERC stated that section 215 recognizes the distinction between reliability matters (where the Commission is to give “due weight to the technical expertise of the ERO”), and matters affecting competition (where the Commission is to give no such deference). NERC stated that, while it understands that consistent treatment of transmission customers in functions related to competitions and markets is an important part of the Commission’s open access policies, this is not within NERC’s mandate to address as the ERO. NERC contends that the Commission’s proposed directive blurs the line between commercial interests and reliability interests and is not based on an objective evaluation of the impact to the reliability of the Bulk-Power System.
NERC contends, and others agreed, that the Commission should address its goals through business practice standards developed by NAESB and through specific Commission rulemakings that direct entities to which the Commission’s market-based jurisdiction applies to take action consistent with the Commission’s open access goals. TANC stated that NERC’s filing letter was clear that NERC and NAESB have agreed that any item that is directly related to the Open Access Same Time Information System or other commercial interactions between customers and transmission providers are within the scope of NAESB activities. TANC pointed out that NERC’s filing letter states repeatedly that the focus of the proposed Reliability Standards is to address only the reliability, not commercial, aspects of available transmission.
Similarly, ISO/RTO Council agreed that the Commission should pursue such commercial concerns through another forum such as the NAESB standards. ISO/RTO Council expressed concern that the Commission’s proposed directive could undermine the coordination efforts between NERC and NAESB on these issues. In addition, ISO/RTO Council contends that the NOPR overstates reliability concerns associated with the standards and that the Commission lacks justification for additional directives. ISO/RTO Council stated that overestimation and hence overselling of ATC can result in potential or actual violations of system operating limits and interconnection reliability operating limits but claimed there has not been a single incident in which a system operating limit and interconnection reliability operating limit has been violated due to the overselling of available transfer capability.
ISO/RTO Council stated that the subject of the proposed audits is not related to compliance with NERC Reliability Standards or reliability in any way. ISO/RTO Council argued that such audits are not in themselves Reliability Standards compliance audits which are appropriately conducted by the ERO and its Reliability Entities through a set schedule. Rather, ISO/RTO Council argued, the proposed audits are designed to allow the Commission and others to replicate and verify calculations to satisfy a competition-related concern.
EEI contends that a Reliability Standard must address a reliability concern that falls within the statutory framework of section 215. EEI further contends that the purpose of a Reliability Standard may not extend beyond the reliable operation of the Bulk-Power System. EEI also stated that it is appropriate for the Commission to determine if a Reliability Standard is unduly discriminatory.35 But, EEI contends, there is a difference between a Reliability Standard that is not unduly discriminatory and a standard that furthers open access goals that are not a part of the reliable operation of the Bulk-Power System. EEI stated that the potential discrimination described in the NOPR is related to the provision of transmission service under an OATT and, to the extent the Commission or others believe such discrimination exists, the Commission has the authority and jurisdiction to address such discrimination under sections 205 and 206 of the FPA. According to EEI, it is imperative that the ERO maintain focus on its reliability duties rather than taking on additional duties to police implementation of tariffs and comparability issues.36
EEI and Entegra separately asked the Commission to clarify that, under Order No. 890, transmission service providers are required to adhere to the Commission’s policies regarding non-discriminatory open access transmission service in their exercise of discretion under the standards. They also asked the Commission to clarify that it will retain jurisdiction under Order No. 890 after approval of the MOD Reliability Standards to remedy any undue discrimination that may result from the implementation of these standards by individual transmission operators or transmission service providers. Entegra separately argued that while it may be necessary and appropriate for the Commission to rely on the NERC process to develop requirements that are solely related to reliability, the Commission cannot and should not abdicate its statutory authority to prevent undue discrimination by delegating to NERC its responsibility to enforce its open access requirements.
Although commenters such as NRU, Pacific Northwest, Public Power Council, Snohomish and SMUD agreed that undue discrimination in transmission service must be addressed, they also contend that such a goal is not a statutory purpose that Reliability Standards are intended to address. Puget Sound agreed, stating that available transfer capability calculations have little impact on reliability. SMUD stated that it is troubled by language in the NOPR that suggests that commercial concepts be addressed by the Reliability Standards, even where no clear nexus to reliability exists. NRU, Pacific Northwest, Public Power Council, and Snohomish stated that the Commission has provided no reliability-based justification for the proposed audit directive and that the proposal cannot be supported on the basis of reliability.
The Joint Municipals agreed that the Commission has not articulated a sufficient statutory basis for the proposed audits. The Joint Municipals stated that the courts have been clear that the Commission must be rigorous in identifying the statutory authority under which it proceeds. The Joint Municipals comment that the Commission is charged with the responsibility to ensure non-discrimination in the provision of transmission service under sections 205, 206 and 211A of the FPA; whereas section 215 clearly identifies reliability as the only purpose of the ERO regime. Accordingly, the Joint Municipals ask the Commission to make clear that in the exercise of its prosecutorial discretion, it will ensure that the Commission and NERC enforcement processes will be focused on violations of the proposed Reliability Standards that threaten system reliability. The Joint Municipals argued, however, that a review of Order Nos. 890, 693 and the NOPR make clear that the impetus for developing a consistent, transparent approach to available transfer capability lies in the Commission’s concern over discrimination in the provision of transmission service, rather than system reliability.37
By contrast, EPSA stated that it supports and applauds the Commission’s efforts to meld the reliability goals of Order No. 693 and the non-discriminatory goals of Order No. 890. EPSA contends that the contributions that market mechanisms make to system reliability, and the need to preserve the positive link between reliability and markets, is a significant dimension of the new Reliability Standards development process. EPSA commends the Commission for recognizing the connection between the MOD Reliability Standards and the initiative to reform Order No. 890 to address existing opportunities for to discriminate against competitive power suppliers. EPSA stated that Order Nos. 890 and 693 articulated serious concerns regarding the lack of clarity, transparency and uniformity in the critical calculations pertaining to one of the most fundamental aspects of the wholesale Bulk-Power System from both a reliability and commercial perspective.
Commission’s Response
The Commission is adopting the NOPR proposal to direct the ERO to conduct an audit of the various implementation documents developed by transmission service providers to confirm that the complete available transfer capability methodologies reflected in the documents are sufficiently transparent to allow the Commission and others to replicate and verify those calculations. The Commission clarifies that these audits are not intended to address the competitive effects of these MOD Reliability Standards. Instead, the audit should review each component of available transfer or flowgate capability, including the transmission service provider’s calculation of capacity benefit margin and transmission reliability margin, for transparency and verifiability to ensure compliance with the MOD Reliability Standards. In the course of its audit, NERC is directed to identify any parameters and assumptions that are not sufficiently specific or transparent to allow the Commission and others to replicate and verify the results.
The Commission disagrees with commenters asserting that the scope of this audit is irrelevant to the Reliability Standards or the reliability of the Bulk-Power System. Requirement R3.1 of MOD-001-1 requires transmission service providers to include in their available transfer capability implementation documents information describing how the selected methodology (or methodologies) has been implemented. Transmission service providers are to provide enough detail for the Commission and others to validate the results of the calculation given the same information used by the transmission service provider. Thus, Requirement R3.1 of MOD-001-1 requires transmission service providers to include enough information in their available transfer capability or available flowage capability implementation documents to confirm that the respective methodologies reflected in them are sufficiently transparent to allow the Commission and others to replicate and verify those calculations. Consequently, the audit is directly relevant to compliance with the Reliability Standards as proposed by the ERO and approved by the Commission in the Final Rule.
As described above, the Reliability Standards approved in the Final Rule are the result of a long process before the Commission. In Order No. 890, the Commission, among other things, expressed concern that a lack of consistent, industry-wide available transfer capability calculation standards poses a threat to the reliable operation of the Bulk-Power System.38 In light of these concerns, the Commission directed public utilities, working through the NERC Reliability Standards development process, to develop Reliability Standards for the consistent and transparent calculation of available transfer capability.39 One month later, the Commission issued Order No. 693, which directed the ERO to modify nine out of ten approved MOD Reliability Standards to be consistent with the requirements in Order No. 890. Thus, the MOD Reliability Standards approved here today are the result of efforts by the Commission, the ERO and industry to address concerns related to the reliable operation of the Bulk-Power System.
The Commission clarifies in the Final Rule that it is not directing the ERO to perform a market-based analysis of the competitive effects of the Reliability Standards approved in the Final Rule. Although the ERO should attempt to develop Reliability Standards that have no undue negative effects on competition,40 the ERO’s statutory functions are properly focused on the reliability of the Bulk-Power System and the Commission does not intend to broaden that focus here. The Commission reiterates in the Final Rule that a proposed Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power System beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an unduly preferential manner. The Reliability Standard should not create an undue advantage for one competitor over another. However, in accordance with sections 205 and 206 of the FPA, the Commission shall remain the final arbiter of undue discrimination. The MOD Reliability Standards approved in the Final Rule require transmission service providers to document their methodologies for calculating available transfer capability or available flowgate capability in a transparent and consistent manner. Compliance with these requirements is essential to reducing the threat posed to the reliable operation of the Bulk-Power System, particularly with respect to the inability of one transmission provider to know with certainty its neighbors’ system conditions affecting its own available transfer capability values.41
Specifically, each of the methodologies for calculating available transfer capability or available flowgate capability provides an algorithm for calculating the respective values. Each of these algorithms requires values for capacity benefit margin and transfer reliability margin. For example, Requirement R10 of MOD-028-1 states:
[available transfer capability] = [total transfer capability] – [existing transmission commitments] – [capacity benefit margin] – [transfer reliability margins] + postbacks + counterflows.
Thus, in order to validate the results of the available transfer capability or available flowgate capability calculations, the Commission and others must be able to validate the calculations for capacity benefit margin and transfer reliability margin. Accordingly, the Commission is directing the ERO to audit the capacity benefit margin and transfer reliability margin implementation documents, created pursuant to MOD-004-1 and MOD-008-1 respectively, to ensure that these documents include information, in such detail that, given the same information, the results of the capacity benefit margin or transfer reliability margin calculation can be validated.
Although the Commission is directing the ERO to conduct audits to ensure compliance with the requirements of the MOD Reliability Standards, the Commission will remain vigilant in its efforts to reduce the potential for undue discrimination in the provision of transmission service pursuant to its authority under sections 205 and 206 of the FPA. Accordingly, transmission customers and neighboring transmission providers will have the opportunity to submit complaints pursuant to section 206 of the FPA, if they believe that a transmission provider is using assumptions or parameters in available transfer capability calculations in an unduly discriminatory or preferential manner.42
Many commenters, including NERC, indicated that NERC lacks the expertise to conduct the proposed audits. These commenters suggested that Commission staff is more suited to perform the audits that pertain to market issues. Others, such as EPSA, support the proposed audits but recognized that NERC staff may not have sufficient knowledge and skill for the task. Other commenters asked for clarification regarding the scope and details of such audits. NERC and others contend that the proposed 180-day deadline for NERC to complete the audits is overly-burdensome and unrealistic, while Entegra supports the NOPR proposal to complete the audits within 180-days of the effective date of the Reliability Standards.
NERC indicated that obtaining personnel with the technical expertise needed to evaluate the implementation of these audits will result in staffing challenges that could be more complex than the Commission foresees. NERC expressed concern that, if the Commission expands the role of the ERO to begin enforcement of open access service, it would not be able to perform the audits with its current staff and would therefore need to hire new employees or consultants. Moreover, NERC contends that it may prove extremely difficult to locate and acquire new employees or consultants with the appropriate qualifications to not only review an implementation document for its engineering merits but also for its commercial implications.
Several commenters agreed that NERC and the Regional Entities lack the ability, experience, authority or staff determine whether the Commission or transmission customers have sufficient and accurate information for commercial and economic purposes or to ensure compliance with the competition goals of Order No. 890.43 The Georgia Companies pointed out that the Reliability Standards were developed by NERC using industry experts on reliability, not necessarily experts on the commercial or regulatory implications of undue discrimination in the provision of transmission service. Similarly, TAPS and TANC contend that the Commission should not require NERC to divert its limited resources to cover market oversight and competition issues. EPSA argued that if both the reliability goals of Order No. 693 and the non-discriminatory access goals of Order No. 890 become the responsibility of NERC and the regional reliability entities, the achievement of each will be diffused. EPSA further contends that a reliability audit cannot be a substitute for an audit of transmission access practices and measures.
Some commenters recommend that, if the Commission is interested in auditing the implementation documents to address commercial concerns, the Commission itself should perform the audits.44 For example, APPA stated that the role of detecting and remedying undue discrimination properly falls upon the Commission, acting in an audit and compliance role or acting upon customer complaints that transmission service providers or transmission operators have failed to fully comply with transparency obligations. Puget Sound stated that the Commission has an established method to conduct such audits – the OATT process. If the Commission chooses to direct NERC to conduct these audits, Entegra argued that NERC staff should be required to conduct the audit under the guidance of Commission staff.
Several parties also questionned the intended scope of the proposed audits.45 For example, Entegra contends that the Commission should specify in greater detail the contents of the audit with Commission staff acting as subject matter experts with respect to the Commission’s policies for non-discriminatory open access transmission service. To the extent an audit team identifies an item in an implementation document as unduly discriminatory or preferential, or otherwise does not comply with the requirements of Order Nos. 890 and 693, Entegra recommended that the Commission should require the transmission service provider to modify the item during the audit process as appropriate. Entegra stated that the audit report should identify and document all areas where the implementation document did not comply with Order Nos. 890 and 693 and explain how the non-compliance was corrected. Further, Entegra suggested that the Commission should specify that the audit findings are preliminary and that it will establish notice and comment procedures for the initial audit report. Finally, Entegra recommended that the Commission should commit to reopen the audit and/or direct any necessary modifications to the implementation documents if the comments of interested parties indicate that any items in the implementation documents are unduly discriminatory or preferential or otherwise do not comply with the Commission’s open access requirements in Order Nos. 890 and 693.
The Georgia Companies recommended that the Commission describe how it proposes that the Commission and others should be able to replicate and verify results and allow proper time for NERC and the industry to determine a plan that meets the Commission’s proposals as well as state and regional requirements. The Georgia Companies also asked that the Commission limit its review of capacity benefit margin and transmission reserve margin implementation documents to their effect on reliability, not undue discrimination.
EPSA recommended the Commission convene a technical conference to clarify the audit scope, responsibilities and jurisdictional questions. In addition, EPSA contends that the Commission needs to have a process to handle complaints as they arise.
Puget Sound stated that the Commission needs to rationalize the OATT enforcement regime, which its staff oversees, and the NERC reliability rule enforcement regime, as they will both apply to the same total transfer capability/available transfer capability concepts. Puget Sound stated that the Commission must be absolutely clear that the regimes, as they both address available transfer capability calculations, are completely consistent and that there is no interpretation gap between enforcement personnel and auditors from the two separate entities. Puget Sound contends that this is necessary because there is a significant risk of conflicting or at least inconsistent interpretations and questions the appropriateness of having two enforcement regimes cover the same issue.
NYISO expressed concern that the proposed audits might be interpreted to require NYISO to publicly disclose confidential market and transmission information in its implementation document. NYISO argued that requiring independent system operators (ISOs) and regional transmission organizations (RTOs) to reveal information, such as transmission flow utilization variables, would place them in a position of choosing to comply with NERC’s available transfer capability replication requirement or internal codes of conduct that forbid ISOs and RTOs from revealing such information. NYISO contends that it is not necessary for confidential information to be revealed in order to allow market participants to replicate available transfer capability calculations. Accordingly, NYISO asked the Commission to clarify that its audit requirement is not meant to require ISOs and RTOs to make confidential information publicly available, and that other methods can be used to allow market participants to replicate available transfer capability calculations without such disclosure.
The ITC Companies contend that the audit process should be strengthened to effectively detect evidence of oversubscription or underutilization of the transmission system and ensure that the commercial aspect of the available transfer capability closely matches the system available transfer capability calculations. The ITC Companies suggested, as an example, an audit of adjacent transmission service providers where they both calculate the available transfer capability or available flowgate capability for the same flowgates or paths. The ITC Companies stated that, usually, the two calculations should have similar results and that any major difference would be the result of differences in assumptions or study parameters. In addition, the ITC Companies commented that the Commission should open up the results of the NERC audit for further comments prior to directing NERC to modify the Reliability Standards to address any lack of transparency in the calculation of ATC and each of its components.
NERC, and other commenters, oppose the 180-day deadline for NERC to complete the audits.46 NERC contends that the imposition of a 180-day deadline to complete these audits places a higher priority on these issues than is warranted. NERC stated that consistency in available transfer capability practices (or the lack thereof) in the treatment of transmission has a relatively low reliability impact on the Bulk-Power System compared to numerous other core areas under which NERC has responsibilities. NERC stated that under its Commission-approved rules, NERC must conduct an audit of users, owners and operators of the Bulk-Power System every three years. NERC contends that the NOPR provides no explanation of the reliability benefits that would necessitate an audit cycle accelerated beyond this three year schedule. In addition, NERC contends that if the Commission insists on broadening NERC’s responsibilities, NERC will need more than 30 days to develop and submit a timeline for the completion of these audits. NERC asked that the Commission allow the ERO sufficient time to appropriate consider the best ways to restructure its resources in light of its new responsibilities.
APPA agreed with NERC stating that the Commission’s proposed timeline is potentially very burdensome. APPA, TANC and TAPS stated that the proposed timeline will likely divert scarce NERC and registered entity staff resources from other tasks that are more central to NERC’s responsibilities as the ERO. They recommend that such audits take place on the normal three-year or five-year audit cycles applicable to these reliability functions. The Georgia Companies stated that full audits with on-site visits of each transmission owner and transmission service provider likely cannot be completed within 180 days. ColumbiaGrid suggested that NERC should be permitted to audit a representative sample of entities rather than every single one and then assess whether a broader audit is necessary.
By contrast, Entegra suggested that the Commission should require NERC to complete the proposed audit within 180 days of the publication of the Final Rule. Entegra pointed out that, as proposed, the proposed audit will not be due until 18 to 21 months from the approval date. Entegra contends that NERC has not explained why drafting the implementation documents and making the corresponding changes to software and operating procedures will require 12 to 15 months after approval. Accordingly, Entegra suggested that the Commission should require all transmission service providers to finalize their implementation documents and submit them to NERC within 90 days of the approval date and require NERC to complete the audit within 90 days after receipt of these implementation documents. Entegra stated that transmission providers will have to complete their implementation documents well in advance of the actual implementation. Entegra argued that requiring the audit before the effective date would allow NERC and the Commission opportunity to identify and remedy – at the front end – any individual or systematic problems that NERC of the Commission find in the transmission service provider implementation documents.
Commission’s Response
While the Commission is adopting the NOPR proposal to direct NERC to conduct an audit, it is persuaded by the comments of the ERO and others to modify the NOPR proposal regarding certain details on implementation of the required audits. First, as already discussed above, the Commission will not require the ERO to perform an audit that requires the ERO to assess whether a transmission operators’ or transmission service providers’ available transfer capability methodology provides opportunities for undue discrimination or preference. Rather, the ERO audits must focus on compliance with the provisions of the MOD Reliability Standards. In accord with the position of numerous commenters, Commission staff is in a more appropriate position to analyze market-related issues. Therefore, the ERO must retain information and materials gathered during the course of its audit and make it available to Commission staff upon request, so as to allow Commission staff to inquire into possible anti-competition concerns.
Moreover, the Commission is persuaded that the ERO should conduct the audits in the due course of its periodic, three-year audit cycle, i.e., these Reliability Standards should be added to the ERO’s list of actively monitored Reliability Standards. The Commission believes that these modifications to the NOPR proposal address the concerns of the ERO and others regarding the expertise of the ERO to conduct the audits and the availability of ERO resources to conduct the audits in a more limited period of time.
The audits directed in the Final Rule should not displace any of NERC’s existing scheduled audits or priorities. If NERC is unable to perform the audits with current staff without sacrificing other audit priorities, it can seek additional resources to perform the audits. Since the MOD Reliability Standards will not become effective until more than one year from Commission approval, NERC can request any additional funding necessary to undertake the audits in its 2011 business plan and budget proposal. Thus, NERC will have sufficient opportunity to perform the audits without any undue burden.
The Commission is declining to direct how the ERO should conduct the MOD Reliability Standards audit, as requested by some commenters. The Commission believes that its action to focus the ERO audit on compliance with the requirements of the Reliability Standards, matches the scope of the audits to the ERO’s expertise. The ERO should be fully capable of developing an audit to measure compliance with the requirements of its Reliability Standards. In directing this audit, the Commission does not expect NERC’s staff to have expert knowledge of the competition requirements of Order No. 890.
If the Commission determines upon its own review of the data, or upon review of a complaint, that it should investigate the implementation of the available transfer capability methodologies, the Commission will need access to historical data. Accordingly, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of its regulations, the Commission is directing the ERO to modify the Reliability Standards so as to increase the document retention requirements to a term of five years, in order to be consistent with the enforcement provisions established in Order No. 670.47
With regard to concerns raised by commenters regarding the non-disclosure of confidential information, the Commission expects the ERO to conduct the MOD Reliability Standards audits consistent with section 1500 of NERC’s Rules of Procedure, which provides detailed rules for the protection of confidential information. Section 1505 of NERC’s Rules specifically addresses the ERO’s provision of confidential information to the Commission or another governmental agency in response to a request for information by that agency. Likewise, the implementation documents will be made publicly available through the corresponding NAESB business standards, approved concurrently with the Final Rule, which incorporate appropriate confidentiality protections.48
The Commission is persuaded by the commenters that the proposed 180-day time frame for conducting the MOD Reliability Standards audits is not practical, and likely not feasible. Upon further consideration, the Commission is directing the ERO to conduct these audits in the course of its periodic, three-year audits of users, owners and operators of the Bulk-Power System. The ERO is to begin this audit process 60 days after the implementation of these Reliability Standards. On an annual basis, the ERO is to commence 180 days after the implementation of the Reliability Standards approved in the Final Rule, and file the audit reports (or the results of its audit in any other format) with the Commission.49
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,50 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). As noted above 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 three new Reliability Standards.
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. .
The Commission did not receive any comments concerning its estimates of the burden hours or costs that proposed in the NOPR. The Commission will use the same estimates in the final rule.
Current OMB Inventory
Data Collection |
Respondents |
Responses |
Hours Per Resp. |
Total Hours |
FERC-725A |
1,439 |
1,439 |
870.5212 |
1,252,680 |
Proposed in NOPR
Data Collection |
Number of Respondents |
Number of Responses |
Hours per Response |
Total Annual Hours |
Reporting |
137 |
1 |
180 |
24,660 |
Recordkeeping |
137 |
1 |
30 |
3,480* |
Total Annual Hrs for Collection: Reporting + recordkeeping hrs = 3,480* + 24,660 = 28,140hrs.
(*mathematical error, should be 4,110 hrs)
Proposed in Final Rule
Data Collection |
Number of Respondents |
Number of Responses |
Hours per Response |
Total Annual Hours |
Reporting |
137 |
1 |
180 |
24,660 |
Recordkeeping |
137 |
1 |
30 |
4,110 |
Total Annual Hrs for Collection: Reporting + recordkeeping hrs = 24,660+4,110 = 28,770hrs.
Proposed 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
Information Collection Costs: As relates to the requirements in the Final Rule:
Cost to Comply:
Reporting = $2,811,240
24,660 hours @ $114 an hour (average cost of attorney ($200 per hour),
consultant ($150), technical ($80), and administrative support ($25))
Recordkeeping = $185,875 (same as below)
Labor (file/record clerk @ $17 an hour) 4,110 hours @ $17/hour = $69,870
Storage 137 respondents @ 8,000 sq. ft. x $925 (off site storage) = $126,725
Total costs = $3,007,835
Labor $ ($2,811,240+ $69,870) + Recordkeeping Storage Costs ($126,725)
As applied to the requirements in Order No. 693
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.
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 is now revising its initial estimates to the following: 2.52 FTEs or a total cost of $323,308. (2.52 x $128,297).51
Data Collection |
Previous Federal |
Final Rule Cost |
Per Resp. |
Total/New Costs |
FERC-725A |
$1,055,889 |
$323,308 |
890.0764 |
$1,379,197 |
15. REASONS FOR CHANGES IN BURDEN INCLUDING THE NEED FOR ANY INCREASE
The changes to the reporting burden are due to revisions to the MOD Reliability Standards. The Commission believes that the Reliability Standards proposed here address the potential for undue discrimination by requiring industry-wide transparency and increased consistency regarding all components of the available transfer capability calculation methodology and certain definitions, data, and modeling assumptions. Specifically, the proposed Reliability Standards contain methodologies for the consistent and transparent calculation of available transfer capability or available flowgate capability.
As noted above, the Commission found in Order No. 890, that the lack of a consistent and transparent methodology for calculating available transfer capability is a significant problem because the calculation of available transfer capability, which varies greatly depending on the criteria and assumptions used, may allow the transmission service provider to discriminate in subtle ways against its competitors. The calculation of available transfer capability is one of the most critical functions under the open access transmission tariff (OATT) because it determines whether transmission customers can access alternative power supplies. Improving transparency and consistency of available transfer capability calculation methodologies will eliminate transmission service providers’ wide discretion in calculating available transfer capability and ensure that customers are treated fairly in seeking alternative power supplies.
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 A designated point on the transmission system through which the Interchange Distribution Calculator calculates the power flow.
12 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007), order on reh'g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-B, 73 FR 39092 (July 8, 2008), 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 74 FR 12540 (March 25, 2009), 126 FERC ¶ 61,228 (2009).
13 See 16 U.S.C. 824o(d)(5) (2006).
14 16 U.S.C. 824d, 824e.
15 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).
16 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.
17 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).
18 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).
19 Order No. 889, FERC Stats. & Regs. ¶ 31,035 at 21749.
20 Id. at 21750.
21 Id.
22 Id.
23 Order No. 888, FERC Stats. & Regs. ¶ 31,036 n.610.
24 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 proposed 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).
25 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.
26 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.
27 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).
28 Id.
29 Mandatory Reliability Standards for the Calculation of Available Transfer Capability, Capacity Benefit Margins, Transmission Reliability Margins, Total Transfer Capability, and Existing Transmission Commitments and Mandatory Reliability Standards for the Bulk-Power System, 74 FR 12747 (March 25, 2009), FERC Stats. & Regs. ¶ 32,641 (2009) (“NOPR”).
30 APPA, Bonneville, Duke, EEI, EPSA, Entegra, FirstEnergy, Georgia, ISO/RTO Council, SMUD and NERC.
31 APPA, Bonneville, and ISO/RTO Council.
32 Bonneville, ISO/RTO Council, Joint Municipals, and SMUD.
33 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 68.
34 E.g., NERC, Duke, EEI, EPSA, EEI, Entegra, the Georgia Companies, ISO/RTO Council, NRU, NYISO, Pacific Northwest, Public Power Council, Snohomish, Puget Sound, SMUD, Joint Municipals, and TANC.
35 Citing Rules Concerning Certification of the Electric Reliability Organization; Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, 71 FR 8662 (Feb. 17, 2006), FERC Stats. & Regs. ¶ 31,204, at P 332 (2006); order on reh’g, Order No. 672-A, 71 FR 19814 (Apr. 18, 2006), FERC Stats. & Regs. ¶ 31,212 (2006).
36 See also Duke, NYISO and TANC comments.
37 Citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 83 (stating that the “purpose of increasing consistency and transparency of [available transfer capability] calculations is to reduce the potential for undue discrimination in the provision of transmission service.”) See also NOPR, FERC Stats. & Regs. ¶ 32,641 at P 2 (stating that the proposed Reliability Standards “address the potential for undue discrimination by requiring industry-wide transparency and increased consistency regarding all components of the [available transfer capability] methodology and certain definitions, data, and modeling.”
38 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 195.
39 Id. P 196.
40 Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 332.
41 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 195.
42 The ERO is to conduct audits to ensure compliance with the MOD standards to assure the reliable operation of the grid. Further, the Commission is not directing that the scope of the audit include an active search or review of anomalous events or unduly discriminatory behavior. If, however, in the course of an audit the ERO happens to identify any assumptions or parameters that appear anomalous, that may appear to cause available transfer capability calculation results to be skewed toward a particular result even if the implementation documents can be validated according to Requirement R3 of MOD-001-1, or that appear to violate NERC’s market-reliability interface principles that the Commission acknowledged in Order No. 672, the ERO is free to notify the Commission’s Office of Enforcement of such anomalies.
43 E.g., APPA, Cottonwood, EEI, EPSA, NRU, Pacific Northwest, Public Power Council, Puget Sound, Joint Municipals and Snohomish.
44 E.g., Cottonwood, EEI, EPSA, Puget Sound, TAPS and TANC.
45 E.g., Entegra, EPSA, the Georgia Companies, ITC Companies, NYISO, and Puget Sound.
46 E.g., APPA, Bonneville, ColumbiaGrid, Georgia Companies, TANC and TAPS.
47 Prohibition of Energy Market Manipulation, Order No. 670, 71 FR 4244 (Jan. 26, 2006), FERC Stats. & Regs. ¶ 31,202, at P 63 (2006) (citing 28 U.S.C. § 2462 (2000)).
48 See Standards for Business Practices and Communication Protocols for Public Utilities, Order No. 676-E, 129 FERC ¶ 61,162 (2009).
49 The Commission does not anticipate allowing an opportunity for public comment on the filed audit reports.
50 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.
51 An FTE = Full Time Employee. The $128,297 “cost” consists of approximately $102,491.59 in salaries and benefits and $25,805.74 in overhead. The Cost estimate is based on the actual annual allocated cost per Commission employee for Fiscal Year 2009.
| File Type | application/msword |
| Author | Michael Miller |
| Last Modified By | michael miller |
| File Modified | 2010-03-10 |
| File Created | 2010-03-10 |