Forest Service
Engineers Corps
Economic Development Administration
Industry and Security Bureau
International Trade Administration
Engineers Corps
Federal Energy Regulatory Commission
Centers for Medicare & Medicaid Services
Health Resources and Services Administration
National Institutes of Health
Fish and Wildlife Service
National Park Service
Drug Enforcement Administration
Immigration and Naturalization Service
Employment Standards Administration
Mine Safety and Health Administration
Health Resources and Services Administration
National Institutes of Health
Committee for the Implementation of Textile Agreements
Federal Aviation Administration
Federal Highway Administration
National Highway Traffic Safety Administration
Surface Transportation Board
Consult the Reader Aids section at the end of this issue for phone numbers, online resources, finding aids, reminders, and notice of recently enacted public laws.
To subscribe to the Federal Register Table of Contents LISTSERV electronic mailing list, go to http://listserv.access.gpo.gov and select Online mailing list archives, FEDREGTOC-L, Join or leave the list (or change settings); then follow the instructions.
Bureau of Consular Affairs, Department of State.
Final rule.
This rule amends the Department's regulations to add and delete immigrant visa symbols on the immigrant visa classification table. The Department is amending the table to add a new class of special immigrants for certain aliens who had petitions or labor certification applications revoked, terminated or rendered null due to the terrorist activities of September 11, 2001, and for the guardian grandparents of certain children rendered orphans by the attacks. The Department is also taking this opportunity to remove the HK immigrant classification symbols used for transition employees of certain U.S. businesses in Hong Kong and their dependents whose visa validity was extended under section 124 of Public Law 101-649. This immigrant status was valid only through January 1, of 2002. The Department is also changing “orphan” to “child” under the classification definition IR3 and correcting the section of law citation under the entry AM3 to read “Public Law 100-102” instead of “P.L. 100-202”.
This rule takes effect on August 29, 2002.
For information regarding this regulation please contact Pam Chavez, Legislation and Regulations Division, Visa Services, Department of State, Washington, DC 20520-0106, phone (202) 663-1206 or e-mail
Public Law 107-56 (the USA Patriot Act) provided special immigration benefits for certain victims of the terrorist acts of September 11, 2001. Section 421 of this Act created a new special immigrant category (SP) for certain aliens who were beneficiaries of petitions or labor certification applications which were revoked, terminated or otherwise rendered null due to the terrorist attacks of September 11, 2001. The USA Patriot Act also provides special immigrant status for the spouse and children of these aliens and for certain grandparents of children who were orphaned as a result of these attacks.
Section 124 of Public Law 101-649 (IMMACT 90) extended the visa validity for employees of certain U.S. businesses located in Hong Kong to January 1, 2002. Aliens issued visas under section 124 of IMMACT 90 were given the classification symbol HK. Since visas are no longer being issued for this visa classification, the Department is removing the code from the classification table.
The rule amends the immigrant visa classification table at 22 CFR 42.11 by adding a new classification symbol SP. The rule also removes the classification symbols HK1, HK2 and HK3. In the classification symbol IR4, the word “orphan” is replaced by the word “child”. In the classification symbol AM3, the public law citation should read “Public Law 100-102.”
The Department's implementation of this regulation as a final rule is based upon the “good cause” exceptions found at 5 U.S.C. 553(b)(B) and (d)(3). Since the new special immigrant category became effective upon enactment of the law and since there is a substantial immediate benefit to aliens, citizens and lawful permanent residents, there is not enough time nor sufficient reason to delay its implementation by issuing a proposed rule with request for comments.
The Department of State, in accordance with the Regulatory Flexibility Act (5 U.S.C. 605(b)), has reviewed this regulation and, by approving it, certifies that this rule will not have a significant economic impact on a substantial number of small entities.
This rule will not result in the expenditure by state, local and tribal governments, in the aggregate, or by the private sector, of $100 million or more in any year and it will not significantly or uniquely affect small governments. Therefore, no actions were deemed necessary under the provisions of the Unfunded Mandates Reform Act of 1995.
This rule is not a major rule as defined by section 804 of the Small Business Regulatory Enforcement Act of 1996. This rule will not result in an annual effect on the economy of $100 million or more; a major increase in costs or prices; or significant adverse effects on competition, employment, investment, productivity, innovation, or on the ability of United States-based companies to compete with foreign-based companies in domestic and export markets.
Although it is being promulgated in conjunction with the Immigration and Naturalization Service, a domestic agency, the Department of State does not consider this rule, to be a “significant regulatory action” under Executive Order 12866, section 3(f), Regulatory Planning and Review. Therefore, in accordance with the letter to the Department of State of February 4, 1994 from the Director of the Office of Management and Budget, it does not require review by the Office of Management and Budget.
This regulation will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. Therefore, in
This rule does not impose any new reporting or record-keeping requirements under the Paperwork Reduction Act.
Aliens, Immigrants, Passports and visas.
8 U.S.C. 1104.
The revisions and additions read as follows:
Environmental Protection Agency (EPA).
Direct final rule.
EPA is approving revisions to the Tennessee State Implementation Plan (SIP) submitted by the State of Tennessee through the Tennessee Department of Environment and Conservation (TDEC) on July 10, 1996, February 14, 1997, and February 21, 1997. These submittals revise the regulations for Exemptions in the Construction and Operating Permits chapter, General Provisions and Applicability in the Nitrogen Oxides chapter, and add a chapter on Conflict of Interest.
This direct final rule is effective October 28, 2002, without further
All comments should be addressed to Steven M. Scofield at the EPA, Region 4 Air Planning Branch, 61 Forsyth Street, SW., Atlanta, Georgia 30303-8960.
Copies of the State submittals are available at the following addresses for inspection during normal business hours:
Steven M. Scofield; Regulatory Development Section; Air Planning Branch; Air, Pesticides and Toxics Management Division; U.S. Environmental Protection Agency Region 4; 61 Forsyth Street, SW; Atlanta, Georgia 30303-8960. Mr. Scofield can also be reached by phone at (404) 562-9034 or by electronic mail at
On July 10, 1996, the State of Tennessee, through the TDEC, submitted revisions to rule 1200-3-9-.04 Exemptions, in the Construction and Operating Permits chapter of the Tennessee SIP. The revisions are summarized as follows:
1. Automobile body shops (except sources in ozone nonattainment areas which emit more than 15 pounds per day of volatile organic compounds);
2. Any process emission source emitting less than 0.1 pounds per hour of a pollutant excluding hazardous air contaminants or pollutants;
3. Any air contaminant source with the potential to emit radionuclides which will result in a dose to the most exposed member of the public of less than 0.1 millirem per year;
4. Any modification (as defined in Rule 1200-3-2-.01) to an existing process emission source, incinerator, or fuel-burning installation to add sources of equipment leaks as long as the estimated increase in annual emissions attributable to the modification does not exceed 5 tons per year.
On February 14, 1997, the State of Tennessee, through the TDEC, submitted a revision to rule 1200-3-27.02 General Provisions and Applicability, revising paragraph (6) by deleting Shelby County from the list of counties in which the owner or operator of any facility which has actual emissions from stationary sources of 25 tons or more nitrogen oxides (NO
On February 21, 1997, the State of Tennessee, through the TDEC, submitted the addition of Chapter 1200-3-17 Conflict of Interest. The chapter was developed as a result of the Attorney General Opinion required as a part of Tennessee's title V submittal. In that opinion, the Attorney General found that the laws and regulations of the State did not fully address conflict of interest as required under sections 7428 and 7429(e) of the CAA. Rule 1200-3-17-.02 defines a “conflict of interest” occurring when a Board member or the Technical Secretary takes an action in the performance of their duties that singularly benefits a source when the Board member or the Technical Secretary has a significant portion of their personal income derived from the operations of said source. The rule requires that prior to the issuance of a permit, variance or an enforcement order that requires an action on their part, the Technical Secretary or a Board member shall issue a statement that declares any conflict of interest that they may have in the matter.
EPA is approving the aforementioned revisions to the Tennessee SIP because they are consistent with the CAA and EPA policy. The EPA is publishing this rule without prior proposal because the Agency views this as a noncontroversial submittal and anticipates no adverse comments. However, in the proposed rules section of this
If the EPA receives such comments, then EPA will publish a document withdrawing the final rule and informing the public that the rule will not take effect. All public comments received will then be addressed in a subsequent final rule based on the proposed rule. The EPA will not institute a second comment period. Parties interested in commenting should do so at this time. If no such comments are received, the public is advised that this rule will be effective on October 28, 2002, and no further action will be taken on the proposed rule. Please note that if we receive adverse comment on an amendment, paragraph, or section of this rule and if that provision may be severed from the remainder of the rule, we may adopt as final those provisions of the rule that are not the subject of an adverse comment.
Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is not a “significant regulatory action” and therefore is not subject to review by the Office of Management and Budget. For this reason, this action is also not subject to Executive Order 13211, “Actions Concerning Regulations That
This rule also does not have tribal implications because it will not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes, as specified by Executive Order 13175 (65 FR 67249, November 9, 2000). This action also does not have Federalism implications because it does not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132 (64 FR 43255, August 10, 1999). This action merely approves a state rule implementing a Federal standard, and does not alter the relationship or the distribution of power and responsibilities established in the Clean Air Act. This rule also is not subject to Executive Order 13045 “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997), because it is not economically significant.
In reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. In this context, in the absence of a prior existing requirement for the State to use voluntary consensus standards (VCS), EPA has no authority to disapprove a SIP submission for failure to use VCS. It would thus be inconsistent with applicable law for EPA, when it reviews a SIP submission, to use VCS in place of a SIP submission that otherwise satisfies the provisions of the Clean Air Act. Thus, the requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) do not apply. This rule does not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
The Congressional Review Act, 5 U.S.C. 801
Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by October 28, 2002. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this rule for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. (
Environmental Protection, Air pollution control, Carbon monoxide, Intergovernmental relations, Lead, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Sulfur oxides, Volatile organic compounds.
42.U.S.C. 7401
(c) * * *
Environmental Protection Agency (EPA).
Final rule.
This regulation establishes a tolerance for combined residues of imazethapyr, its metabolite CL 288511 and its metabolite CL 182704 in or on rice bran, rice grain, and rice straw. This regulation also establishes a tolerance for combined residues of imazethapyr and its metabolite CL 288511 in or on crayfish and meat byproducts of cattle, goat, hog, horse, and sheep. BASF requested these tolerances under the Federal Food, Drug, and Cosmetic Act, as amended by the Food Quality Protection Act of 1996.
This regulation is effective August 29, 2002. Objections and requests for hearings, identified by docket ID number OPP-2002-0189, must be received on or before October 28, 2002.
Written objections and hearing requests may be submitted by mail, in person, or by courier. Please follow the detailed instructions for each method as provided in Unit VI. of the
By mail: Jim Tompkins, Registration Division (7505C), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave., NW.,Washington, DC 20460; telephone number: 703-305-5697; e-mail address: Tompkins.Jim@epa.gov.
You may be affected by this action if you are an agricultural producer, food manufacturer, or pesticide manufacturer. Potentially affected categories and entities may include, but are not limited to:
This listing is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. Other types of entities not listed in the table could also be affected. The North American Industrial Classification System (NAICS) codes have been provided to assist you and others in determining whether or not this action might apply to certain entities. If you have questions regarding the applicability of this action to a particular entity, consult the person listed under
1.
2.
In the
The petition requested that 40 CFR 180.447 be amended by establishing a tolerance for combined residues of the herbicide imazethapyr, 2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5-oxo-1H-imidazol-2-yl]-5-ethyl-3-pyridine carboxylic acid as it free acid or ammonium salt and its metabolite CL 288511, 2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5-oxo-1H-imidazol-2-yl]-5-(1-hydroxyethyl)-3-pyridine carboxylic acid both free and conjugated, in or on rice grain at 0.5 parts per million (ppm), rice straw at 0.3 ppm, and crayfish at 0.1 ppm.
Section 408(b)(2)(A)(i) of the FFDCA allows EPA to establish a tolerance (the legal limit for a pesticide chemical residue in or on a food) only if EPA determines that the tolerance is “safe.” Section 408(b)(2)(A)(ii) defines “safe” to mean that“ there is a reasonable certainty that no harm will result from aggregate exposure to the pesticide chemical residue, including all anticipated dietary exposures and all other exposures for which there is reliable information.” This includes exposure through drinking water and in residential settings, but does not include occupational exposure. Section 408(b)(2)(C) requires EPA to give special consideration to exposure of infants and children to the pesticide chemical residue in establishing a tolerance and to “ensure that there is a reasonable certainty that no harm will result to infants and children from aggregate exposure to the pesticide chemical residue....”
EPA performs a number of analyses to determine the risks from aggregate exposure to pesticide residues. For further discussion of the regulatory requirements of section 408 and a complete description of the risk assessment process, see the final rule on Bifenthrin Pesticide Tolerances (62 FR 62961, November 26, 1997) (FRL-5754-7).
After analysis of submitted residue chemistry data, EPA determined that appropriate tolerances for rice and crayfish differ from those proposed by the registrant. EPA determined that a tolerance of 1.2 ppm is needed for rice bran; no tolerance for rice bran was proposed by the registrant. EPA also determined that tolerances should be 0.20 ppm instead of 0.5 ppm for rice grain, and 0.15 ppm instead of 0.3 ppm for rice straw. Further, EPA determined that the tolerance expression for rice commodities should be for imazethapyr and the metabolites CL 288511 and CL 182704 (5-[1-(beta-D-glucopyranosyloxy)ethyl]-2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5-oxo-1H-imidazol-2-yl]-3-pyridinecarboxylic acid); the registrant's proposed tolerance expression for rice commodities was for imazethapyr as the free acid and ammonium salt and CL 288511 both free and conjugated. For crayfish, EPA determined that the tolerance expression should be for imazethapyr and CL 288511; the registrant's proposed tolerance expression for crayfish was for imazethapyr as the free acid and ammonium salt and CL 288511 both free and conjugated. Finally, EPA determined that tolerances of 0.10 ppm for imazethapyr and CL 288511 need to be established for meat byproducts of cattle, goat, hog, horse, and sheep; the registrant did not propose tolerances for these commodities. EPA determined that tolerances are not needed for eggs; milk; meat and fat of cattle, goat, hog, horse, and sheep; and poultry commodities because there is no reasonable expectation of finite residues based on the calculated maximum total dietary burdens and the results of the poultry metabolism study.
Consistent with section 408(b)(2)(D), EPA has reviewed the available scientific data and other relevant information in support of this action. EPA has sufficient data to assess the hazards of and to make a determination on aggregate exposure, consistent with section 408(b)(2), for a tolerance for combined residues of imazethapyr and its metabolite CL 288511 on crayfish and meat byproducts of cattle, goat, hog, horse, and sheep at 0.10 ppm, and for tolerances for combined residues of imazethapyr, its metabolite CL 288511, and its metabolite CL 182704 on rice bran at 1.2 ppm, rice grain at 0.20 ppm, and rice straw at 0.15 ppm. EPA's assessment of exposures and risks associated with establishing the tolerance follows.
EPA has evaluated the available toxicity data and considered its validity, completeness, and reliability as well as the relationship of the results of the studies to human risk. EPA has also considered available information concerning the variability of the sensitivities of major identifiable subgroups of consumers, including infants and children. The nature of the toxic effects caused by imazethapyr are discussed in the following Table 1 as well as the no observed adverse effect level (NOAEL) and the lowest observed adverse effect level (LOAEL) from the toxicity studies reviewed.
The dose at which no adverse effects are observed (the NOAEL) from the toxicology study identified as appropriate for use in risk assessment is used to estimate the toxicological level of concern (LOC). However, the lowest dose at which adverse effects of concern are identified (the LOAEL) is sometimes used for risk assessment if no NOAEL was achieved in the toxicology study selected. An uncertainty factor (UF) is applied to reflect uncertainties inherent in the extrapolation from laboratory animal data to humans and in the variations in sensitivity among members of the human population as well as other unknowns. An UF of 100 is routinely used, 10X to account for interspecies differences and 10X for intra species differences.
For dietary risk assessment (other than cancer) the Agency uses the UF to calculate an acute or chronic reference dose (acute RfD or chronic RfD) where the RfD is equal to the NOAEL divided by the appropriate UF (RfD = NOAEL/UF). Where an additional safety factor is retained due to concerns unique to the FQPA, this additional factor is applied to the RfD by dividing the RfD by such additional factor. The acute or chronic Population Adjusted Dose (aPAD or cPAD) is a modification of the RfD to accommodate this type of FQPA Safety Factor.
For non-dietary risk assessments (other than cancer) the UF is used to determine the LOC. For example, when 100 is the appropriate UF (10X to account for interspecies differences and 10X for intraspecies differences) the LOC is 100. To estimate risk, a ratio of the NOAEL to exposures (margin of exposure (MOE) = NOAEL/exposure) is calculated and compared to the LOC.
The linear default risk methodology (Q*) is the primary method currently used by the Agency to quantify carcinogenic risk. The Q* approach assumes that any amount of exposure will lead to some degree of cancer risk. A Q* is calculated and used to estimate risk which represents a probability of occurrence of additional cancer cases (e.g., risk is expressed as 1 x 10
1.
i.
ii.
iii.
2.
EPA determined that the residue of concern in drinking water is only imazethapyr. EPA provided ground (SCI-GROW; 8.97 μg/l) and surface water (rice paddy model; peak and average - 93.18 μg/l) estimated environmental concentrations (EECs) for imazethapyr. The ground and surface water EECs were generated assuming a single application of imazethapyr at 0.094 lbs ae/acre (highest registered/proposed single application rate).
Since the models used are considered to be screening tools in the risk assessment process, the Agency does not use EECs from these models to quantify drinking water exposure and risk as a %RfD or %PAD. Instead, drinking water levels of comparison (DWLOCs) are calculated and used as a point of comparison against the model estimates of a pesticide's concentration in water. DWLOCs are theoretical upper limits on a pesticide's concentration in drinking water in light of total aggregate exposure to a pesticide in food, and from residential uses. Since DWLOCs address total aggregate exposure to imazethapyr they are further discussed in the aggregate risk sections in Unit IV.E. of this preamble.
Based on the rice paddy and SCI-GROW models the EECs of imazethapyr for chronic exposures are estimated to be 93.18 μg/L (parts per billion (ppb)) for surface water and 8.97 μg/L (ppb) for ground water. Because the Agency determined that an acute (single dose) risk assessment for both the general
3.
Imazethapyr is not registered for use on any sites that would result in residential exposure.
4.
EPA does not have, at this time, available data to determine whether imazethapyr has a common mechanism of toxicity with other substances or how to include this pesticide in a cumulative risk assessment. Unlike other pesticides for which EPA has followed a cumulative risk approach based on a common mechanism of toxicity, imazethapyr does not appear to produce a toxic metabolite produced by other substances. For the purposes of this tolerance action, therefore, EPA has not assumed that imazethapyr has a common mechanism of toxicity with other substances.
EPA has recently developed a framework that it proposes to use for conducting cumulative risk assessments on substances that have a common mechanism of toxicity. This guidance was issued for public comment on January 16, 2002 (67 FR 2210-2214) and is available from the OPP Website at: http://www.epa.gov/pesticides/trac/science/cumulative_guidance.pdf. Before undertaking a cumulative risk assessment, the Agencv will follow procedures for identifying chemicals that have a common mechanism of toxicity as set forth in the “Guidance for Identifying Pesticide Chemicals and Other Substances that Have a Common Mechanism of Toxicity” (64 FR 5795-5796, February 5, 1999).
1.
2.
3.
To estimate total aggregate exposure to a pesticide from food, drinking water, and residential uses, the Agency calculates DWLOCs which are used as a point of comparison against the model estimates of a pesticide's concentration in water (EECs). DWLOC values are not regulatory standards for drinking water. DWLOCs are theoretical upper limits on a pesticide's concentration in drinking water in light of total aggregate exposure to a pesticide in food and residential uses. In calculating a DWLOC, the Agency determines how much of the acceptable exposure (i.e., the PAD) is available for exposure through drinking water [e.g., allowable chronic water exposure (mg/kg/day) = cPAD - (average food + residential exposure)]. This allowable exposure through drinking water is used to calculate a DWLOC.
A DWLOC will vary depending on the toxic endpoint, drinking water consumption, and body weights. Default body weights and consumption values as used by the USEPA are used to calculate DWLOCs: 2L/70 kg (adult male), 2L/60 kg (adult female), and 1L/10 kg (child). Default body weights and drinking water consumption values vary on an individual basis. This variation will be taken into account in more refined screening-level and quantitative drinking water exposure assessments. Different populations will have different DWLOCs. Generally, a DWLOC is calculated for each type of risk assessment used: acute, short-term, intermediate-term, chronic, and cancer.
When EECs for surface water and groundwater are less than the calculated DWLOCs, EPA concludes with reasonable certainty that exposures to the pesticide in drinking water (when considered along with other sources of exposure for which EPA has reliable data) would not result in unacceptable levels of aggregate human health risk at this time. Because EPA considers the aggregate risk resulting from multiple exposure pathways associated with a pesticide's uses, levels of comparison in drinking water may vary as those uses change. If new uses are added in the future, EPA will reassess the potential impacts of residues of the pesticide in drinking water as a part of the aggregate risk assessment process.
1.
2.
3.
Adequate enforcement methodology (example—gas chromotography) is available to enforce the tolerance expression. The method may be requested from: Paul Golden, USEPA/OPP/BEAD/ACB, Environmental Science Center, 701 Mapes Road, Fort Meade, MD 20755-5350; telephone number: (410) 305-2960; e-mail address: golden.paul@epa.gov
Codex, Canada, and Mexico do not have maximum residue limits (MRLs) for residues of imazethapyr and CL 288511 in/on rice.
The following will be imposed as conditions of registration of imazethapyr on rice: successful pesticide method validation (PMV) and radiovalidation of the rice, crayfish, and livestock enforcement methods, and submission of an acceptable crayfish residue and ruminant feeding studies.
Therefore, the tolerances are established for combined residues of imazethapyr, 2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5-oxo-1H-imidazol-2-yl]-5-ethyl-3-pyridine carboxylic acid, its metabolite CL 288511, 2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5-oxo-1H-imidazol-2-yl]-5-(1-hydroxyethyl)-3-pyridine carboxylic acid, and its metabolite CL 182704, 5-[1-(beta-D-glucopyranosyloxy)ethyl]-2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5-oxo-1H-imidazol-2-yl]-3-pyridinecarboxylic acid, in or on rice grain at 0.5 parts per million (ppm), rice straw at 0.3 ppm. In addition, a tolerance is established for combined residues of imazethapyr and its metabolite CL 288511 in or on crayfish and meat byproducts of cattle, goat, hog, horse, and sheep at 0.10 ppm.
Under section 408(g) of the FFDCA, as amended by the FQPA, any person may file an objection to any aspect of this regulation and may also request a hearing on those objections. The EPA procedural regulations which govern the submission of objections and requests for hearings appear in 40 CFR part 178. Although the procedures in those regulations require some modification to reflect the amendments made to the FFDCA by the FQPA of 1996, EPA will continue to use those procedures, with appropriate adjustments, until the necessary modifications can be made. The new section 408(g) provides essentially the same process for persons to “object” to a regulation for an exemption from the requirement of a tolerance issued by EPA under new section 408(d), as was provided in the old FFDCA sections 408 and 409. However, the period for filing objections is now 60 days, rather than 30 days.
You must file your objection or request a hearing on this regulation in accordance with the instructions provided in this unit and in 40 CFR part 178. To ensure proper receipt by EPA, you must identify docket ID number OPP-2002-0189 in the subject line on the first page of your submission. All requests must be in writing, and must be mailed or delivered to the Hearing Clerk on or before October 28, 2002.
1.
Mail your written request to: Office of the Hearing Clerk (1900C), Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460. You may also deliver your written request to the Office of the Hearing Clerk in Rm. 104, Crystal Mall #2, 1921 Jefferson Davis Hwy., Arlington, VA. The Office of the Hearing Clerk is open from 8 a.m. to 4 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Office of the Hearing Clerk is (703) 603-0061.
2.
EPA is authorized to waive any fee requirement “when in the judgement of the Administrator such a waiver or refund is equitable and not contrary to the purpose of this subsection.” For additional information regarding the waiver of these fees, you may contact James Tompkins by phone at (703) 305-5697, by e-mail at tompkins.jim@epa.gov, or by mailing a request for information to Mr. Tompkins at Registration Division (7505C), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
If you would like to request a waiver of the tolerance objection fees, you must mail your request for such a waiver to: James Hollins, Information Resources and Services Division (7502C), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
3.
A request for a hearing will be granted if the Administrator determines that the material submitted shows the following: There is a genuine and substantial issue of fact; there is a reasonable possibility that available evidence identified by the requestor would, if established resolve one or more of such issues in favor of the requestor, taking into account uncontested claims or facts to the contrary; and resolution of the factual issues(s) in the manner sought by the requestor would be adequate to justify the action requested (40 CFR 178.32).
This final rule establishes a tolerance under FFDCA section 408(d) in response to a petition submitted to the Agency. The Office of Management and Budget (OMB) has exempted these types of actions from review under Executive Order 12866, entitled
The Congressional Review Act, 5 U.S.C. 801
Environmental protection, Administrative practice and procedure, Agricultural commodities, Pesticides and pests, Reporting and recordkeeping requirements.
21 U.S.C. 321(q), 346(a) and 371.
(a)
(2)Tolerances are established for the sum of the residues of the herbicide imazethapyr, 2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5-oxo- 1H-imidazol-2-yl]-5-ethyl-3-pyridine carboxylic acid; its metabolite CL 288511, 2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5-oxo-1H-imidazol-2-yl]-5-(1-hydroxyethyl)-3-pyridine carboxylic acid; and its metabolite CL 182704, 5-[1-(beta-D-glucopyranosyloxy)ethyl]-2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5-oxo-1H-imidazol-2-yl]-3-pyridinecarboxylic acid, applied as its acid or ammonium salt, in or on the following commodities:
(3) A tolerance is established for the sum of residues of the herbicide imazethapyr, 2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5-oxo- 1H-imidazol-2-yl]-5-ethyl-3-pyridine carboxylic acid, and its metabolite CL 288511, 2-[4,5-dihydro-4-methyl-4-(1-methylethyl)-5- oxo-1H-imidazol-2-yl]-5-(1-hydroxyethyl)-3-pyridine carboxylic acid, applied as its acid or ammonium salt, in or on the following commodities:
(b)
(c)
(d)
Environmental Protection Agency (EPA).
Final rule.
This regulation establishes tolerances for combined residues of diflufenzopyr in or on corn, sweet, forage; corn, sweet, kernel plus cob with husks removed; and corn, sweet, stover at 0.05 part per million (ppm); corn, pop, grain and corn, pop, stover at 0.05 ppm; grass, forage at 22 ppm; and grass, hay at 7.0 ppm. This regulation also establishes time-limited tolerances for combined residues of diflufenzopyr in or on cattle, goat, hog, horse, and sheep meat at 0.60 ppm; cattle, goat, hog, horse, and sheep kidney at 4.0 ppm; cattle, goat, hog, horse, and sheep meat byproducts, except kidney at 0.50 ppm; cattle, goat, hog, horse, and sheep fat at 0.30 ppm; and milk at 3.0 ppm. The Interregional Research Project Number 4 (IR-4) requested these tolerances under the Federal Food, Drug, and Cosmetic Act (FFDCA), as amended by the Food Quality Protection Act (FQPA) of 1996.
This regulation is effective August 29, 2002. Objections and requests for hearings, identified by docket ID number OPP-2002-0220, must be received on or before October 28, 2002.
Written objections and hearing requests may be submitted by mail, in person, or by courier. Please follow the detailed instructions for each method as provided in Unit VI. of the
By mail: Shaja R. Brothers, Registration Division (7505C), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone number: (703) 308-3194; e-mail address: brothers.shaja@epa.gov.
You may be affected by this action if you are an agricultural producer, food manufacturer, or pesticide manufacturer. Potentially affected categories and entities may include, but are not limited to:
This listing is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. Other types of entities not listed in the table could also be affected. The North American Industrial Classification System (NAICS) codes have been provided to assist you and others in determining whether or not this action might apply to certain entities. If you have questions regarding the applicability of this action to a particular entity, consult the person listed under
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In the
The petition requested that 40 CFR 180.549 be amended by establishing tolerances for the combined residues of the herbicide diflufenzopyr in or on corn, sweet, forage; corn, sweet, kernel plus cob with husks removed; and corn, sweet, stover at 0.05 ppm; corn, pop, grain, and corn, pop, stover at 0.05 ppm; grass, forage at 22 ppm; and grass, hay at 7.0 ppm. The petition was subsequently revised to request that 40 CFR 180.549 be amended by establishing time-limited tolerances for residues of the herbicide diflufenzopyr, 2-(1-(3,5- difluorophenylamino) carbonyl)hydrazono)ethyl)(-3-pyridinecarboxylic acid, its metabolites convertible to 8-methylpyrido[2,3-d]pyridazin-5(6H)-one, and free and acid-released 8-hydroxymethylpyrido[2,3-d] pyridazine-2,5(1H,6H)-dione, expressed as diflufenzopyr, in or on cattle, goat, hog, horse, and sheep meat at 0.60 ppm; cattle, goat, hog, horse, and sheep kidney at 4.0 ppm; cattle, goat, hog, horse, and sheep meat byproducts, except kidney at 0.50 ppm; cattle, goat, hog, horse, and sheep fat at 0.30 ppm; and milk at 3.0 ppm.
Section 408(b)(2)(A)(i) of the FFDCA allows EPA to establish a tolerance (the legal limit for a pesticide chemical residue in or on a food) only if EPA determines that the tolerance is “safe.” Section 408(b)(2)(A)(ii) defines “safe” to mean that “there is a reasonable certainty that no harm will result from aggregate exposure to the pesticide chemical residue, including all anticipated dietary exposures and all other exposures for which there is reliable information.” This includes exposure through drinking water and in residential settings, but does not include occupational exposure. Section 408(b)(2)(C) requires EPA to give special consideration to exposure of infants and children to the pesticide chemical residue in establishing a tolerance and to “ensure that there is a reasonable certainty that no harm will result to infants and children from aggregate exposure to the pesticide chemical residue. . . .”
EPA performs a number of analyses to determine the risks from aggregate exposure to pesticide residues. For further discussion of the regulatory requirements of section 408 and a complete description of the risk assessment process, see the final rule on Bifenthrin Pesticide Tolerances November 26, 1997 (62 FR 62961) (FRL-5754-7).
Consistent with section 408(b)(2)(D), EPA has reviewed the available scientific data and other relevant information in support of these actions. EPA has sufficient data to assess the hazards of and to make a determination on aggregate exposure, consistent with section 408(b)(2), for tolerances for the combined residues of diflufenzopyr on corn, sweet, forage; corn, sweet, kernel plus cob with husks removed; corn, sweet, stover at 0.05 ppm; corn, pop, grain; and corn, pop, stover at 0.05 ppm; grass, forage at 22 ppm; grass, hay at 7.0 ppm; cattle, goat, hog, horse, and sheep fat at 0.30 ppm; cattle, goat, hog, horse, and sheep kidney at 4.0 ppm; cattle, goat, hog, horse, and sheep meat byproducts, except kidney at 0.50 ppm; cattle, goat, hog, horse, and sheep meat at 0.60 ppm;, and milk at 3.0 ppm. EPA's assessment of exposures and risks associated with establishing tolerances follow.
EPA has evaluated the available toxicity data and considered its validity, completeness, and reliability as well as the relationship of the results of the studies to human risk. EPA has also considered available information concerning the variability of the sensitivities of major identifiable subgroups of consumers, including infants and children. The nature of the toxic effects caused by diflufenzopyr is discussed in Unit III.A. of the Final Rule on Diflufenzopyr Pesticide Tolerance published in the
The dose at which no adverse effects are observed (the NOAEL) from the toxicology study identified as appropriate for use in risk assessment is used to estimate the toxicological level of concern (LOC). However, the lowest dose at which adverse effects of concern
For dietary risk assessment (other than cancer) the Agency uses the UF to calculate an acute or chronic reference dose (acute RfD or chronic RfD) where the RfD is equal to the NOAEL divided by the appropriate UF (RfD = NOAEL/UF). Where an additional safety factor is retained due to concerns unique to the FQPA, this additional factor is applied to the RfD by dividing the RfD by such additional factor. The acute or chronic Population Adjusted Dose (aPAD or cPAD) is a modification of the RfD to accommodate this type of FQPA Safety Factor.
For non-dietary risk assessments (other than cancer) the UF is used to determine the LOC. For example, when 100 is the appropriate UF (10X to account for interspecies differences and 10X for intraspecies differences) the LOC is 100. To estimate risk, a ratio of the NOAEL to exposures (margin of exposure (MOE) = NOAEL/exposure) is calculated and compared to the LOC.
The linear default risk methodology (Q*) is the primary method currently used by the Agency to quantify carcinogenic risk. The Q* approach assumes that any amount of exposure will lead to some degree of cancer risk. A Q* is calculated and used to estimate risk which represents a probability of occurrence of additional cancer cases (e.g., risk is expressed as 1 x 10
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The Agency uses the Generic Estimated Environmental Concentration (GENEEC) or the Pesticide Root Zone Model/Exposure Analysis Modeling System (PRZM/EXAMS) to estimate pesticide concentrations in surface water and SCI-GROW, which predicts pesticide concentrations in ground water. In general, EPA will use GENEEC (a tier 1 model) before using PRZM/EXAMS (a tier 2 model) for a screening-level assessment for surface water. The GENEEC model is a subset of the PRZM/EXAMS model that uses a specific high-end runoff scenario for pesticides. GENEEC incorporates a farm pond scenario, while PRZM/EXAMS incorporate an index reservoir environment in place of the previous pond scenario. The PRZM/EXAMS model includes a percent crop area factor as an adjustment to account for the maximum percent crop coverage within a watershed or drainage basin.
None of these models include consideration of the impact processing (mixing, dilution, or treatment) of raw water for distribution as drinking water would likely have on the removal of pesticides from the source water. The primary use of these models by the Agency at this stage is to provide a screen for sorting out pesticides for which it is highly unlikely that drinking water concentrations would exceed human health levels of concern.
Since the models used are considered to be screening tools in the risk assessment process, the Agency does not use estimated environmental concentrations (EECs) from these models to quantify drinking water exposure and risk as a %RfD or %PAD. Instead drinking water levels of comparison (DWLOCs) are calculated and used as a point of comparison against the model estimates of a pesticide's concentration in water. DWLOCs are theoretical upper limits on a pesticide's concentration in drinking water in light of total aggregate exposure to a pesticide in food and from residential uses. Since DWLOCs address total aggregate exposure to diflufenzopyr, they are further discussed in the aggregate risk sections in Unit III.E. Diflufenzopyr is not very stable and mobile. Based upon proposed uses, fate characteristics, and model predictions, the Agency does not expect diflufenzopyr to reach drinking water resources in significant quantities.
Based on the GENEEC and SCI-GROW models, the EECs of diflufenzopyr for
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EPA does not have, at this time, available data to determine whether diflufenzopyr has a common mechanism of toxicity with other substances or how to include this pesticide in a cumulative risk assessment. Unlike other pesticides for which EPA has followed a cumulative risk approach based on a common mechanism of toxicity, diflufenzopyr does not appear to produce a toxic metabolite produced by other substances. For the purposes of this tolerance action, therefore, EPA has not assumed that diflufenzopyr has a common mechanism of toxicity with other substances. For information regarding EPA's efforts to determine which chemicals have a common mechanism of toxicity and to evaluate the cumulative effects of such chemicals, see the final rule for Bifenthrin Pesticide Tolerances (62 FR 62961, November 26, 1997).
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To estimate total aggregate exposure to a pesticide from food, drinking water, and residential uses, the Agency calculates DWLOCs which are used as a point of comparison against the model estimates of a pesticide's concentration in water (EECs). DWLOC values are not regulatory standards for drinking water. DWLOCs are theoretical upper limits on a pesticide's concentration in drinking water in light of total aggregate exposure to a pesticide in food and residential uses. In calculating a DWLOC, the Agency determines how much of the acceptable exposure (i.e., the PAD) is available for exposure through drinking water (e.g., allowable chronic water exposure (mg/kg/day) = cPAD - (average food + residential exposure)). This allowable exposure through drinking water is used to calculate a DWLOC.
A DWLOC will vary depending on the toxic endpoint, drinking water consumption, and body weights. Default body weights and consumption values as used by the EPA Office of Water are used to calculate DWLOCs: 2L/70 kg (adult male), 2L/60 kg (adult female), and 1L/10 kg (child). Default body weights and drinking water consumption values vary on an individual basis. This variation will be taken into account in more refined screening-level and quantitative drinking water exposure assessments. Different populations will have different DWLOCs. Generally, a DWLOC is calculated for each type of risk assessment used: Acute, short-term, intermediate-term, chronic, and cancer.
When EECs for surface water and ground water are less than the calculated DWLOCs, EPA concludes with reasonable certainty that exposures to the pesticide in drinking water (when considered along with other sources of exposure for which EPA has reliable data) would not result in unacceptable levels of aggregate human health risk at this time. Because EPA considers the aggregate risk resulting from multiple exposure pathways associated with a pesticide's uses, levels of comparison in drinking water may vary as those uses change. If new uses are added in the future, EPA will reassess the potential impacts of residues of the pesticide in drinking water as a part of the aggregate risk assessment process.
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There are currently no established Codex, Mexican maximum residue limits (MRLs) for residues of diflufenzopyr in/on plant or livestock commodities. A Canadian MRL of 0.05 ppm for residues of diflufenzopyr, expressed as the parent and metabolites convertible to M1, has been established for corn. No compatibility issues exist with regard to the existing and proposed U.S. tolerances.
The registrant submitted a meat and milk magnitude of residue study in lactating dairy cows. Registration for use of diflufenzopyr on sweet corn, pop corn, forage, and hay grasses will be conditional pending the outcome of the Agency's review of the submitted study.
Therefore, the tolerances are established for combined residues of diflufenzopyr, 2-(1-[([3,5-difluorophenylamino] carbonyl)hydrazono]ethyl)-3-pyridinecarboxylic acid, and its metabolites convertible to 8-methylpyrido[2,3-d]pyridazin-5(6H)-one, expressed as diflufenzopyr, in or on corn, sweet, forage; corn, sweet, kernel plus cob with husks removed; and corn, sweet, stover at 0.05 ppm; corn, pop, grain, and corn, pop, stover at 0.05 ppm; forage, grass at 22 ppm; and forage, hay at 7.0 ppm.
Time-limited tolerances are also established for combined residues of diflufenzopyr, 2-(1-[([3,5-difluorophenylamino] carbonyl)hydrazono]ethyl)-3-pyridinecarboxylic acid, its metabolites convertible to 8-methylpyrido[2,3-d]pyridazin-5(6H)-one, and free and acid-released 8-hydroxymethylpyrido[2,3-d]pyridazine-
Under section 408(g) of the FFDCA, as amended by the FQPA, any person may file an objection to any aspect of this regulation and may also request a hearing on those objections. The EPA procedural regulations which govern the submission of objections and requests for hearings appear in 40 CFR part 178. Although the procedures in those regulations require some modification to reflect the amendments made to the FFDCA by the FQPA of 1996, EPA will continue to use those procedures, with appropriate adjustments, until the necessary modifications can be made. The new section 408(g) provides essentially the same process for persons to “object” to a regulation for an exemption from the requirement of a tolerance issued by EPA under new section 408(d), as was provided in the old FFDCA sections 408 and 409. However, the period for filing objections is now 60 days, rather than 30 days.
You must file your objection or request a hearing on this regulation in accordance with the instructions provided in this unit and in 40 CFR part 178. To ensure proper receipt by EPA, you must identify docket ID number OPP-2002-0220 in the subject line on the first page of your submission. All requests must be in writing, and must be mailed or delivered to the Hearing Clerk on or before October 28, 2002.
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Mail your written request to: Office of the Hearing Clerk (1900C), Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460. You may also deliver your written request to the Office of the Hearing Clerk in Rm. 104, Crystal Mall # 2, 1921 Jefferson Davis Hwy., Arlington, VA. The Office of the Hearing Clerk is open from 8 a.m. to 4 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Office of the Hearing Clerk is (703) 603-0061.
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EPA is authorized to waive any fee requirement “when in the judgement of the Administrator such a waiver or refund is equitable and not contrary to the purpose of this subsection.” For additional information regarding the waiver of these fees, you may contact James Tompkins by phone at (703) 305-5697, by e-mail at tompkins.jim@epa.gov, or by mailing a request for information to Mr. Tompkins at Registration Division (7505C), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
If you would like to request a waiver of the tolerance objection fees, you must mail your request for such a waiver to: James Hollins, Information Resources and Services Division (7502C), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
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A request for a hearing will be granted if the Administrator determines that the material submitted shows the following: There is a genuine and substantial issue of fact; there is a reasonable possibility that available evidence identified by the requestor would, if established resolve one or more of such issues in favor of the requestor, taking into account uncontested claims or facts to the contrary; and resolution of the factual issues(s) in the manner sought by the requestor would be adequate to justify the action requested (40 CFR 178.32).
This final rule establishes a tolerance under FFDCA section 408(d) in response to a petition submitted to the Agency. The Office of Management and Budget (OMB) has exempted these types of actions from review under Executive Order 12866, entitled
The Congressional Review Act, 5 U.S.C. 801
Environmental protection, Administrative practice and procedure, Agricultural commodities, Pesticides and pests, Reporting and recordkeeping requirements.
21 U.S.C. 321(q), 346(a) and 374.
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(2) Time-limited tolerances are established for combined residues of diflufenzopyr, 2-(1-[([3,5-difluorophenylamino]carbonyl)hydrazono]ethyl)-3- pyridinecarboxylic acid, its metabolites convertible to 8-methylpyrido[2,3-d]pyridazin- 5(6H)-one, and free and acid-released 8-hydroxymethylpyrido[2,3-d]pyridazine-2,5(1H,6H)-dione, expressed as diflufenzopyr, in or on the following raw agricultural commodities:
Environmental Protection Agency (EPA).
Final rule.
This regulation establishes tolerances for residues of the fungicide, fosetyl-Al aluminum tris (
This regulation is effective August 29, 2002. Objections and requests for hearings, identified by docket ID number OPP-2002-0144 must be received on or before October 28, 2002.
Written objections and hearing requests may be submitted by mail, in person, or by courier. Please follow the detailed instructions for each method as provided in Unit VI. of the
By mail: Sidney Jackson, Registration Division (7505C), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave., NW.,Washington, DC 20460; telephone number: (703) 305-7610; e-mail address: jackson.sidney@epa.gov.
You may be affected by this action if you are an agricultural producer, food manufacturer, or pesticide manufacturer. Potentially affected categories and entities may include, but are not limited to:
This listing is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. Other types of entities not listed in the table could also be affected. The North American Industrial Classification System (NAICS) codes have been provided to assist you and others in determining whether or not this action might apply to certain entities. If you have questions regarding the applicability of this action to a particular entity, consult the person listed under
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In the
The petition requested that 40 CFR 180.415 be amended by establishing tolerances for residues of the fungicide fosetyl-Al, aluminum tris (
Section 408(b)(2)(A)(i) of the FFDCA allows EPA to establish a tolerance (the legal limit for a pesticide chemical residue in or on a food) only if EPA determines that the tolerance is “safe.” Section 408(b)(2)(A)(ii) defines “safe” to mean that “there is a reasonable certainty that no harm will result from aggregate exposure to the pesticide chemical residue, including all anticipated dietary exposures and all other exposures for which there is reliable information.” This includes exposure through drinking water and in residential settings, but does not include occupational exposure. Section 408(b)(2)(C) requires EPA to give special consideration to exposure of infants and children to the pesticide chemical residue in establishing a tolerance and to “ensure that there is a reasonable certainty that no harm will result to infants and children from aggregate exposure to the pesticide chemical residue. . . .”
EPA performs a number of analyses to determine the risks from aggregate exposure to pesticide residues. For further discussion of the regulatory requirements of section 408 and a complete description of the risk assessment process, see the final rule on Bifenthrin Pesticide Tolerances (62 FR 62961, November 26, 1997) (FRL-5754-7).
Consistent with section 408(b)(2)(D), EPA has reviewed the available scientific data and other relevant information in support of this action. EPA has sufficient data to assess the hazards of and to make a determination on aggregate exposure, consistent with section 408(b)(2), for a tolerances for residues of fosetyl-Al on bushberry subgroup, lingonberry, salal, and juneberry at 40 ppm; turnip tops at 40 ppm; turnip roots at 15 ppm; succulent pea at 0.3 ppm; and citrus fruit group at 5.0 ppm. EPA's assessment of exposures and risks associated with establishing the tolerances follows.
EPA has evaluated the available toxicity data and considered their validity, completeness, and reliability as well as the relationship of the results of the studies to human risk. EPA has also considered available information concerning the variability of the sensitivities of major identifiable subgroups of consumers, including infants and children. The nature of the toxic effects caused by fosetyl-Al are discussed in the
The dose at which no adverse effects are observed (the NOAEL) from the toxicology study identified as appropriate for use in risk assessment is used to estimate the toxicological level of concern (LOC). However, the lowest dose at which adverse effects of concern are identified (the LOAEL) is sometimes used for risk assessment if no NOAEL was achieved in the toxicology study selected. An uncertainty factor (UF) is applied to reflect uncertainties inherent in the extrapolation from laboratory animal data to humans and in the variations in sensitivity among members of the human population as well as other unknowns. An UF of 100 is routinely used, 10X to account for interspecies differences and 10X for intraspecies differences.
For dietary risk assessment (other than cancer) the Agency uses the UF to calculate an acute or chronic reference dose (acute RfD or chronic RfD) where the RfD is equal to the NOAEL divided by the appropriate UF (RfD = NOAEL/UF). Where an additional safety factor is retained due to concerns unique to the FQPA, this additional factor is applied to the RfD by dividing the RfD by such additional factor. The acute or chronic Population Adjusted Dose (aPAD or cPAD) is a modification of the RfD to accommodate this type of FQPA Safety Factor.
For non-dietary risk assessments (other than cancer) the UF is used to determine the LOC. For example, when 100 is the appropriate UF (10X to account for interspecies differences and 10X for intraspecies differences) the LOC is 100. To estimate risk, a ratio of the NOAEL to exposures (margin of exposure (MOE) = NOAEL/exposure) is calculated and compared to the LOC.
The linear default risk methodology (Q*) is the primary method currently used by the Agency to quantify carcinogenic risk. The Q* approach assumes that any amount of exposure will lead to some degree of cancer risk. A Q* is calculated and used to estimate risk which represents a probability of occurrence of additional cancer cases (e.g., risk is expressed as 1 x 10-
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The Agency lacks sufficient monitoring exposure data to complete a comprehensive dietary exposure analysis and risk assessment for fosetyl-Al in drinking water. Because the Agency does not have comprehensive monitoring data, drinking water concentration estimates are made by reliance on simulation or modeling taking into account data on the physical characteristics of fosetyl-Al.
The Agency uses the FQPA Index Reservoir Screening Tool (FIRST) or the Pesticide Root Zone/Exposure Analysis Modeling System (PRZM/EXAMS), to produce estimates of pesticide concentrations in an index reservoir. The Screening Concentrations in Ground Water (SCI-GROW) model is used to predict pesticide concentrations in shallow ground water. For a screening-level assessment for surface water EPA will use FIRST (a tier 1 model) before using PRZM/EXAMS (a tier 2 model). The FIRST model is a subset of the PRZM/EXAMS model that uses a specific high-end runoff scenario for pesticides. While both FIRST and PRZM/EXAMS incorporate an index reservoir environment, the PRZM/EXAMS model includes a percent crop area factor as an adjustment to account for the maximum percent crop coverage within a watershed or drainage basin.
None of these models include consideration of the impact processing (mixing, dilution, or treatment) of raw water for distribution as drinking water would likely have on the removal of pesticides from the source water. The primary use of these models by the Agency at this stage is to provide a coarse screen for sorting out pesticides for which it is highly unlikely that drinking water concentrations would ever exceed human health levels of concern.
Since the models used are considered to be screening tools in the risk assessment process, the Agency does not use estimated environmental concentrations (EECs) from these models to quantify drinking water exposure and risk as a %RfD or %PAD. Instead drinking water levels of comparison (DWLOCs) are calculated and used as a point of comparison against the model estimates of a pesticide's concentration in water. DWLOCs are theoretical upper limits on a pesticide's concentration in drinking water in light of total aggregate exposure to a pesticide in food, and from residential uses. Since DWLOCs address total aggregate exposure to fosetyl-Al, they are further discussed in the aggregate risk sections in Unit III.E.
Based on the FIRST and SCI-GROW 2 models, the EECs for fosetyl-Al for acute exposures are estimated to be 0.0086 parts per billion (ppb) for surface water and
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Fosetyl-Al is currently registered for use on the following residential non-dietary sites: Lawn, turf, and ornamental plants under the brand names CHIPO Aliette WDG and Aliette HG. CHIPO Aliette WDG is sold to professional applicators only, which includes lawn care operators (LCO). Because all residential uses of CHIPO Aliette WDG are applied by the LCO, a residential applicator exposure assessment for this product was not performed. Short- and intermediate-term dermal, inhalation, and oral exposures to fosetyl-Al may occur from residential handling/post-application activities.
Short-term (1 to 30 days) dermal and inhalation exposures may occur to adult residential handlers from mixing, loading and applying fosetyl-Al to turf. However, intermediate-term (1 to 6 months) and long-term (more than 6 months) exposure durations are not likely based on the use pattern. In addition, the Agency did not select applicable short- or intermediate-term dermal endpoints. Therefore, only short-term inhalation exposure assessments for residential handlers from mixing, loading and applying fosetyl-Al to turf were performed. MOEs for short-term inhalation exposures are estimated at 170,000 for mixing loading and applying to turf with low pressure handwands and 140,000 for mixing, loading and applying to turf with hose-end sprayer. Short-term MOEs for inhalation exposure are above 100 and do not exceed EPA's level of concern.
There is potential dermal (adults and children) and oral exposure (children only) during post-application activities. However, because no dermal toxicity endpoints were identified, only incidental oral exposure to children is assessed. The following post-application exposure scenarios resulting from lawn treatment were assessed: (1) Incidental non-dietary ingestion of pesticide residues on lawns from hand-to-mouth transfer; (2) incidental non-dietary ingestion of residues from object-to-mouth activities (pesticide-treated turfgrass); and (3) incidental non-dietary ingestion of soil from pesticide-treated residential areas. The exposure and risk estimates for the three residential exposure scenarios are assessed for the day of application (day “0”) because it is assumed that children could contact the lawn immediately after application. On the day of application, it was assumed that 5% of the application rate is available from the turfgrass as transferrable residue (20% for object-to-mouth activities). Based on the short half-life (
Residential exposures that could reasonably be expected to occur on the same day are combined and compared to the appropriate toxicity endpoint. Because no dermal endpoints were identified, the only multiple-residential exposure scenarios involve children's exposure from oral routes following
Spray drift is always a potential source of exposure to residents nearby to spraying operations. This is particularly the case with aerial application, but, to a lesser extent, could also be a potential source of exposure from the ground application method employed for fosetyl-Al. The Agency has been working with the Spray Drift Task Force, EPA Regional Offices and State Lead Agencies for pesticide regulation and other parties to develop the best spray drift management practices. The Agency is now requiring interim mitigation measures for aerial applications that must be placed on product labels/labeling. The Agency has completed its evaluation of the new data base submitted by the Spray Drift Task Force, a membership of U.S. pesticide registrants, and is developing a policy on how to appropriately apply the data and the AgDRIFT computer model to its risk assessments for pesticides applied by air, orchard airblast, and ground hydraulic methods. After the policy is in place, the Agency may impose further refinements in spray drift management practices to reduce off-target drift and risks associated with aerial as well as other application types where appropriate.
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EPA does not have, at this time, available data to determine whether fosetyl-Al has a common mechanism of toxicity with other substances or how to include this pesticide in a cumulative risk assessment. Unlike other pesticides for which EPA has followed a cumulative risk approach based on a common mechanism of toxicity, fosetyl-Al does not appear to produce a toxic metabolite produced by other substances. For the purposes of this tolerance action, therefore, EPA has not assumed that fosetyl-Al has a common mechanism of toxicity with other substances. On this basis, the petitioner must submit, upon EPA's request and according to a schedule determined by the Agency, such information as the Agency directs to be submitted in order to evaluate issues related to whether fosetyl-Al shares a common mechanism of toxicity with any other substance and, if so, whether any tolerances for fosetyl-Al need to be modified or revoked.
For information regarding EPA's efforts to determine which chemicals have a common mechanism of toxicity and to evaluate the cumulative effects of such chemicals, see the final rule for Bifenthrin Pesticide Tolerances (62 FR 62961, November 26, 1997).
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EPA determined that the 10X safety factor to protect infants and children should be reduced to 1X. The FQPA factor was reduced because the toxicology data base is complete; the developmental and reproductive toxicity data did not indicate increased quantitative or qualitative susceptibility of rats or rabbits to
To estimate total aggregate exposure to a pesticide from food, drinking water, and residential uses, the Agency calculates DWLOCs which are used as a point of comparison against the model estimates of a pesticide's concentration in water (EECs). DWLOC values are not regulatory standards for drinking water. DWLOCs are theoretical upper limits on a pesticide's concentration in drinking water in light of total aggregate exposure to a pesticide in food and residential uses. In calculating a DWLOC, the Agency determines how much of the acceptable exposure (i.e., the PAD) is available for exposure through drinking water (e.g., allowable chronic water exposure (mg/kg/day) = cPAD - (average food + residential exposure)). This allowable exposure through drinking water is used to calculate a DWLOC.
A DWLOC will vary depending on the toxic endpoint, drinking water consumption, and body weights. Default body weights and consumption values as used by the USEPA Office of Water are used to calculate DWLOCs: 2L/70 kg (adult male), 2L/60 kg (adult female), and 1L/10 kg (child). Default body weights and drinking water consumption values vary on an individual basis. This variation will be taken into account in more refined screening-level and quantitative drinking water exposure assessments. Different populations will have different DWLOCs. Generally, a DWLOC is calculated for each type of risk assessment used: Acute, short-term, intermediate-term, chronic, and cancer.
When EECs for surface water and ground water are less than the calculated DWLOCs, OPP concludes with reasonable certainty that exposures to the pesticide in drinking water (when considered along with other sources of exposure for which OPP has reliable data) would not result in unacceptable levels of aggregate human health risk at this time. Because OPP considers the aggregate risk resulting from multiple exposure pathways associated with a pesticide's uses, levels of comparison in drinking water may vary as those uses change. If new uses are added in the future, OPP will reassess the potential impacts of residues of the pesticide in drinking water as a part of the aggregate risk assessment process.
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Using the exposure assumptions described in this unit for chronic exposure, EPA has concluded that exposure to fosetyl-Al from food will utilize 4% of the cPAD for the U.S. population, 5% of the cPAD for infants and 8% of the cPAD for children 1-6 years old, subpopulation at greatest exposure. Based on the use pattern, chronic residential exposure to residues of fosetyl-Al is not expected. In addition, there is potential for chronic dietary exposure to fosetyl-Al in drinking water. After calculating DWLOCs and comparing them to the EECs for surface and ground water, EPA does not expect the aggregate exposure to exceed 100% of the cPAD.
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A short-term risk assessment is required for adults because there is a residential handler inhalation exposure scenario. In addition, a short-term risk assessment is required for infants and children because there is a residential post-application oral exposure scenario. As no short- or intermediate-term dermal endpoint was established, there is no dermal component to these aggregate risk assessments.
Fosetyl-Al is currently registered for use that could result in short-term residential exposure and the Agency has determined that it is appropriate to aggregate chronic food and water and short-term exposures for fosetyl-Al.
Using the exposure assumptions described in this unit for short-term exposures, EPA has concluded that food and residential exposures aggregated result in aggregate MOEs of 3,300 for adults, 570 for children ages 1-6 years old, and 650 for all infants (less than 1 year old). These aggregate MOEs do not exceed the Agency's level of concern for aggregate exposure to food and residential uses. In addition, short-term DWLOCs were calculated and compared to the EECs for chronic exposure of fosetyl-Al in ground and surface water. After calculating DWLOCs and comparing them to the EECs for surface and ground water, EPA does not expect short-term aggregate exposure to exceed the Agency's level of concern, as shown in the following Table 3:
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An intermediate-term risk assessment was not performed since adult residential handler scenarios are not expected to occur for longer than a short-term timeframe (more than 30 days of continuous exposure) and intermediate-term exposure is not likely to occur for infants and children (residential post-application oral exposure scenario) because fosetyl-Al has a very short half-life (less than 3 hours in aerobic soil).
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6.
An adequate analytical method is available for enforcement of the proposed tolerances in/on turnips (roots and tops), succulent peas, blueberries, and citrus. The method is Method I in PAM II, which uses diazomethane as the methylating agent and quantitation of fosetyl-Al by GC/FPD. The limit of quantitation (LOQ) is 0.05 ppm for turnips and succulent peas and 0.1 ppm for citrus. The method may be requested from: Francis Griffith, Analytical Chemistry Branch, Environmental Science Center, Environmental Protection Agency, 701 Mapes Road, Fort George G. Mead, MD 20755-5350; telephone number: (410) 305-2905; e-mail address: griffith.francis@epa.gov.
There are no established or proposed maximum residue limits or tolerances for fosetyl-Al in or on turnip roots and tops, succulent peas, blueberries or citrus fruit for Canada, Mexico, or Codex.
Registration for succulent pea will be conditional pending the submission of adequate storage stability data for this crop.
Therefore, the tolerances are established for residues of fosetyl-Al, aluminum tris (
Under section 408(g) of the FFDCA, as amended by the FQPA, any person may file an objection to any aspect of this regulation and may also request a hearing on those objections. The EPA procedural regulations which govern the submission of objections and requests for hearings appear in 40 CFR part 178. Although the procedures in those regulations require some modification to reflect the amendments made to the FFDCA by the FQPA of 1996, EPA will continue to use those procedures, with appropriate adjustments, until the necessary modifications can be made. The new section 408(g) provides essentially the same process for persons to “object” to a regulation for an exemption from the requirement of a tolerance issued by EPA under new section 408(d), as was provided in the old FFDCA sections 408 and 409. However, the period for filing objections is now 60 days, rather than 30 days.
You must file your objection or request a hearing on this regulation in accordance with the instructions provided in this unit and in 40 CFR part 178. To ensure proper receipt by EPA, you must identify docket control number OPP-2002-0144 in the subject line on the first page of your submission. All requests must be in writing, and must be mailed or delivered to the Hearing Clerk on or before October 28, 2002.
1.
Mail your written request to: Office of the Hearing Clerk (1900C), Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460. You may also deliver your request to the Office of the Hearing Clerk in Rm. 104, Crystal Mall #2, 1921 Jefferson Davis Hwy., Arlington, VA. The Office of the Hearing Clerk is open from 8 a.m. to 4 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Office of the Hearing Clerk is (703) 603-0061.
2.
EPA is authorized to waive any fee requirement “when in the judgement of the Administrator such a waiver or refund is equitable and not contrary to the purpose of this subsection.” For additional information regarding the waiver of these fees, you may contact James Tompkins by phone at (703) 305-5697, by e-mail at tompkins.jim@epa.gov, or by mailing a request for information to Mr. Tompkins at Registration Division (7505C), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
If you would like to request a waiver of the tolerance objection fees, you must mail your request for such a waiver to: James Hollins, Information Resources and Services Division (7502C), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
3.
A request for a hearing will be granted if the Administrator determines that the material submitted shows the following: There is a genuine and substantial issue of fact; there is a reasonable possibility that available evidence identified by the requestor would, if established resolve one or more of such issues in favor of the requestor, taking into account uncontested claims or facts to the contrary; and resolution of the factual issues(s) in the manner sought by the requestor would be adequate to justify the action requested (40 CFR 178.32).
This final rule establishes a tolerances under FFDCA section 408(d) in response to a petition submitted to the Agency. The Office of Management and Budget (OMB) has exempted these types of actions from review under Executive Order 12866, entitled
The Congressional Review Act, 5 U.S.C. 801
Environmental protection, Administrative practice and procedure, Agricultural commodities, Pesticides and pests, Reporting and recordkeeping requirements.
21 U.S.C. 321(q), 346(a) and 374.
(a) * * *
Federal Election Commission.
Notice of proposed rulemaking.
The Federal Election Commission seeks comments on proposed changes to its rules relating to disclaimers in political communications, fraudulent solicitations, civil penalties, and personal use of campaign funds under the Federal Election Campaign Act of 1971, as amended (“FECA” or “the Act”). The proposed rules implement the Bipartisan Campaign Reform Act of 2002 (“BCRA”), which specifies new requirements for disclaimers accompanying radio, television, and print campaign communications; expands the scope of FECA's fraudulent misrepresentation prohibition; increases FECA's civil penalties for violating the prohibition on contributions made in the name of another; and codifies the “irrespective” test for permissible use of campaign funds by candidates and Federal office holders. The Commission had planned to address BCRA-related rules for inaugural committees in this rulemaking; however, inaugural committees will now instead be addressed in a future rulemaking.
Please note that the draft rules that follow do not represent a final decision by the Commission on the issues presented by this rulemaking. Further information is provided in the supplementary information that follows.
Comments must be received on or before September 27, 2002.
All comments should be addressed to Mr. John C. Vergelli, Acting Assistant General Counsel, and must be submitted in either electronic or written form. Electronic mail comments should be sent to
Mr. John C. Vergelli, Acting Assistant General Counsel, or Attorneys, Ms. Ruth Heilizer (personal use), Ms. Dawn Odrowski (fraudulent solicitations), Mr. Mark Allen (civil penalties), Mr. Richard Ewell (disclaimers), 999 E Street, NW., Washington, DC 20463, (202) 694-1650 or (800) 424-9530.
The Bipartisan Campaign Reform Act of 2002 (“BCRA”), Pub. L. 107-155, 116 Stat. 81 (March 27, 2002), contains extensive detailed amendments to the Federal Election Campaign Act of 1971 (“FECA” or “the Act”), as amended, 2 U.S.C. 431
This NPRM addresses changes to: disclaimer requirements for campaign communications (2 U.S.C. 441d); fraudulent misrepresentation for purposes of soliciting contributions or donations (2 U.S.C. 441h); civil penalties for a specific knowing and willful violation of FECA (2 U.S.C. 437g); permissible uses of campaign funds by candidates and officeholders (2 U.S.C. 439a); and a technical amendment to the definition of “Act” to include BCRA amendments to FECA. The changes to the Act addressed in this NPRM are only a few of many changes made to the Act by BCRA. Other rulemakings have addressed or will address: (1) Non-Federal funds or “soft money” (promulgated on June 22, 2002, 67 FR 49064 (July 29, 2002)); (2) reorganization of “contribution” and “expenditure” definitions (promulgated on August 5, 2002, 67 FR 50582); (3) electioneering communications (Notice of Proposed Rulemaking, 67 FR 51131 (August 7, 2002)); (4) coordinated and independent expenditures;
Under the Act, certain communications must include disclaimers identifying who paid for and, where applicable, who authorized the communication. In BCRA, Congress added new specificity to these requirements, expanded the disclaimer requirement to reach “any communication” made by political committees, and required that “electioneering communications” include disclaimers.
The Commission proposes to implement these statutory changes by deleting pre-BCRA 11 CFR 110.11 in its entirety, and adopting a new section 110.11. As explained in detail below, proposed section 110.11 would incorporate many substantive provisions from the pre-BCRA version of the section. By deleting pre-BCRA section 110.11 and adopting a new section 110.11, the Commission would be able to implement the changes necessitated by BCRA, and to reorganize 11 CFR 110.11 into a more easily understandable rule.
Proposed paragraph (a)(1) would set out the applicability of the section, and would define certain terms used in the section. Proposed paragraph (a)(1) would explain that the disclaimer requirements of this section would apply only to communications through any broadcast, cable, or satellite transmission, newspaper, magazine, outdoor advertising facility, mailing, or any other type of general public political advertising. This wording would generally follow 2 U.S.C. 441d(a), with one change from the statutory language. Whereas the statute refers only to “any broadcasting station,” the regulation would cover “any broadcast, cable, or satellite transmission.” This change is based on Congress' intent, apparent in 2 U.S.C. 441d(d), to regulate communications in the mass media of radio and television, and the Commission's judgment that it would be unsupportable to regulate a television communication that was broadcast, while not regulating the same communication merely because it was carried on cable or satellite.
The Commission seeks comment on whether the term
The Commission notes, however, that the definitions of “public communication” (2 U.S.C. 431(22)) and “communication” (2 U.S.C. 441d(a)) have a fundamental similarity in that both use virtually identical phrases, “or any other type [form] of general public political advertising,” to summarize the respective definitions. (Section 431(22) uses the word “form,” while section 441d(a) uses the word “type;” the Commission discerns no substantive differences arising from the choice of synonyms.) Also, conforming the definitions would appear to promote consistent use of terminology throughout the regulations.
Proposed paragraphs (a)(1)(i) through (iv) would enumerate the particular types of such communications to which the disclaimer requirements would apply. Throughout proposed section 110.11, the word “type” would be used, rather than “form,” as in the pre-BCRA version of the regulation. This change would have no substantive effect and would be done only to conform the regulation to the language of the statute. See 2 U.S.C. 441d.
In BCRA, Congress provided that “any communication” for which a political committee makes a disbursement must include a disclaimer, expanding the scope of the disclaimer requirement for political committee communications. 2 U.S.C. 441d(a). Proposed paragraph (a)(1)(i) would read, “[a]ll such communications for which a political committee makes a disbursement,” with the qualifier “such” intended to clarify that only communications by a political committee through one or more of the media enumerated in the first sentence of proposed paragraph (a)(1) must have a disclaimer.
Proposed paragraph (a)(1)(ii) would require that “[a]ll such communications by any person that expressly advocate the election or defeat of a clearly identified candidate” must include a disclaimer. 2 U.S.C. 441d(a). The proposed rule would not substantively change the disclaimer requirement for express advocacy communications from the pre-BCRA version of the regulation.
Proposed paragraph (a)(1)(iii) would require “[a]ll such communications by any person” that solicit a contribution to include a disclaimer. 2 U.S.C. 441d(a). The proposed rule would not change the disclaimer requirement for solicitations from the pre-BCRA version of the rule.
Congress amended 2 U.S.C. 441d(a) to require that “electioneering communications” include disclaimers. The Commission proposes new paragraph (a)(1)(iv), which would require that “[a]ll electioneering communications” include a disclaimer.
Proposed paragraph (a)(2) would define two terms used in the section. In a separate rulemaking, the Commission has proposed a definition of the term “electioneering communication,” as that term is used in BCRA. Proposed 11 CFR 100.29(a), see “Electioneering Communications,” 67 FR 51131 (Aug. 7, 2002). Proposed paragraph (a)(2)(i) would state that
In BCRA, Congress amended 2 U.S.C. 441d(a)(1) by removing the adjective “direct” from the pre-BCRA term “direct mailing.” The Commission proposes to define
Proposed paragraph (b) would set out the general content requirements for disclaimers, depending on who paid for the communication and, where applicable, who authorized the communication. Pre-BCRA paragraphs (a)(1)(i) and (ii) of section 110.11, which apply to communications authorized and paid for by a candidate and communications authorized by a candidate but paid for by another person, respectively, would be redesignated as proposed paragraphs (b)(1) and (2), respectively, without substantive revision.
Proposed paragraph (b)(3) would apply to a communication, including any solicitation, that is not paid for or authorized by a candidate. The provisions of pre-BCRA 11 CFR 110.11(a)(1)(iii) would be replaced with proposed paragraph (b)(3), with one substantive change. In BCRA, Congress provided that a covered communication not authorized by a candidate, his or her authorized committees or agents must have a disclaimer that includes the “permanent street address, telephone number, or World Wide Web address” of the person who paid for the communication. 2 U.S.C. 441d(a)(3). Similar language would be added in proposed paragraph (b)(3).
The Commission proposes not to continue pre-BCRA 11 CFR 110.11(a)(1)(iv) in proposed section 110.11. This paragraph, pre-BCRA, applies to “solicitations directed to the general public on behalf of a political committee which is not an authorized committee of a candidate.” Pre-BCRA paragraph (a)(1)(iv) thus appears to be redundant with proposed paragraph (b)(3),
In BCRA, Congress created a number of specific requirements for disclaimers to be included in communications covered by the statute. These statutory requirements vary, depending on whether the communication was printed or broadcast through radio or television, and on whether a candidate or another person paid for the communication. 2 U.S.C. 441d(c), (d). Proposed paragraph (c) would combine the disclaimer requirements in pre-BCRA 11 CFR 110.11(a)(5) with the new requirements Congress added in BCRA.
Proposed paragraph (c)(1) would set forth a general, “clear and conspicuous” requirement applicable to all disclaimers, regardless of the medium in which the communication is transmitted. Proposed paragraph (c)(1) would be a slightly revised version of the “clear and conspicuous” requirement in pre-BCRA 11 CFR 110.11(a)(5). The final sentence of proposed paragraph (c)(1) would provide that a disclaimer is not clear and conspicuous if it is difficult to read or hear, or if its placement is easily overlooked. This would modify the corresponding pre-BCRA provision, which was focused on print communications only, by generalizing it to apply to radio and television communications, as well. The Commission seeks comment on this proposed paragraph.
Several of the specific disclaimer requirements added by BCRA apply only to printed communications. 2 U.S.C. 441d(c)(1). Proposed paragraph (c)(2) would implement the new statutory specifications, and would incorporate three of the print-specific provisions of pre-BCRA section 110.11.
Given the specificity of the statutory requirements added by BCRA, proposed paragraphs (c)(2)(i), (ii), and (iii) would precisely track 2 U.S.C. 441d(c)(1), (2), and (3), respectively. Proposed paragraph (c)(2)(i) would require that the disclaimer on printed communications be of sufficient type size to be clearly readable by the recipient. 2 U.S.C. 441d(c)(1). The Commission seeks comment on whether the term, “sufficient type size,” should be further addressed, either in a specific definition, or by providing a “safe harbor” for disclaimers of at least a specified size. For example, the disclaimer type size could be related, as a percentage or fraction, to the communication's core message text. If the core message text in the communication appears in an 18-point font, the regulation could require that the disclaimer text must appear in a type font, for example, at least two-thirds the size of 18-point font, or 12-point font, or could deem it sufficient if it was of such size. Alternatively, the disclaimer type size could be related, as a percentage or fraction, to the largest type size that appears in the communication. For example, if the banner text or headline text on a newspaper advertisement is two inches tall by twelve inches wide, the disclaimer text must be 60% of the banner text or headline text, or 1.2 inches tall by 7.2 inches wide, or would be deemed sufficient if of at least that size. Or, alternatively, there could be a safe harbor for a disclaimer with a type size that is at least as large as the smallest type size in the communication. Or, there could be a safe harbor for a disclaimer with a type size that is at least as large as the smallest type size in the body of the text of the message.
Proposed paragraph (c)(2)(ii) would specify that the disclaimer included in printed communications must be contained within a printed box set apart from the other contents of the communication. 2 U.S.C. 441d(c)(2). Proposed paragraph (c)(2)(iii) would specify that the text of the disclaimer must be printed with a reasonable degree of color contrast between the background and the printed statement. 2 U.S.C. 441d(c)(3). The Commission seeks comment on whether “reasonable degree of color contrast” should be further defined, and specifically whether the color contrast requirement should be related to the color contrast of the core message text.
Proposed paragraphs (c)(2)(iv) and (v) would incorporate pre-BCRA provisions specific to print communications. Proposed paragraph (c)(2)(iv), to which the provisions of pre-BCRA paragraph (a)(5)(i) would be redesignated without substantive revision, would state that a disclaimer need not appear on the front cover of a communication, except for communications that only contain a front face, such as billboards. Proposed paragraph (c)(2)(v), to which the provisions of pre-BCRA paragraph (a)(5)(ii) would be redesignated without substantive change, would state that a communication that would require a disclaimer if distributed separately, and that is included in a package of materials, must contain the required disclaimer.
In BCRA, Congress added new requirements for disclaimers in radio and television communications paid for by candidates or persons authorized by candidates. 2 U.S.C. 441d(d)(1). Proposed paragraph (c)(3) would implement these specific statutory requirements.
Proposed paragraph (c)(3)(i) would require that a communication that is paid for or authorized by a candidate and transmitted through radio must include an audio statement spoken by the candidate himself or herself. 2 U.S.C. 441d(d)(1)(A). The statement would have to identify the candidate, and state that the candidate has approved the communication.
Proposed paragraph (c)(3)(ii) would require that a communication that is paid for or authorized by a candidate and transmitted through television have an oral disclaimer spoken by the candidate himself or herself. 2 U.S.C. 441d(d)(1)(B). The provision would require the candidate to identify himself or herself, and state that he or she has approved the communication. In addition, proposed paragraph (c)(3)(ii) would require that a full-screen view or a picture of the candidate appear while the statement is conveyed. The proposed paragraph would also require the statement to appear in writing at the conclusion of the communication in a clearly readable manner, with a reasonable degree of color contrast between the statement and the background for a period of at least four (4) seconds.
The pre-BCRA regulations provide that a written disclaimer appearing on the screen of a television communication “shall be considered clear and conspicuous if [it] appear[s] in letters equal to or greater than four (4) percent of the vertical picture height for not less than four (4) seconds.” 11 CFR 110.11(a)(5)(iii). The proposed regulations would not continue this “safe harbor” provision because Congress has added specific statutory requirements that render it incomplete. Specifically, the statute now requires that the written disclaimer in television communications appear “with a reasonable degree of color contrast between the background and written statement.” 2 U.S.C. 441d(d)(1)(B); proposed 11 CFR 110.11(c)(3)(ii), above. Neither the statute nor these proposed regulations define “reasonable degree of
Proposed paragraph (c)(3)(iii) would set out two examples of spoken disclaimers that, if used by a candidate, would satisfy the requirements of proposed paragraphs (c)(3)(i) and (ii). The proposed examples would not be mandatory and would not be an exhaustive list of acceptable disclaimers. Proposed paragraph (c)(3)(iii) would be intended to provide a clear “safe harbor” for candidates attempting to comply with the regulation. The Commission seeks comment on the use of these or other examples.
Congress set forth a scripted audio statement required for disclaimers in communications transmitted through radio or television and paid for by persons other than candidates or persons authorized by candidates. 2 U.S.C. 441d(d)(2). The Commission proposes new paragraph (c)(4), which would, tracking the statute, require the name of the political committee or other person responsible for the communication and any connected organization to be included in the communication. “Connected organization” is defined in 11 CFR 100.6. The scripted statement would be: “XXX is responsible for the content of this advertising.” 2 U.S.C. 441d(d)(2). Furthermore, in the case of a television transmission the proposed rule would require that the statement be conveyed by a full-screen view of a representative of the political committee making the statement, or in a voice-over by such representative. The Commission seeks comment on whether the regulation should specify who may represent the payor for this purpose. The regulation could, for example, require that the representative be an officer or the treasurer, or it could allow a paid spokesperson, such as a celebrity or actor. In the case of a television transmission, the disclaimer statement would also have to appear in writing at the end of the communication in a clearly readable manner with a reasonable degree of color contrast between the background and the printed statement for a period of at least four (4) seconds. 2 U.S.C. 441d(d)(2).
Proposed paragraph (d) of section 110.11 would cover disclaimers for communications that constitute coordinated party expenditures and independent expenditures by political party committees. The relevant pre-BCRA provisions of 11 CFR 110.11(a)(2) would be redesignated as proposed paragraph (d)(1), without substantive change. There would be a minor grammatical change.
Proposed paragraph (d)(2) would cover communications that constitute independent expenditures by political party committees.
The Commission proposes to redesignate the provisions of pre-BCRA 11 CFR 110.11(a)(4), pertaining to communications that qualify as “exempt activities,” as proposed paragraph (e) of section 110.11. Proposed paragraph (e) would include two minor revisions to its pre-BCRA predecessor. In the first sentence, the word “expenditure” would be replaced with the word “communication” to conform this proposed paragraph to the wording of proposed paragraph (a). This proposed revision would not constitute a substantive change. Also, there would be a non-substantive revision to the cross-reference to the definitions of “exempt activities,” which would be updated to reflect changes to part 100 made in a recent reorganization rulemaking. “Reorganization of Regulations on ‘Contribution’ and ‘Expenditure,’ ” 67 FR 50582 (Aug. 5, 2002). Overall, the relocation and the minor revisions would not be intended to change the substantive operation of these provisions.
Exceptions to the disclaimer requirements would be set out in proposed paragraph (f). The exceptions in pre-BCRA paragraphs (a)(6)(i), (ii), and (iii) would be redesignated as proposed paragraphs (f)(1)(i), (ii), and (iii), respectively, without any other revision.
The Commission proposes incorporating the provisions of pre-BCRA 11 CFR 110.11(a)(7), regarding certain communications by a separate segregated fund or its connected organization, in proposed paragraph (f)(2), because this provision is essentially an exception. In addition, in proposed paragraph (f)(2), the word “form” would be changed to “type.” This change would have no substantive effect, and would be done only to conform to the language of the statute.
Proposed paragraph (g) of section 110.11 would continue the pre-BCRA rule pertaining to comparable rates for print advertising. That is, the contents of pre-BCRA 11 CFR 110.11(b) would be redesignated as proposed paragraph (g). Other than the addition of a heading for the paragraph, there would be no revisions to the pre-BCRA rule. Proposed paragraph (g) would, as does its pre-BCRA predecessor, track 2 U.S.C. 441d(b).
In BCRA, Congress adds a subsection to the fraudulent misrepresentation statute at 2 U.S.C. 441h. The new provision, 2 U.S.C. 441h(b), prohibits a person from fraudulently misrepresenting that the person is acting for or on behalf of a Federal candidate or political party, or an employee or agent of either, for the purpose of soliciting contributions or donations. It also prohibits persons from participating in, or conspiring to participate in, plans, schemes, or designs to make such fraudulent misrepresentations in soliciting contributions and donations. BCRA also non-substantively amends the existing fraudulent misrepresentation statute by redesignating it as subsection (a) of 2 U.S.C. 441h. The Commission proposes to implement the new statutory provision, together with the pre-BCRA fraudulent misrepresentation regulation found at 11 CFR 110.9(b), by combining them in a new section 11 CFR 110.16.
The pre-BCRA misrepresentation statute, now codified at 2 U.S.C. 441h(a), is aimed at fraudulent misrepresentation of campaign authority. For additional background,
Because the language and purpose of the pre-BCRA misrepresentation statute encompasses only misrepresentations by a candidate or the candidate's employee or agent, the Commission has historically been unable to take action in enforcement matters where persons unassociated with a candidate or candidate committee have solicited funds by purporting to act on behalf of a specific candidate or party. Candidates have complained that contributions which contributors believed were going to benefit the candidate were diverted to other purposes, harming both the candidate and contributor. Consequently, the Commission has frequently included in its annual legislative recommendations to Congress a recommendation that 2 U.S.C. 441h be amended to specifically prohibit any person from fraudulently misrepresenting a candidate or political party in solicitations.
Proposed 11 CFR 110.16(a) would amend the pre-BCRA fraudulent misrepresentation regulation at 11 CFR 110.9(b) by adding the title “in general,” following BCRA, which added a similar heading to section (a) of 2 U.S.C. 441h. Technical amendments would also make the language of proposed paragraph (a) gender-neutral. Finally, proposed paragraph (a)(2) would be amended to include the word “schemes” to more closely track the statutory language.
Proposed 11 CFR 110.16(b) would track the statutory language in BCRA. Proposed paragraph (b)(1) would prohibit a person from fraudulently misrepresenting that the person speaks, writes, or otherwise acts for or on behalf of a candidate, political party, or an employee or agent of either, in soliciting contributions or donations. Proposed paragraph (b)(2) would prohibit a person from willfully and knowingly participating in, or conspiring to participate in, any plan, scheme, or design to violate proposed paragraph (b)(1).
The Commission emphasizes that section 441h and proposed 11 CFR 110.16 are different from common law fraud. First, section 441h is part of a Federal statute designed to address campaign finance abuses, not common law fraud. Congress enacted FECA to protect the public interest. Unlike common law fraudulent misrepresentation, section 441h gives rise to no tort action; it is part of an enforcement scheme enacted to promote the integrity of the financing of Federal elections, and to prevent corruption or the appearance of corruption.
Thus, the Supreme Court has recognized that statutes that address schemes to defraud do not require proof of the common law requirements of “justifiable reliance” and “damages.”
Second, section 441h(a) states that the fraudulent misrepresentation must be “on a matter which is damaging to [the misrepresented] candidate or political party.” If this includes proof of damage as required by common law fraudulent misrepresentation, then the phrase “on a matter damaging” is superfluous. Courts construe statutes so “as to avoid rendering superfluous any parts thereof.”
The Commission seeks comments on proposed changes to its rules on civil penalties under FECA. The proposed rules are based on BCRA, which increases the civil penalties that may be negotiated by the Commission or imposed by a court for violations of the Act.
The Act imposes civil penalties on anyone violating any portion of the Act or certain related portions of the Federal tax code. The Act's civil penalties, found at 2 U.S.C. 437g(a)(5), (6), and (12), are organized into two tiers of monetary penalties; one tier of penalties for violations of the Act, and a second tier of penalties for “knowing and willful” violations of the Act.
BCRA amends sections 437g(a)(5)(B) and 437(g)(a)(6)(C) by separating out and increasing the penalties for a subset of knowing and willful violations, namely, contributions that are made in the name of another.
Section 437g(a)(6)(C) of FECA, authorizing a court to impose civil penalties on a person who knowingly and willfully violates the Act, has been similarly amended by BCRA. Accordingly, the Commission is proposing to amend current 11 CFR 111.24 to implement these amendments to FECA.
The proposed rule would divide current 11 CFR 111.24(a) into proposed paragraphs (a)(1), and (a)(2)(i) and (ii). Proposed paragraph (a)(1) would contain the unchanged language of the current regulation for civil penalties for violations of the Act or the relevant tax code provisions. Proposed paragraph (a)(2) would address “knowing and willful” violations and would be further divided into proposed paragraphs (a)(2)(i) and (ii). Proposed paragraph (a)(2)(i) would contain the unchanged language of the current regulation for civil penalties for knowing and willful violations of the Act or relevant tax code provisions. Proposed 11 CFR 111.24(a)(2)(ii) would contain proposed language implementing BCRA's amendments to FECA increasing civil penalties for knowing and willing violations involving contributions made in the name of another. The proposed language would explain that in the case of a knowing and willful violation of the prohibition on contributions in the name of another, the civil penalty would not be less than an amount that
In BCRA, Congress deleted 2 U.S.C. 439a in its entirety, and replaced it with a new section 439a. One of BCRA's principal sponsors explained:
[BCRA] amends 2 U.S.C. section 439a to specify which candidate expenditures from campaign funds would be considered an unlawful conversion of a contribution or donation to personal use. The language continues to allow candidates to use excess campaign funds for transfers to a national, State or local committee of a political party. It is the intent of the authors that—as is the case under current law—such transfers be permitted without limitation. Furthermore, while the provision is intended to codify the FEC's current regulations on the use of campaign funds for personal expenses, we do not intend to codify any advisory opinion or other current interpretation of those regulations.
The Commission notes that certain language from the pre-BCRA version of section 439a has not been included in the post-BCRA version of section 439a. First, the phrase “in excess of any amount necessary to defray” campaign expenses has been deleted from the statute. The Commission's personal use regulations are framed in terms of “excess campaign funds.”
Also, the post-BCRA version of 2 U.S.C. 439a does not include the language “any other lawful purpose” in the statutory enumeration of permissible uses of excess campaign funds, as did the pre-BCRA version of the statute. 11 CFR 113.2(d) provides that “excess campaign funds” may be “used for any other lawful purpose,” in addition to specific uses permitted in paragraphs (a), (b), and (c) of that section. The Commission proposes that 11 CFR 113.2(d) remain intact, as it believes that Congress's continuing intent is to allow only lawful uses of campaign funds and donations. The Commission seeks comment on these proposals.
The pre-BCRA version of 2 U.S.C. 439a contained a general prohibition against the personal use of campaign funds, but did not specify any particular impermissible uses. The Commission's pre-BCRA personal use regulations define certain uses of campaign funds or donations as per se prohibited personal uses. 11 CFR 113.1(g)(1)(i). In BCRA, Congress amended 2 U.S.C. 439a to include a non-exhaustive list of prohibited personal uses of campaign funds. 2 U.S.C. 439a(b). As one of BCRA's principal sponsors explained, new section 439a “[c]odifies FEC regulations relating to the personal use of campaign funds by candidates. Contributions will be considered converted to personal use if they are used for an expense that would exist irrespective of the campaign or duties as an officeholder, including home mortgage or rent, clothing, vacation expenses, tuition payments, non-campaign-related automobile expenses, and a variety of other items.” 148 Cong. Rec. S1993-1994 (daily ed. March 18, 2002) (statement of Sen. Feingold).
The Commission notes that several of new 2 U.S.C. 439a's personal use provisions are summarized versions of pre-BCRA personal use regulations. For example, the statute now prohibits the use of campaign contributions and donations for “a clothing purchase” (2 U.S.C. 439a(b)(2)(B)); whereas the corresponding regulation at 11 CFR 113.1(g)(1)(i)(C) prohibits the personal use of “[c]lothing, other than items of
The Commission proposes three changes to its
In addition, new section 439a includes “a vacation or other non-campaign-related trip” in the list of prohibited uses of excess campaign funds. 2 U.S.C. 439a(b)(2)(E). The Commission accordingly proposes to include an implementing “vacations and other non-campaign-related trips” provision as 11 CFR 113.1(g)(1)(i)(K). The Commission also proposes to modify current 11 CFR 113.1g(1)(ii)(C), which applies to “travel expenses” and is located in the “case by case” category of rules, to indicate that “vacations and other non-campaign-related trips” are
Proposed 11 CFR 113.1(g)(1)(i)(K) tracks the statutory language of new 2 U.S.C. 439a. However, candidates who are Federal officeholders may take trips that are not campaign-related, such as factfinding trips, which may nonetheless be part of their duties as Federal officeholders. The Commission seeks comment on whether Congress intended to ban completely the use of campaign funds for such trips. Compare 11 CFR 113.1(g)(5), which states in part that the use of campaign funds for “political or officially connected expenses * * * [are] not personal use to the extent that the expense is * * * an ordinary and necessary expense incurred in connection with the duties of a holder of Federal office,” with 2 U.S.C. 439a(b)(2)(E). Additionally, the Commission seeks comment on whether non-vacation, non-campaign-related travel should be evaluated on a case-by-case basis, under proposed 11 CFR 113.1(g)(1)(ii)(C).
The Commission proposes one other change to the
The Commission notes that Congress codified the regulatory “irrespective” test. 2 U.S.C. 439a(b)(2);
The Commission proposes a recordkeeping requirement for campaign funds used for expenses that may be partially personal in nature, including vehicle expenses, as set forth in proposed 11 CFR 113.1(g)(1)(i)(J), and legal expenses, meal expenses, travel expenses, and charitable expenses, as listed in 11 CFR 113.1(g)(1)(ii) and (g)(2).
Current 11 CFR 100.18 defines “Act” to mean the Federal Election Campaign Act as amended by the 1974, 1976, and 1980 amendments. The proposed rules would amend this definition to include the amendments to FECA within the Bipartisan Campaign Reform Act.
The Commission certifies that the attached proposed rules, if promulgated, will not have a significant economic impact on a substantial number of small entities. The basis of this certification is that national, State, and local party committees of the two major political parties to which the proposed fraudulent solicitation, disclaimers, and civil penalties rules would apply are not small entities under 5 U.S.C. 601. In addition, the rules for personal use would only affect individuals, not entities, and the rules for the prohibition on fraudulent solicitation do not carry an economic impact. Furthermore, the small entities to which the rules would apply would not be unduly burdened by the proposed new requirements for disclaimers since the proposed requirements only add specificity to the current disclaimer requirements. The proposed increase in civil penalties would not unduly burden small entities since a small entity would pay a civil penalty only if the entity engaged in a specific knowing and willful violation of the Act.
Elections
Campaign funds, and political committees and parties.
Campaign funds, and political committee and parties.
Campaign funds, and political candidates.
For the reasons set out in the preamble, the Commission proposes to amend chapter I of title 11 of the
1. The authority citation for part 100 would be revised to read as follows:
2 U.S.C. 431, 434, 438(a)(8).
2. Section 100.18 would be revised to read as follows:
3. The authority citation for part 110 would be revised to read as follows:
2 U.S.C. 431(8), 431(9), 432(c)(2), 437d(a)(8), 438(a)(8), 441a, 441b, 441d, 441e, 441f, 441g, 441h, and 441k.
4. Section 110.11 would be revised to read as follows:
(a)
(1)
(i) All such communications for which a political committee makes a disbursement.
(ii) All such communications by any person that expressly advocate the election or defeat of a clearly identified candidate.
(iii) All such communications by any person that solicits any contribution.
(iv) All electioneering communications by any person.
(2)
(i) Electioneering communication has the same meaning as set forth at 11 CFR 100.29.
(ii) As used in this section only, mailing means more than one hundred substantially similar pieces of mail.
(b)
(1) If the communication, including any solicitation, is paid for and authorized by a candidate, an authorized committee of a candidate, or its agent, the disclaimer must clearly
(2) If the communication, including any solicitation, is authorized by a candidate, an authorized committee of a candidate, or its agent, but paid for by any other person, the disclaimer must clearly state that the communication is paid for by such other person and is authorized by such candidate, authorized committee, or agent; or
(3) If the communication, including any solicitation, is not authorized by a candidate, authorized committee of a candidate or its agents, the disclaimer must clearly state the full name and permanent street address, telephone number, or World Wide Web address of the person who paid for the communication, and that the communication is not authorized by any candidate or candidate's committee.
(c)
(1)
(2)
(i) The disclaimer must be of sufficient type size to be clearly readable by the recipient of the communication.
(ii) The disclaimer must be contained in a printed box set apart from the other contents of the communication.
(iii) The disclaimer must be printed with a reasonable degree of color contrast between the background and the printed statement.
(iv) The disclaimer need not appear on the front or cover page of the communication as long as it appears within the communication, except on communications, such as billboards, that contain only a front face.
(v) A communication that would require a disclaimer if distributed separately, that is included in a package of materials, must contain the required disclaimer.
(3)
(i) A communication transmitted through radio must include an audio statement by the candidate that identifies the candidate and states that he or she has approved the communication; or
(ii) A communication transmitted through television must include a statement that identifies the candidate and states that he or she has approved the communication. The statement shall be conveyed by an unobscured, full-screen view of the candidate making the statement, or the candidate in a voice-over, accompanied by a clearly identifiable photographic or similar image of the candidate. The statement shall also appear in writing at the end of the communication in a clearly readable manner with a reasonable degree of color contrast between the background and the disclaimer statement, for a period of at least four (4) seconds.
(iii) The following are examples of acceptable disclaimers for a communication covered by paragraph (c)(3) of this section, but they are not the only allowable disclaimers.
(A) “I am [insert name of candidate], a candidate for [insert Federal office sought], and I authorized this advertisement.”
(B) “My name is [insert name of candidate]. I am running for [insert Federal office sought], and I authorized this message.”
(4)
(i) A communication transmitted through radio or television must include the following audio statement, “XXX is responsible for the content of this advertising,” spoken clearly, with the blank to be filled in with the name of the political committee or other person paying for the communication, and the name of the connected organization, if any, of the payor; and
(ii) A communication transmitted through television must include the audio statement required by paragraph (c)(4)(i) of this section. The statement must be conveyed by an unobscured full-screen view of a representative of the political committee or other person making the statement, or by a representative of such political committee or other person in voice-over. The disclaimer statement must appear in writing at the end of the communication in a clearly readable manner with a reasonable degree of color contrast between the background and the printed statement, for a period of at least four (4) seconds.
(d)
(1) (i) For a communication paid for by a political party committee pursuant to 2 U.S.C. 441a(d), the disclaimer required by paragraph (a) of this section must identify the political party committee that makes the expenditure as the person who paid for the communication, regardless of whether the political party committee was acting in its own capacity or as the designated agent of another political party committee.
(ii) A communication made by a political party committee pursuant to 2 U.S.C. 441a(d) prior to the date the party's candidate is nominated shall satisfy the requirements of this section if it clearly states who paid for the communication.
(2) For a communication paid for by a political party committee that constitutes an independent expenditure under 11 CFR 100.16, the disclaimer required by this section must identify the political party committee that paid for the communication, and must state that the communication is not authorized by any candidate or candidate's committee.
(e)
(f)
(1) The requirements of paragraphs (a) through (e) of this section do not apply to the following:
(i) Bumper stickers, pins, buttons, pens, and similar small items upon which the disclaimer cannot be conveniently printed; or
(ii) Skywriting, water towers, wearing apparel, or other means of displaying an advertisement of such a nature that the inclusion of a disclaimer would be impracticable; or
(iii) Checks, receipts, and similar items of minimal value which are used for purely administrative purposes and do not contain a political message.
(2) Whenever a separate segregated fund or its connected organization solicits contributions to the fund from those persons it may solicit under the applicable provisions of 11 CFR part 114, or makes a communication to those persons, such communication shall not be considered a type of general public political advertising and need not contain the disclaimer set forth in paragraphs (a) through (c) of this section.
(g)
(1) No person who sells space in a newspaper or magazine to a candidate, an authorized committee of a candidate, or an agent of the candidate, for use in connection with the candidate's campaign for nomination or for election, shall charge an amount for the space which exceeds the comparable rate for the space for non-campaign purposes.
(2) For purposes of this section, comparable rate means the rate charged to a national or general rate advertiser, and shall include discount privileges usually and normally available to a national or general rate advertiser.
5. Section 110.16 would be added to read as follows:
(a)
(1) Fraudulently misrepresent the person or any committee or organization under the person's control as speaking or writing or otherwise acting for or on behalf of any other candidate or political party or employee or agent thereof in a matter which is damaging to such other candidate or political party or employee or agent thereof; or
(2) Willfully and knowingly participate in or conspire to participate in any plan, scheme, or design to violate paragraph (a)(1) of this section.
(b)
(1) Fraudulently misrepresent the person as speaking, writing, or otherwise acting for or on behalf of any candidate or political party or employee or agent thereof for the purpose of soliciting contributions or donations; or
(2) Willfully and knowingly participate in or conspire to participate in any plan, scheme, or design to violate paragraph (b)(1) of this section.
6. The authority citation for part 111 would continue to read as follows:
2 U.S.C. 437g, 437d(a), and 438(a)(8); 28 U.S.C. 2461 nt.
7. In § 111.24, paragraph (a) would be revised to read as follows:
(a) Except as provided in 11 CFR part 111, subpart B and in paragraph (b) of this section, a civil penalty negotiated by the Commission or imposed by a court for a violation of the Act or chapters 95 or 96 of title 26 (26 U.S.C.) shall be as follows:
(1) Except as provided in paragraph (a)(2) of this section, in the case of a violation of the Act or chapters 95 or 96 of title 26 (26 U.S.C), the civil penalty shall not exceed the greater of $5,500 or an amount equal to any contribution or expenditure involved in the violation.
(2) Knowing and willful violations.
(i) In the case of a knowing and willful violation of the Act or chapters 95 or 96 of title 26 (26 U.S.C.), the civil penalty shall not exceed the greater of $11,000 or an amount equal to 200% of any contribution or expenditure involved in the violation.
(ii) Notwithstanding paragraph (a)(2)(i) of this section, in the case of a knowing and willful violation of 2 U.S.C. 441f, the civil penalty shall not be less than 300% of the amount of any contribution involved in the violation and shall not exceed the greater of $50,000 or 1,000% of the amount of any contribution involved in the violation.
8. The authority citation for part 113 would continue to read as follows:
2 U.S.C. 439a.
9. In section 113.1, paragraph (g) would be revised to read as follows:
When used in this part—
(g)
(1) (i) Personal use includes but is not limited to the use of funds in a campaign account for:
(A) Household food items or supplies;
(B) Funeral, cremation or burial expenses;
(C) Clothing, other than items of
(D) Tuition payments, other than those associated with training campaign staff;
(E) Mortgage, rent or utility payments—
(
(
(F) Admission to a sporting event, concert, theater or other form of entertainment, unless part of a specific campaign or officeholder activity;
(G) Dues, fees or gratuities at a country club, health club, recreational facility or other nonpolitical organization, unless they are part of the costs of a specific fundraising event that takes place on the organization's premises;
(H) Salary payments to a member of the candidate's family, unless the family member is providing
(I) Salary payments to a candidate or any other compensation for income lost as a result of the campaign for federal office;
(J) Vehicle expenses, unless they are a
(K) A vacation or other non-campaign-related trip.
(ii) The Commission will determine, on a case by case basis, whether other uses of funds in a campaign account fulfill a commitment, obligation or expense that would exist irrespective of the candidate's campaign or duties as a Federal officeholder, and therefore are
(A) Legal expenses;
(B) Meal expenses; and
(C) Travel expenses, except for a vacation or other non-campaign-related trip under paragraph (g)(1)(i)(K) of this section, including subsistence expenses incurred during travel. If a committee uses campaign funds to pay expenses associated with travel that involves both personal activities and campaign or officeholder related activities, the incremental expenses that result from the personal activities are personal use, unless the person(s) benefiting from this use reimburse(s) the campaign account within thirty days for the amount of the incremental expenses.
(2)
(3)
(4)
(5)
(6)
(i) The payment is a donation to a legal expense trust fund established in accordance with the rules of the United States Senate or the United States House of Representatives;
(ii) The payment is made from funds that are the candidate's personal funds as defined in 11 CFR 110.10(b), including an account jointly held by the candidate and a member of the candidate's family;
(iii) Payments for that expense were made by the person making the payment before the candidate became a candidate. Payments that are compensation shall be considered contributions unless—
(A) The compensation results from
(B) The compensation is exclusively in consideration of services provided by the employee as part of this employment; and
(C) The compensation does not exceed the amount of compensation which would be paid to any other similarly qualified person for the same work over the same period of time.
(7)
(i) The spouse of the candidate;
(ii) Any child, step-child, parent, grandparent, sibling, half-sibling or step-sibling of the candidate or the candidate's spouse;
(iii) The spouse of any child, step-child, parent, grandparent, sibling, half-sibling or step-sibling of the candidate; and
(iv) A person who has a committed relationship with the candidate, such as sharing a household and having mutual responsibility for each other's personal welfare or living expenses.
(8) For those uses of campaign funds described in proposed paragraphs (g)(1)(i) and (g)(1)(ii) of this section that involve both personal use and campaign use, a contemporaneous log or other record must be kept to document the dates and expenses related to the personal use of the campaign funds. The log must be updated whenever campaign funds are used for personal expenses, as described in paragraph (g)(1) of this section, rather than for campaign expenses. The log or other record must also be maintained and preserved for 3 years after the report disclosing the disbursement is filed, pursuant to 11 CFR 102.9 and 104.14(b).
Federal Aviation Administration, DOT.
Notice of proposed rulemaking (NPRM).
This document proposes to supersede Airworthiness Directive (AD) 2002-05-05, which currently applies to certain Cirrus Design Corporation (Cirrus) Models SR20 and SR22 airplanes. AD 2002-05-05 currently requires you to incorporate temporary operating limitations into the Limitation Section of the airplane flight manual (AFM) for certain affected airplanes and install a cable clamp external to the cone adapter on the Cirrus Aircraft Parachute System (CAPS) activation cable for all affected airplanes. AD 2002-05-05 resulted from a report from the manufacturer that certain CAPS may not activate in an emergency situation. This proposed AD is the result of the manufacturer redesigning the CAPS activation system. This proposed AD would require you to modify the CAPS activation system. The actions specified by this proposed AD are intended to eliminate the chance of failure of the CAPS activation system in an emergency situation. Failure of this system could result in occupant injury and/or loss of life and loss of aircraft.
The Federal Aviation Administration (FAA) must receive any comments on this proposed rule on or before November 1, 2002.
Submit comments to FAA, Central Region, Office of the Regional Counsel, Attention: Rules Docket No. 2002-CE-31-AD, 901 Locust, Room 506, Kansas City, Missouri 64106. You may view any comments at this location between 8 a.m. and 4 p.m., Monday through Friday, except Federal holidays.
You may get service information that applies to this proposed AD from Cirrus Design Corporation, 4515 Taylor Circle, Duluth, MN 55811; telephone: (218) 727-2737. You may also view this information at the Rules Docket at the address above.
Gregory J. Michalik, Aerospace Engineer, FAA, Chicago ACO, 2300 East Devon Avenue, Des Plaines, IL 60018; telephone: (847) 294-7135; facsimile: (847) 294-7834.
The FAA invites comments on this proposed rule. You may submit whatever written data, views, or arguments you choose. You need to include the rule's docket number and submit your comments to the address specified under the caption
The FAA specifically invites comments on the overall regulatory, economic, environmental, and energy aspects of this proposed rule that might suggest a need to modify the rule.
You may view all comments we receive before and after the closing date of the rule in the Rules Docket. We will file a report in the Rules Docket that summarizes each contact we have with the public that concerns the substantive parts of this proposed AD.
If you want FAA to acknowledge the receipt of your mailed comments, you must include a self-addressed, stamped postcard. On the postcard, write “Comments to Docket No. 2002-CE-31-AD.” We will date stamp and mail the postcard back to you.
The FAA received a report from the type certificate holder that a condition existed that could cause the Cirrus Airplane Parachute System (CAPS) installed on certain Cirrus Design Corporation (Cirrus) Model SR20 and SR22 airplanes not to activate in the event of an emergency. Ballistic Recovery Systems (BRS), the supplier of the CAPS, discovered the condition during a supplemental type certificate (STC) certification test of the same unit on another airplane.
Investigation revealed that the rocket cone could allow for variance in the internal diameter at the threaded end of the rocket cone. This variance could result in the retaining nut internal to the cone adapter not to be fully secured on the affected parachutes. When the igniter end of the cable housing is unsecured, the cable will not pull the igniter pin free to release the parachute.
Section 23.221 of the Federal Aviation Regulations (14 CFR 23.221) requires that single-engine, normal category airplanes demonstrate compliance with either the one-turn spin recovery or the spin-resistant requirements. The airplane, for spin recovery compliance, must recover from a one-turn spin or a three-second spin, whichever takes longer, in not more than one additional turn after the controls have been applied for recovery. The Cirrus SR20/SR22 are not certificated to meet the spin recovery requirements or spin resistant requirements of 14 CFR 23.221. Instead, Cirrus installed an Airplane Parachute System (CAPS) that was FAA-approved as part of the SR20/SR22 type design.
Possible failure of the CAPS activation system in a emergency situation caused us to issue AD 2002-05-05, Amendment 39-12673 (67 FR 11220, March 13, 2002). AD 2002-05-05 requires the following:
—Incorporating temporary operating limitations into the Limitation Section of the airplane flight manual (AFM) for the airplanes with a CAPS that incorporates the process change; and
—Installing a cable clamp external to the cone adapter on the CAPS activation cable.
After further testing, Cirrus has made design changes to the whole CAPS activation system that now eliminates possible failure of the CAP activation system. Incorporation of the design changes eliminates the need for the actions of AD 2002-05-05.
Cirrus Design Corporation has issued the following service bulletins:
These service bulletins include procedures for:
After examining the circumstances and reviewing all available information related to the incidents described above, we have determined that:
This proposed AD would supersede AD 2002-05-05 with a new AD that would incorporate the actions in the previously-referenced service bulletins.
We estimate that this proposed AD affects 391 airplanes in the U.S. registry.
We estimate the following costs to accomplish the proposed modification to the CAPS handle access cover:
We estimate the following costs to accomplish the proposed modification to the CAPS activation handle bracket:
We estimate the following costs to accomplish the proposed modification to the CAPS activation cable:
We summarize the following estimated costs to accomplish the proposed modification to the CAPS activation system:
The manufacturer will provide warranty credit for labor and parts to the extent noted under WARRANTY INFORMATION in each previously-referenced service bulletin.
The compliance time of this proposed AD is “within 90 days after the effective date of this AD, unless already accomplished.”
Failure of the CAPS is only unsafe during airplane operation; this unsafe condition is not a result of the number of times the airplane is operated. The chance of this situation occurring is the same for an airplane with 10 hours time-in-service (TIS) as it would be for an airplane with 500 hours TIS. For this reason, the FAA has determined that a compliance based on calendar time should be utilized in this AD in order to assure that the unsafe condition is addressed on all airplanes in a reasonable time period.
The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposed rule would not have federalism implications under Executive Order 13132.
For the reasons discussed above, I certify that this proposed action (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action has been placed in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption
Air transportation, Aircraft, Aviation safety, Safety.
Accordingly, under the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations(14 CFR part 39) as follows:
1. The authority citation for part 39 continues to read as follows:
49 U.S.C. 106(g), 40113, 44701.
2. FAA amends § 39.13 by removing Airworthiness Directive (AD) 2002-05-05, Amendment 39-12673 (67 FR March 13, 2002), and by adding a new AD to read as follows:
(a)
(b)
(c)
(d)
Cirrus Service Bulletin SB 20-95-05, Issued: July 10, 2002, on page 9 of 16, includes an incorrect compliance to SB 22-95-05 in step 15. The correct compliance should be to SB 20-95-05.
Cirrus Service Bulletin SB 20-95-03, Issued: June 10, 2002, on page 2 of 2, includes an incorrect compliance to SB 22-95-03 in step 4. The correct compliance should be to SB 20-95-03.
(e)
(1) You may use an alternative method of compliance or adjust the compliance time if:
(i) Your alternative method of compliance provides an equivalent level of safety; and
(ii) The Manager, Chicago Aircraft Certification Office (ACO), approves your alternative. Submit your request through an FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, Chicago ACO.
(2) Alternative methods of compliance approved in accordance with AD 2002-05-05, which is superseded by this AD, are not approved as alternative methods of compliance with this AD.
This AD applies to each airplane identified in paragraph (a) of this AD, regardless of whether it has been modified, altered, or repaired in the area subject to the requirements of this AD. For airplanes that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (e) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if you have not eliminated the unsafe condition, specific actions you propose to address it.
(f)
(g)
(h)
(i)
Federal Aviation Administration, DOT.
Notice of proposed rulemaking (NPRM).
This document proposes to adopt a new airworthiness directive (AD) that would apply to certain Air Tractor, Inc. (Air Tractor) Models AT-250, AT-300, AT-301, AT-302, AT-400, AT-400A, AT-401, AT-401A, AT-402, AT-402A, AT-501, AT-502, and AT-502A airplanes. This proposed AD would require you to install an overturn skid plate in the cockpit area. This proposed AD is the result of reports of foreign material entering the cabin area and contributing to accidents of the affected airplanes. The actions specified by this proposed AD are intended to minimize the possibility of dirt or mud penetrating the cockpit. Such mud and dirt penetration into the cockpit could lead to pilot asphyxia or injury.
The Federal Aviation Administration (FAA) must receive any comments on this proposed rule on or before November 4, 2002.
Submit comments to FAA, Central Region, Office of the Regional Counsel, Attention: Rules Docket No. 2000-CE-60-AD, 901 Locust, Room 506, Kansas City, Missouri 64106. You may view any comments at this location between 8 a.m. and 4 p.m., Monday through Friday, except Federal holidays. You may also send comments electronically to the following address:
You may get service information that applies to this proposed AD from Air Tractor, Inc., P.O. Box 485, Olney, Texas 76374. You may also view this information at the Rules Docket at the address above.
Andrew McAnaul, Aerospace Engineer, FAA, Fort Worth Airplane Certification Office, 2601 Meacham Boulevard, Fort Worth, Texas 76193-0150; telephone: (817) 222-5156; facsimile: (817) 222-5960.
The FAA invites comments on this proposed rule. You may submit whatever written data, views, or arguments you choose. You need to include the rule's docket number and submit your comments to the address specified under the caption
The FAA specifically invites comments on the overall regulatory, economic, environmental, and energy aspects of this proposed rule that might suggest a need to modify the rule. You may view all comments we receive before and after the closing date of the rule in the Rules Docket. We will file a report in the Rules Docket that summarizes each contact we have with the public that concerns the substantive parts of this proposed AD.
If you want FAA to acknowledge the receipt of your mailed comments, you must include a self-addressed, stamped postcard. On the postcard, write “Comments to Docket No. 2000-CE-60-AD.” We will date stamp and mail the postcard back to you.
The FAA has received accident reports on Air Tractor Models AT-301 and AT-401 airplanes. The reports indicate that the aircraft skids tail first after an overturn, the windshield and curved overturn tube act as a scoop, foreign material enters the cockpit if the top of the canopy is damaged, and this foreign material then enters into the cabin area and possibly contributes to pilot deaths.
Such mud and dirt penetration into the cockpit could lead to pilot asphyxia or injury.
Air Tractor has issued Snow Engineering Company Service Letter #97, dated March 23, 1991, Revised October 3, 2000.
The service bulletin includes procedures for installing a cockpit overturn skid plate.
After examining the circumstances and reviewing all available information related to the incidents described above, we have determined that:
• The unsafe condition referenced in this document exists or could develop on other Air Tractor Models AT-250, AT-300, AT-301, AT-302, AT-400, AT-400A, AT-401, AT-401A, AT-402, AT-402A, AT-501, AT-502, and AT-502A airplanes of the same type design;
• The actions specified in the previously-referenced service information should be accomplished on the affected airplanes; and
• AD action should be taken in order to correct this unsafe condition.
This proposed AD would require you to incorporate the actions in the previously-referenced service bulletin.
We estimate that this proposed AD affects 845 airplanes in the U.S. registry.
We estimate the following costs to accomplish the proposed modification:
The compliance time of this proposed AD is within the next 180 days after the effective date of this AD.
Although an accident where the aircraft skids tail first after an overturn could occur on the affected airplanes during airplane operation, the condition is not directly related to airplane usage. The condition exists on the airplanes regardless of whether the airplane has accumulated 50 hours time-in-service (TIS) or 5,000 hours TIS.
The FAA has determined that the 180-day compliance time:
• Gives all owners/operators of the affected airplanes adequate time to schedule and accomplish the actions in this proposed AD; and
• Assures that the unsafe condition referenced in this proposed AD will be
The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposed rule would not have federalism implications under Executive Order 13132.
For the reasons discussed above, I certify that this proposed action (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action has been placed in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption
Air transportation, Aircraft, Aviation safety, Safety.
Accordingly, under the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:
1. The authority citation for part 39 continues to read as follows:
49 U.S.C. 106(g), 40113, 44701.
2. FAA amends § 39.13 by adding a new airworthiness directive (AD) to read as follows:
(a)
(b)
(c)
(d)
(e)
(1) Your alternative method of compliance provides an equivalent level of safety; and
(2) The Manager, Fort Worth Aircraft Certification Office, approves your alternative. Submit your request through an FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, Fort Worth Aircraft Certification Office.
This AD applies to each airplane identified in paragraph (a) of this AD, regardless of whether it has been modified, altered, or repaired in the area subject to the requirements of this AD. For airplanes that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (e) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if you have not eliminated the unsafe condition, specific actions you propose to address it.
(f)
(g)
(h)
Federal Aviation Administration, DOT.
Supplemental notice of proposed rulemaking; reopening of comment period.
This document revises an earlier proposed airworthiness directive (AD), applicable to certain McDonnell Douglas Model MD-11 and -11F airplanes, that would have required an inspection to detect chafed wires in the avionics equipment compartment, and repair, if necessary. That proposed AD also would have required replacement of the existing cover of the avionics cooling fan with a new cover, and
Comments must be received by September 23, 2002.
Submit comments in triplicate to the Federal Aviation Administration (FAA), Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 2001-NM-160-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056. Comments may be inspected at this location between 9 a.m. and 3 p.m., Monday through Friday, except Federal holidays. Comments may be submitted via fax to (425) 227-1232. Comments may also be sent via the Internet using the following address: 9-anm-
The service information referenced in the proposed rule may be obtained from Boeing Commercial Aircraft Group, Long Beach Division, 3855 Lakewood Boulevard, Long Beach, California 90846, Attention: Data and Service Management, Dept. C1-L5A (D800-0024). This information may be examined at the FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington; or at the FAA, Los Angeles Aircraft Certification Office, 3960 Paramount Boulevard, Lakewood, California.
Interested persons are invited to participate in the making of the proposed rule by submitting such written data, views, or arguments as they may desire. Communications shall identify the Rules Docket number and be submitted in triplicate to the address specified above. All communications received on or before the closing date for comments, specified above, will be considered before taking action on the proposed rule. The proposals contained in this action may be changed in light of the comments received.
• Organize comments issue-by-issue. For example, discuss a request to change the compliance time and a request to change the service bulletin reference as two separate issues.
• For each issue, state what specific change to the proposed AD is being requested.
• Include justification (
Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the proposed rule. All comments submitted will be available, both before and after the closing date for comments, in the Rules Docket for examination by interested persons. A report summarizing each FAA-public contact concerned with the substance of this proposal will be filed in the Rules Docket.
Commenters wishing the FAA to acknowledge receipt of their comments submitted in response to this action must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket Number 2001-NM-160-AD.” The postcard will be date stamped and returned to the commenter.
Any person may obtain a copy of this NPRM by submitting a request to the FAA, Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 2001-NM-160-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056.
A proposal to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) to add an airworthiness directive (AD), applicable to certain McDonnell Douglas Model MD-11 and -11F airplanes, was published as a notice of proposed rulemaking (NPRM) in the
Interested persons have been afforded an opportunity to participate in the making of this amendment. Due consideration has been given to the comments received.
One commenter asks whether operators that previously accomplished the actions specified in the original issue of McDonnell Douglas Service Bulletin MD11-21-033, dated May 1, 1992, which does not include an inspection of the wires in the area of the avionics cooling fans inside the avionics equipment compartment, have to do the inspection required by paragraph (a) of the NPRM. The commenter notes that Boeing Alert Service Bulletin MD11-21A033, Revision 01, dated April 30, 2001 (which is referenced in the NPRM as the appropriate source of service information), states that no more work is necessary on airplanes modified by the original issue of the service bulletin. The commenter states that the original incident was maintenance induced (
The FAA acknowledges that Boeing Alert Service Bulletin MD11-21A033, Revision 01, dated April 30, 2001, states that no more work is necessary on airplanes modified by the original issue of the service bulletin, and that the original issue of that service bulletin did not include an inspection of the subject
Note 3 of the NPRM states, “Accomplishment of the actions specified in McDonnell Douglas Service Bulletin MD11-21-033, dated May 1, 1992, before the effective date of this AD, is considered acceptable for compliance with the requirements of this AD.” Based on the commenter's question, we find that clarification of Note 3 of the NPRM is necessary. Accomplishment of the actions specified in the original version of service bulletin is acceptable for compliance with only the replacement required by paragraph (b) of this supplemental NPRM. Therefore, we have revised this language in the supplemental NPRM. In addition, since the language in Note 3 of the NPRM is regulatory in nature, that note has been redesignated as paragraph (c) of this supplemental NPRM.
Since issuance of the NPRM, we have discovered an incorrect part number listed in paragraph 3.B.3. of the Accomplishment Instructions of Boeing Alert Service Bulletin MD11-21A033, Revision 01, dated April 30, 2001, which is referenced as the appropriate source of service information for accomplishing the replacement and installation required by paragraph (b) of this supplemental NPRM. That paragraph states, “ * * * with new AXE7270-569 cover and install new AXE7270-569 placard on cover as shown on Figure 1.” However, as indicated in View C-C, Figure 1 of the service bulletin, the correct part number for the new cover is ABM7569-501, not AXE7270-569. Therefore, we have added a statement in paragraph (b) of the supplemental NPRM that “(t)he replacement must be done with part numbers that are specified in Figure 1 of the service bulletin.”
We find that Model MD-11F airplanes were not specifically identified by model name in the applicability of the NPRM. However, those airplanes were identified by manufacturer's fuselage numbers in the effectivity listing of Boeing Alert Service Bulletin MD11-21A033, Revision 01, dated April 30, 2001, which was referenced in the applicability of the NPRM. Therefore, we have revised this supplemental NPRM to specifically reference Model MD-11 and -11F airplanes where appropriate. In addition, we have specified model designations in the applicability of this supplemental NPRM as published in the most recent type certificate data sheet for the affected models.
For clarification purposes, we have revised the definition of a “general visual inspection” in Note 2 of this supplemental NPRM.
Since one of these changes expands the scope of the originally proposed rule, we have determined that it is necessary to reopen the comment period to provide additional opportunity for public comment.
There are approximately 80 Model MD-11 and -11F airplanes of the affected design in the worldwide fleet. We estimate that 33 airplanes of U.S. registry would be affected by this AD, that it would take approximately 4 work hours per airplane to accomplish the proposed actions, and that the average labor rate is $60 per work hour. Required parts would cost approximately $1,991 per airplane. Based on these figures, the cost impact of the proposed AD on U.S. operators is estimated to be $73,623, or $2,231 per airplane.
The cost impact figure discussed above is based on assumptions that no operator has yet accomplished any of the proposed requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted. The cost impact figures discussed in AD rulemaking actions represent only the time necessary to perform the specific actions actually required by the AD. These figures typically do not include incidental costs, such as the time required to gain access and close up, planning time, or time necessitated by other administrative actions.
The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposal would not have federalism implications under Executive Order 13132.
For the reasons discussed above, I certify that this proposed regulation (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action is contained in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption
Air transportation, Aircraft, Aviation safety, Safety.
Accordingly, pursuant to the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:
1. The authority citation for part 39 continues to read as follows:
49 U.S.C. 106(g), 40113, 44701.
2. Section 39.13 is amended by adding the following new airworthiness directive:
This AD applies to each airplane identified in the preceding applicability provision, regardless of whether it has been modified, altered, or repaired in the area subject to the requirements of this AD. For airplanes that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (e) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if the unsafe condition has not been eliminated, the request should include specific proposed actions to address it.
To ensure that the cover of the avionics cooling fans is removed only for fan maintenance, and to prevent smoke and/or fire in the avionics equipment compartment due to chafing and arcing as a result of maintenance personnel lying against the removed cover and/or insulation blankets that cover wire harnesses, accomplish the following:
(a) Within 18 months after the effective date of this AD, do a general visual inspection to detect chafed wires in the area of the avionics cooling fans inside the avionics equipment compartment, per Boeing Alert Service Bulletin MD11-21A033, Revision 01, dated April 30, 2001. If any chafed wiring is detected, before further flight, repair per the service bulletin.
For the purposes of this AD, a general visual inspection is defined as: “A visual examination of an interior or exterior area, installation, or assembly to detect obvious damage, failure, or irregularity. This level of inspection is made from within touching distance unless otherwise specified. A mirror may be necessary to enhance visual access to all exposed surfaces in the inspection area. This level of inspection is made under normally available lighting conditions such as daylight, hangar lighting, flashlight, or droplight and may require removal or opening of access panels or doors. Stands, ladders, or platforms may be required to gain proximity to the area being checked.”
(b) Within 18 months after the effective date of this AD, replace the existing cover of the avionics cooling fan with a new cover, and install a new placard on the cover, per Boeing Alert Service Bulletin MD11-21A033, Revision 01, dated April 30, 2001. The replacement must done with part numbers that are specified in View C-C, Figure 1, of the service bulletin.
(c) Accomplishment of the actions specified in McDonnell Douglas Service Bulletin MD11-21-033, dated May 1, 1992, before the effective date of this AD, is considered acceptable for compliance with the requirements of paragraph (b) of this AD.
(d) As of the effective date of this AD, no person shall install a cover assembly, part number ABM7569-1, on any airplane.
(e) An alternative method of compliance or adjustment of the compliance time that provides an acceptable level of safety may be used if approved by the Manager, Los Angeles Aircraft Certification Office (ACO), FAA. Operators shall submit their requests through an appropriate FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, Los Angeles ACO.
Information concerning the existence of approved alternative methods of compliance with this AD, if any, may be obtained from the Los Angeles ACO.
(f) Special flight permits may be issued in accordance with sections 21.197 and 21.199 of the Federal Aviation Regulations (14 CFR 21.197 and 21.199) to operate the airplane to a location where the requirements of this AD can be accomplished.
Federal Aviation Administration, DOT.
Notice of proposed rulemaking (NPRM).
This document proposes the supersedure of an existing airworthiness directive (AD), applicable to certain McDonnell Douglas Model MD-11 and -11F airplanes, that currently requires a one-time detailed inspection to detect discrepancies of all electrical wiring installations in various areas of the airplane; and corrective actions, if necessary. This action would require another identical inspection in additional fuselage stations, and corrective actions, if necessary. This proposal is prompted by a report from the airplane manufacturer that it failed to include 41 inches of fuselage in the previously required inspection. The actions specified by the proposed AD are intended to prevent electrical arcing and/or heat damaged wires due to improper wire installations during manufacture and/or maintenance of the airplane, and consequent fire and smoke in various areas of the airplane.
Comments must be received by October 15, 2002.
Submit comments in triplicate to the Federal Aviation Administration (FAA), Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 2001-NM-56-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056. Comments may be inspected at this location between 9 a.m. and 3 p.m., Monday through Friday, except Federal holidays. Comments may be submitted via fax to (425) 227-1232. Comments may also be sent via the Internet using the following address:
The service information referenced in the proposed rule may be obtained from Boeing Commercial Aircraft Group, Long Beach Division, 3855 Lakewood Boulevard, Long Beach, California 90846, Attention: Data and Service Management, Dept. C1-L5A (D800-0024). This information may be examined at the FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington.
Interested persons are invited to participate in the making of the proposed rule by submitting such written data, views, or arguments as they may desire. Communications shall identify the Rules Docket number and be submitted in triplicate to the address specified above. All communications received on or before the closing date for comments, specified above, will be considered before taking action on the proposed rule. The proposals contained in this action may be changed in light of the comments received.
Submit comments using the following format:
• Organize comments issue-by-issue. For example, discuss a request to change the compliance time and a request to change the service bulletin reference as two separate issues.
• For each issue, state what specific change to the proposed AD is being requested.
• Include justification (
Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the proposed rule. All comments submitted will be available, both before and after the closing date for comments, in the Rules Docket for examination by interested persons. A report summarizing each FAA-public contact concerned with the substance of this proposal will be filed in the Rules Docket.
Commenters wishing the FAA to acknowledge receipt of their comments submitted in response to this action must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket Number 2001-NM-56-AD.” The postcard will be date stamped and returned to the commenter.
Any person may obtain a copy of this NPRM by submitting a request to the FAA, Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 2001-NM-56-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056.
On November 22, 2000, the FAA issued AD 2000-24-15, amendment 39-12022 (65 FR 75620, December 4, 2000), applicable to certain McDonnell Douglas Model MD-11 airplanes, to require a one-time detailed inspection to detect discrepancies of all electrical wiring installations in various areas of the airplane, and corrective actions, if necessary. That action was prompted by incidents of damaged wire insulation and chafed wires in various areas. The requirements of that AD are intended to prevent electrical arcing and/or heat damaged wires due to improper wire installations during manufacture and/or maintenance of the airplane, and consequent fire and smoke in various areas of the airplane.
The incident that prompted AD 2000-24-15 is not considered to be related to an accident that occurred off the coast of Nova Scotia involving a McDonnell Douglas Model MD-11 airplane. The cause of that accident is still under investigation.
The FAA, in conjunction with Boeing and operators of Model MD-11 and -11F airplanes, is continuing to review all aspects of the service history of those airplanes to identify potential unsafe conditions and to take appropriate corrective actions. This proposed airworthiness directive (AD) is one of a series of actions identified during that process. The process is continuing and the FAA may consider additional rulemaking actions as further results of the review become available.
Since the issuance of AD 2000-24-15, the airplane manufacturer has informed the FAA that it failed to include 41 inches of fuselage in the inspection and corrective procedures of McDonnell Douglas Service Bulletin MD11-24-165, dated April 4, 2000, and Boeing Service Bulletin MD11-24-165, Revision 01, including Appendix, dated November 6, 2000 (which are referenced in AD 2000-24-15 as appropriate sources of service information). This additional area is subject to the identified unsafe condition of AD 2000-24-15.
The FAA has reviewed and approved Boeing Service Bulletin MD11-24-165, Revision 02, including Appendix, dated March 8, 2001. The procedures in Revision 02 of the service bulletin are essentially identical to those in the original version and Revision 01 of the service bulletin. The only relevant change is to the affected fuselage stations, which now include an additional 41 inches of fuselage to be inspected. Accomplishment of the actions specified in the service bulletin is intended to adequately address the identified unsafe condition.
Since an unsafe condition has been identified that is likely to exist or develop on other products of this same type design, the proposed AD would supersede AD 2000-24-15 to continue to require a one-time detailed inspection to detect discrepancies of all electrical wiring installations in various areas of the airplane; and corrective actions, if necessary. The proposed AD also would require another identical inspection in additional fuselage stations, and corrective actions, if necessary. These additional actions would be required to be accomplished in accordance with Boeing Service Bulletin MD11-24-165, Revision 02, including Appendix, dated March 8, 2001, described previously.
The FAA finds that Model MD-11F airplanes are not specifically identified by model in the applicability of AD 2000-24-15; however, they are identified by manufacturer's fuselage numbers. Therefore, the FAA has revised the applicability of this proposed AD to include Model MD-11F airplanes in addition to Model MD-11 airplanes, and to identify model designations as published in the most recent type certificate data sheet for the affected models.
As discussed in the preamble of notice of proposed rulemaking (NPRM) for AD 2000-24-15, the Accomplishment Instructions of the service bulletins referenced in that AD do NOT provide instructions for accomplishing corrective actions for certain discrepancies that are detected. Therefore, the FAA finds that the following corrective actions specified in paragraphs (c) and (d) of AD 2000-24-15, which have been retained and redesignated as paragraphs (d) and (e) in this proposed AD, must be accomplished, if necessary, to address the identified unsafe condition of the proposed AD:
• If no gap between the wire bundle and blanket can be seen when pressure is applied to the blanket, before further flight, reposition wires or clamping so that a gap can been seen when pressure is applied to the blanket.
• If any screw terminal of the flag lug bus bar is loose, before further flight, retorque to 10 to 11 inch-pounds.
Operators should note that Boeing Service Bulletin MD11-24-165, Revision 02, including Appendix, dated March 8, 2001 (described previously), does contain these corrective actions.
The FAA has changed all references to a “detailed visual inspection” in the existing AD to “detailed inspection” in this proposed AD.
There are approximately 182 Model MD-11 and -11F airplanes of the affected design in the worldwide fleet. The FAA estimates that 60 airplanes of U.S. registry would be affected by this proposed AD.
Each of the six inspections required by paragraphs (a)(1) through (a)(6) of this proposed AD, which are currently required by AD 2000-24-15, approximately 10 work hours per airplane to accomplish, at an average labor rate of $60 per work hour. Based on these figures, the cost impact of these currently required actions on U.S. operators is estimated to be $216,000, or $3,600 per airplane.
The inspection required by paragraph (a)(7) of this proposed AD, which is currently required by AD 2000-24-15, takes approximately 5 work hours per airplane to accomplish, at an average labor rate of $60 per work hour. Based on these figures, the cost impact of this currently required action on U.S. operators is estimated to be $18,000, or $300 per airplane.
The inspection required by paragraph (a)(8) of this proposed AD, which is currently required by AD 2000-24-15, takes approximately 12 work hours per airplane to accomplish, at an average labor rate of $60 per work hour. Based on these figures, the cost impact of this currently required action on U.S. operators is estimated to be $43,200, or $720 per airplane.
The new inspection required by paragraph (b) of this proposed AD would take approximately 1 work hour per airplane to accomplish, at an average labor rate of $60 per work hour. Based on these figures, the cost impact of this proposed inspection of this AD on U.S. operators is estimated to be $3,600, or $60 per airplane.
The cost impact figures discussed above are based on assumptions that no operator has yet accomplished any of the current or proposed requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted. The cost impact figures discussed in AD rulemaking actions represent only the time necessary to perform the specific actions actually required by the AD. These figures typically do not include incidental costs, such as the time required to gain access and close up, planning time, or time necessitated by other administrative actions. However, the FAA has been advised that manufacturer warranty remedies are available for labor costs associated with accomplishing the actions required by this proposed AD. Therefore, the future economic cost impact of this rule on U.S. operators may be less than the cost impact figure indicated above.
The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposal would not have federalism implications under Executive Order 13132.
For the reasons discussed above, I certify that this proposed regulation (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action is contained in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption
Air transportation, Aircraft, Aviation safety, Safety.
Accordingly, pursuant to the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:
1. The authority citation for part 39 continues to read as follows:
49 U.S.C. 106(g), 40113, 44701.
2. Section 39.13 is amended by removing amendment 39-12022 (65 FR 75620, December 4, 2000), and by adding a new airworthiness directive (AD), to read as follows:
This AD applies to each airplane identified in the preceding applicability provision, regardless of whether it has been modified, altered, or repaired in the area subject to the requirements of this AD. For airplanes that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (f)(1) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if the unsafe condition has not been eliminated, the request should include specific proposed actions to address it.
The FAA recommends that the actions required by this AD be accomplished immediately after accomplishing the replacement of metallized polyethyleneteraphthalate (MPET) insulation blankets, as required by AD 2000-11-02, amendment 39-11750 (65 FR 34341, May 26, 2000).
To prevent electrical arcing and/or heat damaged wires due to improper wire installations during manufacture and/or maintenance of the airplane, and consequent fire and smoke in various areas of the airplane, accomplish the following:
(a) Within 5 years after January 8, 2001 (the effective date of AD 2000-24-15, amendment 39-12022), accomplish the actions specified in paragraphs (a)(1), (a)(2), (a)(3), (a)(4), (a)(5), (a)(6), (a)(7), and (a)(8) of this AD, as applicable.
(1) For all airplanes: Perform a one-time detailed inspection to detect discrepancies of all electrical wiring installations in the center and aft cargo compartments from stations Y=1521.000 to Y=2007.000, in accordance with paragraph 3.B., “Work Instructions,” of the Accomplishment Instructions of McDonnell Douglas Service Bulletin MD11-24-171, dated April 4, 2000; or Revision 01, dated November 6, 2000.
For the purposes of this AD, a detailed inspection is defined as: “An intensive visual examination of a specific structural area, system, installation, or assembly to detect damage, failure, or irregularity. Available lighting is normally supplemented with a direct source of good lighting at intensity deemed appropriate by the inspector. Inspection aids such as mirror, magnifying lenses, etc. may be used. Surface cleaning and elaborate access procedures may be required.”
(2) For all airplanes: Perform a one-time detailed inspection to detect discrepancies of all electrical wiring installations in the forward cargo compartment from stations Y=595.000 to Y=6-73.500, in accordance with the paragraph 3.B., “Work Instructions,” of the Accomplishment Instructions of McDonnell Douglas Service Bulletin MD11-24-170, dated April 12, 2000; or Revision 01, dated November 6, 2000.
(3) For all airplanes: Perform a one-time detailed inspection to detect discrepancies of all electrical wiring installations in the forward passenger compartment from stations Y=5-11.000 to Y=2007.000, in accordance with the paragraph 3.B., “Work Instructions,” of the Accomplishment Instructions of McDonnell Douglas Service Bulletin MD11-24-167, dated April 4, 2000; or Boeing Service Bulletin MD11-24-167, Revision 01, including Appendix 1, dated November 6, 2000.
(4) For all airplanes: Perform a one-time detailed inspection to detect discrepancies of all electrical wiring installations in the forward passenger compartment from stations Y=756.000 to Y=1501.000, in accordance with the paragraph 3.B., “Work Instructions,” of the Accomplishment Instructions of McDonnell Douglas Service Bulletin MD11-24-165, dated April 4, 2000;
(5) For all airplanes: Perform a one-time detailed inspection to detect discrepancies of all electrical wiring installations in the forward passenger compartment from stations Y=465.000 to Y=755.000, in accordance with the paragraph 3.B., “Work Instructions,” of the Accomplishment Instructions of McDonnell Douglas Service Bulletin MD11-24-163, dated April 4, 2000; or Boeing Service Bulletin MD11-24-163, Revision 01, including Appendix 1, dated November 6, 2000.
(6) For all airplanes: Perform a one-time detailed inspection to detect discrepancies of all electrical wiring installations in the flight compartment and forward drop ceilings areas from stations Y=275.000 to Y=464.000, in accordance with the paragraph 3.B., “Work Instructions,” of the Accomplishment Instructions of McDonnell Douglas Service Bulletin MD11-24-188, dated April 28, 2000; or Revision 01, dated November 6, 2000.
(7) For airplanes having manufacturer's fuselage numbers 0447 through 0449 inclusive, 0451 through 0464 inclusive, 0466 through 0489 inclusive, 0491 through 0517 inclusive, 0519 through 0552 inclusive, 0554 through 0556 inclusive, 0557, and 0558 through 0633 inclusive: Perform a one-time detailed inspection to detect discrepancies of all electrical wiring installations in the center accessory compartment from stations Y=6-50.000 to Y=1179.000, in accordance with the paragraph 3.B., “Work Instructions,” of the Accomplishment Instructions of McDonnell Douglas Service Bulletin MD11-24-161, dated April 10, 2000; or Revision 01, dated November 6, 2000.
(8) For airplanes having manufacturer's fuselage numbers 0447 through 0449 inclusive, 0451 through 0464 inclusive, 0466 through 0489 inclusive, 0491 through 0517 inclusive, 0519 through 0552 inclusive, 0554 through 0556 inclusive, 0557, and 0558 through 0633 inclusive: Perform a one-time detailed inspection to detect discrepancies of all electrical wiring installations in the main avionics compartment from stations Y=275.000 to Y=464.000, in accordance with the paragraph 3.B., “Work Instructions,” of the Accomplishment Instructions of McDonnell Douglas Service Bulletin MD11-24-162, dated April 10, 2000; or Revision 01, dated November 6, 2000.
(b) For Group 2 airplanes identified in Boeing Service Bulletin MD11-24-165, Revision 02, including Appendix, dated March 8, 2001: Within 5 years after the effective date of this AD, perform a one-time detailed inspection to detect discrepancies of all electrical wiring installations in the forward passenger compartment from stations Y=1501.000 to Y=5-10.000, in accordance with the paragraph 3.B., “Work Instructions,” “Group 2,” of the Accomplishment Instructions of Boeing Service Bulletin MD11-24-165, Revision 02, dated March 8, 2001.
(c) If any discrepancy is detected during the inspection required by paragraphs (a)(1) through (a)(8) of this AD or paragraph (b) of this AD, before further flight, accomplish the applicable corrective action(s) in accordance with the Accomplishment Instructions of the following applicable service bulletins, except as provided in paragraphs (d) and (e) of this AD, as applicable:
(1) McDonnell Douglas Service Bulletin MD11-24-171, dated April 4, 2000; or Revision 01, dated November 6, 2000;
(2) McDonnell Douglas Service Bulletin MD11-24-170, dated April 12, 2000; or Revision 01, dated November 6, 2000;
(3) McDonnell Douglas Service Bulletin MD11-24-167, dated April 4, 2000;
(4) Boeing Service Bulletin MD11-24-167, dated April 4, 2000, Revision 01, including Appendix, dated November 6, 2000;
(5) McDonnell Douglas Service Bulletin MD11-24-165, dated April 4, 2000;
(6) Boeing Service Bulletin MD11-24-165, Revision 01, including Appendix, dated November 6, 2000;
(7) McDonnell Douglas Service Bulletin MD11-24-163, dated April 4, 2000;
(8) Boeing Service Bulletin MD11-24-163, Revision 01, including Appendix 1, dated November 6, 2000;
(9) McDonnell Douglas Service Bulletin MD11-24-188, dated April 28, 2000; or Revision 01, dated November 6, 2000;
(10) McDonnell Douglas Service Bulletin MD11-24-161, dated April 10, 2000; or Revision 01, dated November 6, 2000; or
(11) McDonnell Douglas Service Bulletin MD11-24-162, dated April 10, 2000; or Revision 01, dated November 6, 2000.
(12) Boeing Service Bulletin MD11-24-165, Revision 02, including Appendix, dated March 8, 2001.
Where there are differences between the AD and the referenced service bulletins, the AD prevails.
(d) If no gap between the wire bundle and blanket can be seen where the wiring is routed over the structural frames when pressure is applied to the blanket, before further flight, reposition wires or clamps so that a gap can be seen when pressure is applied to the blanket.
(e) If any screw terminal of the flag lug bus bar is loose, before further flight, retorque to 10 to 11 inch-pounds.
(f)(1) An alternative method of compliance or adjustment of the compliance time that provides an acceptable level of safety may be used if approved by the Manager, Los Angeles Aircraft Certification Office (ACO), FAA. Operators shall submit their requests through an appropriate FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, Los Angeles ACO.
Information concerning the existence of approved alternative methods of compliance with this AD, if any, may be obtained from the Los Angeles ACO.
(2) Alternative methods of compliance, approved previously in accordance with AD 2000-24-15, amendment 39-12022, are approved as alternative methods of compliance with this AD.
(g) Special flight permits may be issued in accordance with sections 21.197 and 21.199 of the Federal Aviation Regulations (14 CFR 21.197 and 21.199) to operate the airplane to a location where the requirements of this AD can be accomplished.
Federal Aviation Administration, DOT.
Notice of proposed rulemaking (NPRM).
This document proposes the supersedure of an existing airworthiness directive (AD), applicable to certain McDonnell Douglas Model MD-11 airplanes, that currently requires, among other actions, a one-time inspection to detect discrepancies at certain areas around the entry light connector of the sliding ceiling panel above the forward passenger doors; repair, if necessary; and installation or modification of a flapper door ramp deflector on the forward entry drop ceiling structure. That AD also currently requires an inspection of the wire assembly support installation above the entry door (L1) sliding panel for chafing, and repair, if necessary. This action also would continue to require the existing requirements and require replacing the wire support bracket with new support clip assemblies. This action is necessary to prevent chafing of electrical wire assemblies above the forward passenger doors and above the entry door (L1) sliding panel of the forward drop ceiling on the passenger compartment, which could result in electrical arcing, and consequent electrical fire in the passenger compartment. This action is intended to address the identified unsafe condition.
Comments must be received by October 15, 2002.
Submit comments in triplicate to the Federal Aviation Administration (FAA), Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 2001-NM-62-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056. Comments may be inspected at this location between 9 a.m. and 3 p.m., Monday through Friday, except Federal holidays. Comments may be submitted via fax to (425) 227-1232. Comments may also be sent via the Internet using the following address:
The service information referenced in the proposed rule may be obtained from Boeing Commercial Aircraft Group, Long Beach Division, 3855 Lakewood Boulevard, Long Beach, California 90846, Attention: Data and Service Management, Dept. C1-L5A (D800-0024). This information may be examined at the FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington.
Interested persons are invited to participate in the making of the proposed rule by submitting such written data, views, or arguments as they may desire. Communications shall identify the Rules Docket number and be submitted in triplicate to the address specified above. All communications received on or before the closing date for comments, specified above, will be considered before taking action on the proposed rule. The proposals contained in this action may be changed in light of the comments received.
Submit comments using the following format:
• Organize comments issue-by-issue. For example, discuss a request to change the compliance time and a request to change the service bulletin reference as two separate issues.
• For each issue, state what specific change to the proposed AD is being requested.
• Include justification (
Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the proposed rule. All comments submitted will be available, both before and after the closing date for comments, in the Rules Docket for examination by interested persons. A report summarizing each FAA-public contact concerned with the substance of this proposal will be filed in the Rules Docket.
Commenters wishing the FAA to acknowledge receipt of their comments submitted in response to this action must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket Number 2001-NM-62-AD.” The postcard will be date stamped and returned to the commenter.
Any person may obtain a copy of this NPRM by submitting a request to the FAA, Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 2001-NM-62-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056.
On November 22, 2000, the FAA issued airworthiness directive (AD) 2000-24-11, amendment 39-12018 (65 FR 75612, December 4, 2000), applicable to certain McDonnell Douglas Model MD-11 airplanes, to require a one-time inspection to detect discrepancies at certain areas around the entry light connector of the sliding ceiling panel above the forward passenger doors, and repair, if necessary. For certain airplanes, that AD also requires installation or modification of a flapper door ramp deflector on the forward entry drop ceiling structure. For certain other airplanes, that AD requires inspection of the wire assembly support installation for evidence of chafing, and corrective actions, if necessary. For certain airplanes, that AD also requires modification of a support bracket for the ramp deflector assembly. That action was prompted by the FAA's determination that further rulemaking action was necessary to address the identified unsafe condition. The requirements of that AD are intended to prevent chafing of electrical wire assemblies above the forward passenger doors, which could result in an electrical fire in the passenger compartment.
The incidents that prompted AD 2000-24-11 are not considered to be related to an accident that occurred off the coast of Nova Scotia involving a McDonnell Douglas Model MD-11 airplane. The cause of that accident is still under investigation.
The FAA, in conjunction with Boeing and operators of Model MD-11 and -11F airplanes, is continuing to review all aspects of the service history of those airplanes to identify potential unsafe conditions and to take appropriate corrective actions. This proposed AD is one of a series of actions identified during that process. The process is continuing and the FAA may consider additional rulemaking actions as further results of the review become available.
In the preamble of the notice of proposed rulemaking (NPRM) for AD 2000-03-10, amendment 39-11569 (64 FR 57811, October 27, 1999), which was superseded by AD 2000-24-11, the FAA indicated that the airplane manufacturer had advised us that modifying the wire assembly support installation above the entry door (L1) sliding panel in accordance with McDonnell Douglas Alert Service Bulletin MD11-24A068, Revision 01, dated March 8, 1999, may cause further damage of the wire assembly due to the possibility of the wire assembly chafing on adjacent brackets. The manufacturer also advised that it was planning to revise the service bulletin to alleviate the potential chafing problem.
As a result of this information, the FAA did NOT include the subject modification in the requirements of AD 2000-03-10.
Since the issuance of AD 2000-24-11, the FAA has received reports of chafing damage to the electrical wire bundle (wire assembly ABS9202) located above the entry door (L1) sliding panel of the forward drop ceiling of the passenger compartment. These incidents occurred on McDonnell Douglas Model MD-11 and MD-11F airplanes on which the
Chafing of electrical wire assemblies above the forward passenger doors (as identified in AD 2000-24-11) and above the entry door (L1) sliding panel of the forward drop ceiling on the passenger compartment, if not corrected, could result in electrical arcing, and consequent electrical fire in the passenger compartment.
The FAA has reviewed and approved Boeing Alert Service Bulletin MD11-24A068, Revision 02, dated May 16, 2001. The service bulletin describes procedures for a general visual inspection of the wire assembly support installation above the entry door (L1) sliding panel for chafing per the service bulletin; and repair, if necessary. The service bulletin also describes procedures for replacing the wire support bracket with new support clip assemblies and ensuring adequate clearance exists for all parts of the wire assembly, including breakouts to module blocks and grounds. In addition, the effectivity listing of Revision 02 of the service bulletin removes certain airplanes and adds others, which are subject to the identified unsafe condition.
Accomplishment of the actions specified in Revision 02 of service bulletin is intended to adequately address chafing of electrical wire assemblies above the entry door (L1) sliding panel of the forward drop ceiling on the passenger compartment, which could result in electrical arcing, and consequent electrical fire in the passenger compartment.
Since an unsafe condition has been identified that is likely to exist or develop on other products of this same type design, the proposed AD would supersede AD 2000-24-11 to continue to require, among other actions, a one-time inspection to detect discrepancies at certain areas around the entry light connector of the sliding ceiling panel above the forward passenger doors; repair, if necessary; and installation or modification of a flapper door ramp deflector on the forward entry drop ceiling structure. The proposed AD also would require accomplishment of the actions specified in Boeing Alert Service Bulletin MD11-24A068, Revision 02, dated May 16, 2001, described previously.
The applicability of this proposed AD references Boeing Alert Service Bulletin MD11-24A068, Revision 02, dated May 16, 2001, as one of the appropriate sources of service information for determining the affected Model MD-11 and -11F airplanes, rather than McDonnell Douglas Alert Service Bulletin MD11-24A068, Revision 01, dated March 8, 1999, as referenced in the applicability of AD 2000-24-11. As indicated above, Revision 02 includes additional airplanes that are subject to the requirements of this AD. Also, the applicability of this AD excludes airplanes listed in Boeing Alert Service Bulletin MD11-24A068, Revision 02, dated May 16, 2001, that have been modified from a passenger to a freighter configuration and have had the entry door (L1) sliding panel described in the service bulletin removed. In addition, we have revised the applicability of the existing AD to identify model designations as published in the most recent type certificate data sheet for the affected models.
There are approximately 110 airplanes of the affected design in the worldwide fleet that are affected by the actions currently required by AD 2000-24-11 and retained in this proposed AD. Of these 110 airplanes, the FAA estimates that 21 airplanes of U.S. registry would be affected by proposed AD.
The inspection to detect discrepancies around the entry light connector of the slide ceiling panel above the forward passenger doors takes approximately 2 work hours per airplane to accomplish, at an average labor rate of $60 per work hour. Based on these figures, the cost impact of this currently required inspection on U.S. operators is estimated to be $2,520, or $120 per airplane.
For Group 1 airplanes as specified in McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 06 (approximately 16 airplanes of U.S. registry), the installation of the flapper door ramp deflector takes approximately 8 work hours per airplane to accomplish, at an average labor rate of $60 per work hour. Required parts cost approximately $455 per airplane. Based on these figures, the cost impact of this currently required installation on U.S. operators of Group 1 airplanes is estimated to be $14,960, or $935 per airplane.
For Group 2 airplanes as specified in McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 06 (approximately 8 airplanes of U.S. registry), the installation of the flapper door ramp deflector takes approximately 8 work hours per airplane to accomplish, at an average labor rate of $60 per work hour. Required parts cost approximately $890 per airplane. Based on these figures, the cost impact of this currently required installation on U.S. operators of Group 2 airplanes is estimated to be $10,960, or $1,370 per airplane.
For airplanes listed in McDonnell Douglas Alert Service Bulletin MD11-24A068, Revision 01, dated March 8, 1999 (approximately 21 airplanes of U.S. registry), the inspection of the wire assembly support installation takes approximately 1 work hour per airplane to accomplish, at an average labor rate of $60 per work hour. Based on these figures, the cost impact of this currently required inspection on U.S. operators is estimated to be $1,260, or $60 per airplane.
For airplanes in Groups 1 and 3 as specified in McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 06 (approximately 18 airplanes of U.S. registry), the modification takes approximately 2 work hours per airplane to accomplish, at an average labor rate of $60 per work hour. Based on these figures, the cost impact of this currently required modification on U.S. operators is estimated to be $2,160, or $120 per airplane.
There are approximately 195 Model MD-11 and -11F airplanes of the affected design in the worldwide fleet that are affected by the actions required by this proposed AD. Of these 195 airplanes, the FAA estimates that 64 airplanes of U.S. registry would be affected by this proposed AD.
The new actions that are proposed in this AD action would take approximately 3 work hours per airplane to accomplish, at an average labor rate of $60 per work hour. Required parts would cost approximately $294 per airplane. Based on these figures, the cost impact of the newly proposed requirements of this AD on U.S. operators is estimated to be $30,336, or $474 per airplane.
The cost impact figures discussed above are based on assumptions that no operator has yet accomplished any of the current or proposed requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted. The cost impact figures discussed in AD rulemaking actions represent only the time necessary to perform the specific actions actually required by the AD. These figures typically do not include incidental costs, such as the time required to gain access and close up, planning time, or time necessitated by other administrative actions.
The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposal would not have federalism implications under Executive Order 13132.
For the reasons discussed above, I certify that this proposed regulation (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action is contained in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption
Air transportation, Aircraft, Aviation safety, Safety.
Accordingly, pursuant to the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:
1. The authority citation for part 39 continues to read as follows:
49 U.S.C. 106(g), 40113, 44701.
2. Section 39.13 is amended by removing amendment 39-12018 (65 FR 75612, December 4, 2000), and by adding a new airworthiness directive (AD), to read as follows:
This AD applies to each airplane identified in the preceding applicability provision, regardless of whether it has been modified, altered, or repaired in the area subject to the requirements of this AD. For airplanes that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (g) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if the unsafe condition has not been eliminated, the request should include specific proposed actions to address it.
To prevent chafing of electrical wire assemblies above the forward passenger doors and above the entry door (L1) sliding panel of the forward drop ceiling on the passenger compartment, which could result in electrical arcing, and consequent electrical fire in the passenger compartment, accomplish the following:
(a) For airplanes listed in McDonnell Douglas Alert Service Bulletins MD11-25A194, Revision 05, dated June 21, 1999; and MD11-24A068, Revision 01, dated March 8, 1999: Within 10 days after December 28, 1998 (the effective date of AD 98-25-11 R1, amendment 39-10988), perform a detailed visual inspection of the aircraft wiring to detect discrepancies that include but are not limited to frayed, chafed, or nicked wires and wire insulation in the areas specified in paragraphs (a)(1) and (a)(2) of this AD.
For the purposes of this AD, a detailed visual inspection is defined as: “An intensive visual examination of a specific structural area, system, installation, or assembly to detect damage, failure, or irregularity. Available lighting is normally supplemented with a direct source of good lighting at intensity deemed appropriate by the inspector. Inspection aids such as mirror, magnifying lenses, etc., may be used. Surface cleaning and elaborate access procedures may be required.”
(1) At the area of the forward drop ceiling just outboard of mod block S3-735, and forward and inboard of the light ballast for the entry light on the sliding ceiling panel above the forward left passenger door (1L) at station location x = 24.75, y = 435, and z = 64.5.
(2) At the area above the forward right passenger door (1R) at station location x = -30, y = 430, and z = 70 in the ramp deflector assembly part number 4223570-501.
(b) If any discrepancy is detected during the visual inspection required by paragraph (a) of this AD, prior to further flight, repair in accordance with Chapter 20, Standard Wiring Practices of the MD-11 Wiring Diagram Manual, dated January 1, 1998, or April 1, 1998.
(c) For airplanes listed in McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 05, dated June 21, 1999; or MD11-24A068, Revision 01, dated March 8, 1999: Within 6 months after March 23, 2000 (the effective date of AD 2000-03-10, amendment 39-11569), accomplish the actions specified in paragraphs (c)(1), (c)(2), (c)(3), and (c)(4) of this AD, as applicable.
(1) For Group 1 airplanes listed in McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 05, dated June 21,
(2) For Group 2 airplanes listed in McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 05, dated June 21, 1999: Install a ramp deflector assembly on the right side forward entry drop ceiling structure in accordance with McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 05, dated June 21, 1999; or McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 06, dated January 27, 2000. After the effective date of this AD, only Revision 06 of the alert service bulletin shall be used.
Installation of a ramp deflector assembly in accordance with McDonnell Douglas Service Bulletin MD11-25-194, dated March 15, 1996; Revision 01, dated May 1, 1996; Revision 02, dated July 12, 1996; Revision 03, dated December 12, 1996; or Revision 04, dated March 8, 1999, is acceptable for compliance with the requirements of paragraph (c)(2) of this AD.
(3) For Group 3 airplanes listed in McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 05, dated June 21, 1999: Modify the previously installed ramp deflector assembly bracket in accordance with McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 05, dated June 21, 1999; or McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 06, dated January 27, 2000. After the effective date of this AD, only Revision 06 of the alert service bulletin shall be used.
(4) For airplanes listed in McDonnell Douglas Alert Service Bulletin MD11-24A068, Revision 01, dated March 8, 1999: Perform a general visual inspection of the wire assembly support installation for evidence of chafing, in accordance with the service bulletin. If any chafing is detected, prior to further flight, repair or replace any discrepant part with a new part in accordance with the service bulletin.
For the purposes of this AD, a general visual inspection is defined as “A visual examination of an interior or exterior area, installation, or assembly to detect obvious damage, failure, or irregularity. This level of inspection is made under normally available lighting conditions such as daylight, hangar lighting, flashlight, or drop-light, and may require removal or opening of access panels or doors. Stands, ladders, or platforms may be required to gain proximity to the area being checked.”
(d) For airplanes other than those identified in paragraph (a) of this AD: Within 10 days after January 8, 2001 (the effective date of AD 2000-24-11, amendment 39-12018), perform a detailed visual inspection of the aircraft wiring to detect discrepancies that include but are not limited to frayed, chafed, or nicked wires and wire insulation in the areas specified in paragraphs (a)(1) and (a)(2) of this AD. If any discrepancy is found, prior to further flight, repair in accordance with the requirements of paragraph (b) of this AD.
Accomplishment of the inspection required by paragraph (a) of AD 98-25-11 R1, amendment 39-10988, prior to the effective date of this AD, is acceptable for compliance with paragraph (d) of this AD.
(e) For airplanes listed in Group 3 of McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 06, dated January 27, 2000: Within 6 months after January 8, 2001, modify the ramp deflector assembly support bracket on the right side forward entry door drop ceiling structure, in accordance with McDonnell Douglas Alert Service Bulletin MD11-25A194, Revision 06, dated January 27, 2000.
(f) For airplanes listed in Groups 1 and 2 in Boeing Alert Service Bulletin MD11-24A068, Revision 02, dated May 16, 2001: Within 6 months after the effective date of this AD, do the actions specified in paragraphs (f)(1) and (f)(2) of this AD.
(1) Do a general visual inspection of the wire assembly support installation above the entry door (L1) sliding panel of the forward drop ceiling of the passenger compartment for chafing per the service bulletin. If any chafing is found, before further flight, repair per the service bulletin.
(2) Replace the wire support bracket with new support clip assemblies and ensure adequate clearance exists for all parts of the wire assembly, including breakouts to module blacks and grounds, per the service bulletin.
(g) An alternative method of compliance or adjustment of the compliance time that provides an acceptable level of safety may be used if approved by the Manager, Los Angeles Aircraft Certification Office (ACO), FAA. Operators shall submit their requests through an appropriate FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, Los Angeles ACO.
Information concerning the existence of approved alternative methods of compliance with this AD, if any, may be obtained from the Los Angeles ACO.
(h) Special flight permits may be issued in accordance with sections 21.197 and 21.199 of the Federal Aviation Regulations (14 CFR 21.197 and 21.199) to operate the airplane to a location where the requirements of this AD can be accomplished.
Federal Aviation Administration, DOT.
Notice of proposed rulemaking (NPRM).
This document proposes the adoption of a new airworthiness directive (AD) that is applicable to certain McDonnell Douglas Model MD-11 and -11F airplanes. This proposal would require an inspection to detect damage of the wiring/bundles routed to the wire support bar of the circuit breaker panel and to the circuit breakers, and an inspection of the wiring/bundles for correct routing. This proposal also would require installation of protective sleeving, spacers, and sta-straps; and corrective/follow-on actions, if necessary. This action is necessary to prevent chafing and consequent arcing or loss of electrical power to associated avionics buses in the upper avionics circuit breaker panel of the main observer's station, which could result in smoke and/or fire in the cockpit. This action is intended to address the identified unsafe condition.
Comments must be received by October 15, 2002.
Submit comments in triplicate to the Federal Aviation Administration (FAA), Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 2001-NM-166-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056. Comments may be inspected at this location between 9 a.m. and 3 p.m., Monday through Friday, except Federal holidays. Comments may be submitted via fax to (425) 227-1232. Comments may also be sent via the Internet using the following address:
The service information referenced in the proposed rule may be obtained from Boeing Commercial Aircraft Group, Long Beach Division, 3855 Lakewood Boulevard, Long Beach, California 90846, Attention: Data and Service Management, Dept. C1-L5A (D800-0024). This information may be examined at the FAA, Transport Airplane Directorate, 1601 Lind Avenue, SW., Renton, Washington; or at the FAA, Los Angeles Aircraft Certification Office, 3960 Paramount Boulevard, Lakewood, California.
Interested persons are invited to participate in the making of the proposed rule by submitting such written data, views, or arguments as they may desire. Communications shall identify the Rules Docket number and be submitted in triplicate to the address specified above. All communications received on or before the closing date for comments, specified above, will be considered before taking action on the proposed rule. The proposals contained in this action may be changed in light of the comments received.
Submit comments using the following format:
• Organize comments issue-by-issue. For example, discuss a request to change the compliance time and a request to change the service bulletin reference as two separate issues.
• For each issue, state what specific change to the proposed AD is being requested.
• Include justification (
Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the proposed rule. All comments submitted will be available, both before and after the closing date for comments, in the Rules Docket for examination by interested persons. A report summarizing each FAA-public contact concerned with the substance of this proposal will be filed in the Rules Docket.
Commenters wishing the FAA to acknowledge receipt of their comments submitted in response to this action must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket Number 2001-NM-166-AD.” The postcard will be date stamped and returned to the commenter.
Any person may obtain a copy of this NPRM by submitting a request to the FAA, Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 2001-NM-166-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056.
As part of its practice of re-examining all aspects of the service experience of a particular aircraft whenever an accident occurs, the FAA has become aware of an incident of loss of 28-volt alternating current (VAC) instrument electrical power on a McDonnell Douglas Model MD-11 airplane. Investigation revealed a wire pulled out at the upper avionics circuit breaker panel of the main observer's station. Boeing conducted inspections on six airplanes that revealed improper wire routing, insufficient chafe protection, and strained wires on the upper avionics circuit breaker panel area on five of the inspected airplanes. These conditions, if not corrected, could result in arcing or loss of electrical power to associated avionics buses in the upper avionics circuit breaker panel, which could result in smoke and/or fire in the cockpit.
The upper avionics circuit breaker panel of the main observer's station on certain MD-11F airplanes are identical to those on the affected MD-11 airplanes. Therefore, both of these models may be subject to the same unsafe condition.
This incident is not considered to be related to an accident that occurred off the coast of Nova Scotia involving a McDonnell Douglas Model MD-11 airplane. The cause of that accident is still under investigation.
We, along with Boeing and operators of Model MD-11 and -11F airplanes, is continuing to review all aspects of the service history of those airplanes to identify potential unsafe conditions and to take appropriate corrective actions. This proposed airworthiness directive (AD) is one of a series of actions identified during that process. The process is continuing and we may consider additional rulemaking actions as further results of the review become available.
We have reviewed and approved Boeing Alert Service Bulletin MD11-24A179, Revision 02, dated December 19, 2001, which describes the following procedures:
1. Doing a detailed inspection to detect damage of the wiring/bundles routed to the wire support bar of the circuit breaker panel and to the circuit breakers;
2. Doing a general visual inspection of the wiring/bundles for correct routing and making sure that ABS9108 (16-gauge power feeders) routing provides adequate stress relief from the support bar to bus termination points;
3. Installing protective sleeving, spacers, and sta-straps;
4. Repairing or replacing any damaged wiring/bundle with new wiring;
5. Replacing the wire clamp located on the support bar of the circuit breaker panel with a new clamp, if necessary; and
6. Modifying the wire routing, if necessary.
Accomplishment of the actions specified in the service bulletin is intended to adequately address the identified unsafe condition.
Since an unsafe condition has been identified that is likely to exist or develop on other products of this same type design, the proposed AD would require accomplishment of the actions specified in the service bulletin described previously.
We have specified model designations in the applicability of this proposed AD as published in the most recent type certificate data sheet for the affected models. These model designations differ in the referenced service bulletin.
There are approximately 195 Model MD-11 and -11F airplanes of the
The cost impact figure discussed above is based on assumptions that no operator has yet accomplished any of the proposed requirements of this AD action, and that no operator would accomplish those actions in the future if this proposed AD were not adopted. The cost impact figures discussed in AD rulemaking actions represent only the time necessary to perform the specific actions actually required by the AD. These figures typically do not include incidental costs, such as the time required to gain access and close up, planning time, or time necessitated by other administrative actions.
The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposal would not have federalism implications under Executive Order 13132.
For the reasons discussed above, I certify that this proposed regulation (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action is contained in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption
Air transportation, Aircraft, Aviation safety, Safety.
Accordingly, pursuant to the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:
1. The authority citation for part 39 continues to read as follows:
49 U.S.C. 106(g), 40113, 44701.
2. Section 39.13 is amended by adding the following new airworthiness directive:
This AD applies to each airplane identified in the preceding applicability provision, regardless of whether it has been modified, altered, or repaired in the area subject to the requirements of this AD. For airplanes that have been modified, altered, or repaired so that the performance of the requirements of this AD is affected, the owner/operator must request approval for an alternative method of compliance in accordance with paragraph (c) of this AD. The request should include an assessment of the effect of the modification, alteration, or repair on the unsafe condition addressed by this AD; and, if the unsafe condition has not been eliminated, the request should include specific proposed actions to address it.
To prevent chafing and consequent arcing or loss of electrical power to associated avionics buses in the upper avionics circuit breaker panel, which could result in smoke and/or fire in the cockpit, accomplish the following:
(a) Within 6 months after the effective date of this AD, do the actions specified in paragraphs (a)(1) through (a)(3) of this AD, per Boeing Alert Service Bulletin MD11-24A179, Revision 02, dated December 19, 2001.
(1) Do a detailed inspection to detect damage of the wiring/bundles routed to the wire support bar of the circuit breaker panel and to the circuit breakers.
For the purposes of this AD, a detailed inspection is defined as: “An intensive visual examination of a specific structural area, system, installation, or assembly to detect damage, failure, or irregularity. Available lighting is normally supplemented with a direct source of good lighting at intensity deemed appropriate by the inspector. Inspection aids such as mirror, magnifying lenses, etc., may be used. Surface cleaning and elaborate access procedures may be required.”
(2) Do a general visual inspection of the wiring/bundles for correct routing. Make sure ABS9108 (16-gauge power feeders) routing provides adequate stress relief from the support bar to bus termination points.
For the purposes of this AD, a general visual inspection is defined as: “A visual examination of an interior or exterior area, installation, or assembly to detect obvious damage, failure, or irregularity. This level of inspection is made from within touching distance unless otherwise specified. A mirror may be necessary to enhance visual access to all exposed surfaces in the inspection area. This level of inspection is made under normally available lighting conditions such as daylight, hangar lighting, flashlight, or droplight and may require removal or opening of access panels or doors. Stands, ladders, or platforms may be required to gain proximity to the area being checked.”
(3) Install protective sleeving, spacers, and sta-straps.
(b) Before further flight after doing the inspections required by paragraphs (a)(1) and (a)(2) of this AD, do the applicable corrective/follow-on action(s) specified in “Table-Corrective/Follow-On Actions” of this AD per Boeing Alert Service Bulletin MD11-24A179, Revision 02, dated December 19, 2001. Table—Corrective/Follow-On Actions is as follows:
(c) An alternative method of compliance or adjustment of the compliance time that provides an acceptable level of safety may be used if approved by the Manager, Los Angeles Aircraft Certification Office (ACO), FAA. Operators shall submit their requests through an appropriate FAA Principal Maintenance Inspector, who may add comments and then send it to the Manager, Los Angeles ACO.
Information concerning the existence of approved alternative methods of compliance with this AD, if any, may be obtained from the Los Angeles ACO.
(d) Special flight permits may be issued in accordance with sections 21.197 and 21.199 of the Federal Aviation Regulations (14 CFR 21.197 and 21.199) to operate the airplane to a location where the requirements of this AD can be accomplished.
Import Administration, International Trade Administration, Department of Commerce; Office of Insular Affairs, Department of the Interior.
Notice of proposed rulemaking and request for comments.
The Departments propose amending their regulations governing watch duty-exemption allocations and the watch and jewelry duty-refund benefits for producers in the United States insular possessions (the U.S. Virgin Islands, Guam, American Samoa and the Commonwealth of the Northern Mariana Islands). The proposed rule would amend ITA regulations by clarifying the meaning of “permanent resident” which is a term used in Pub. L. 97-446 and the current regulations.
Written comments must be received on or before September 30, 2002.
Address written comments to Faye Robinson, Acting Director, Statutory Import Programs Staff, FCB, Suite 4100W, U.S. Department of Commerce, 14th and Constitution Ave., NW., Washington, DC 20230.
Faye Robinson, (202) 482-3526, same address as above.
The insular possessions watch industry provision in Sec. 110 of Pub. L. 97-446 (96 Stat. 2331) (1983), as amended by Sec. 602 of Pub. L. 103-465 (108 Stat. 4991) (1994); additional U.S. Note 5 to chapter 91 of the Harmonized Tariff Schedule of the United States (“HTSUS”), as amended by Pub. L. 94-241 (90 Stat. 263) (1976) requires the Secretary of Commerce and the Secretary of the Interior, acting jointly, to establish a limit on the quantity of watches and watch movements which may be entered free of duty during each calendar year. The law also requires the Secretaries to establish the shares of this limited quantity which may be entered from the Virgin Islands, Guam, American Samoa and the Commonwealth of the Northern Mariana Islands (“CNMI”). After the Departments have verified the data submitted on the annual application (Form ITA-334P), the producers' duty-exemption allocations are calculated from the territorial share in accordance with 15 CFR 303.14 and each producer is issued a duty-exemption license. The law further requires the Secretaries to issue duty-refund certificates to each territorial watch and watch movement producer based on the company's duty-free shipments and creditable wages paid during the previous calendar year.
Pub. L. 106-36 (113 Stat. 127) (1999) authorizes the issuance of a duty-refund certificate to each territorial jewelry producer for any article of jewelry provided for in heading 7113 of the HTSUS which is the product of any such territory. The value of the certificate is based on creditable wages paid and duty-free units shipped into the United States during the previous calendar year. Although the law specifically mentions the U.S. Virgin Islands, Guam and American Samoa, the issuance of the duty-refund certificate would also apply to the CNMI due to the Covenant to Establish a Commonwealth of the Northern Mariana Islands in Political Union with the United States of America (Pub. L. 94-241), which states that goods from the CNMI are entitled to the same tariff treatment as imports from Guam.
We propose amending Subpart A § 303.2(a) by adding paragraph (a)(16) and Subpart B § 303.16(a) by adding paragraph (a)(11) to provide a definition for “permanent resident” in order to clarify the meaning of the term for purposes of the insular program. The program was designed to spur local employment by giving producers benefits based on creditable wages paid to local people who were permanently domiciled in the insular possessions. Therefore, the Annual Application (Form ITA-334P) has always required each applicant to state the wages paid to employees who did not reside and work in the territory for at least six months during the calendar year so that the wages paid to non-residents could be deducted from the total wages before the creditable wages benefits were calculated. The program was not designed to give benefits based on creditable wages paid to program owners, shareholders or employees who are not domiciled in the insular possessions. We propose a definition that would continue to provide producers with benefits based on creditable wages including the creditable wages paid to program workers who meet the permanent resident criteria which require a person with one or more residences outside the insular possessions to maintain his or her domicile in the insular possessions, to reside (
In accordance with the Regulatory Flexibility Act, 5 U.S.C. 601
This proposed rulemaking does not involve new collection-of-information requirements subject to review and approval by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995. Collection activities are currently approved by the
Notwithstanding any other provision of the law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with a collection of information unless it displays a currently valid OMB Control Number.
It has been determined that the proposed rulemaking is not significant for purposes of Executive Order 12866.
Administrative practice and procedure, American Samoa, Customs duties and inspection, Guam, Imports, Marketing quotas, Northern Mariana Islands, Reporting and recordkeeping requirements, Virgin Islands, Watches and jewelry.
For reasons set forth above, the Departments propose to amend 15 CFR Part 303 as follows:
1. The authority citation for 15 CFR Part 303 continues to read as follows:
Pub. L. 97-446, 96 Stat. 2331 (19 U.S.C. 1202, note); Pub. L. 103-465, 108 Stat. 4991; Pub. L. 94-241, 90 Stat. 263 (48 U.S.C. 1681, note); Pub. L. 106-36, 113 Stat.127,167.
2. Section 303.2 is amended by adding paragraph (a)(16) as follows:
(a) * * *
(16)
3. Section 303.16 is amended by adding paragraph (a)(11) as follows:
(a) * * *
(11) Permanent resident means a person with one residence which is in the insular possessions or a person with one or more residences outside the insular possessions who meets criteria that include maintaining his or her domicile in the insular possessions, residing (
Federal Energy Regulatory Commission, DOE.
Advance notice of proposed rulemaking; staff public meeting.
On August 16, 2002 (67 FR 54749, August 26, 2002), the Federal Energy Regulatory Commission (Commission) issued an Advance Notice of Proposed Rulemaking seeking comments on standard small generator interconnection agreements and procedures that would be applicable to all public utilities that own, operate, or control transmission facilities under the Federal Power Act. This document announces a staff public meeting that will enable the parties to discuss and reach consensus on the proposed agreements and procedures.
The meeting will take place September 9 and 10, 2002, at 10 a.m.
Commission Meeting Room, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426.
The Federal Energy Regulatory Commission (Commission) has issued an Advance Notice of Proposed Rulemaking seeking comments on standard small generator interconnection agreements and procedures that would be applicable to all public utilities that own, operate, or control transmission facilities under the Federal Power Act.
The Commission has directed staff to try to develop a consensus on the standard small generator interconnection agreements and procedures. To this end, the Commission staff will hold a meeting on Monday, September 9, from 10 a.m. until 5 p.m. in the Commission Meeting Room at the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC. Breakout discussion meetings will be continued on Tuesday, September 10, 2002. These meetings will be open to the public.
All subsequent public meetings to discuss standard small generator interconnection agreements and procedures will be announced on the Commission's Internet site at
Federal Highway Administration (FHWA), DOT.
Cancellation of public meeting.
The FHWA published a notice of public meetings August 9,
The meeting scheduled for Thursday, August 29, 2002, from 10 to 2 p.m. is cancelled. Meetings will be held on Thursday, September 19 and Wednesday, September 25, 2002 from 10 to 2 p.m.
Cambridge Systematics, 4445 Willard Avenue, Suite 300, Chevy Chase, MD 20815. Telephone: (301) 347-0100 and Fax: (301) 347-0101.
Persons needing further information contact Mike Harris at PB Farradyne, Inc., by telephone at (703) 742-5759 or by Fax at (703) 742-5989. The U.S. DOT contact is Scott Battles, FHWA, 400 Seventh Street SW., Washington, DC 20590, (202) 366-4372. Office hours are from 7:45 a.m. to 4:15 p.m., e.t., Monday through Friday, except legal holidays.
An electronic copy of this document may be downloaded by using a computer, modem, and suitable communications software from the Government Printing Office's Electronic Bulletin Board Services at (202) 512-1661. Internet users may reach the Office of the Federal Register's home page at:
23 U.S.C. 106, 109, 115, 315, 320, and 402(a); 23 CFR 1.32; 49 CFR 1.48; sec. 1051, Pub. L. 1022-240, 105 Stat. 2001; sec. 358(b), Pub. L. 104-59, 109 Stat. 625.
Army Corps of Engineers, DOD.
Notice of public meeting.
The Army Corps of Engineers will hold public meetings in South Florida on the proposed rule to establish programmatic regulations for the Comprehensive Everglades Restoration Plan. Congress approved the Comprehensive Everglades Restoration Plan in section 601 of the Water Resources Development Act of 2000, Pub. L. 106541, 114 Stat. 2680, which was enacted into law on December 11, 2000. The Act requires the Secretary of the Army to promulgate programmatic regulations within two years to ensure that the goals and purposes of the Comprehensive Everglades Restoration Plan are achieved.
The public meetings are scheduled to begin at 7 p.m. as follows:
The meeting locations are:
Stu Appelbaum, Corps of Engineers, Jacksonville District, at the above address, phone (904) 232-1877; fax (904) 899-5001. You may also access the programmatic regulations web page at:
On August 2, 2002 the Army published the proposed rule to establish the programmatic regulations in the
You may submit your comments on the proposed rule by any of several methods:
1. You may submit written comments to U.S. Army Corps of Engineers, ATTN: CESAJ-DR-R, P.O. Box 4970, Jacksonville, FL 32232-0019.
2. You may send comments by electronic mail (e-mail) to:
3. You may also submit comments through the Internet by completing a comment form on the programmatic regulations web page at;
If submitting comments by electronic format, please submit them in ASCII file format or Word file and avoid the use of special characters and any form of encryption. Please include your name and return e-mail address in your e-mail message. Please note that your e-mail address will not be retained at the termination of the public comment period.
Each public meeting will begin with the Army Corps of Engineers providing a brief summary presentation on the proposed rule. Following the presentation, the public will be given the opportunity to speak. Speaker request cards will be available at the meeting for anyone wishing to speak.
Sec. 601, Pub. L. 106-541, 114 Stat. 2680; 10 U.S.C. 3013(g)(3); 33 U.S.C. 1 and 701; and 5 U.S.C. 301.
Environmental Protection Agency (EPA).
Proposed rule.
The EPA proposes to approve the State implementation plan (SIP) revisions submitted by the State of Tennessee for the purpose of revising the regulations for construction and operating permits, general provisions and applicability, and conflict of interest in the Tennessee SIP. In the Final Rules section of this
Written comments must be received on or before September 30, 2002.
All comments should be addressed to Steven M. Scofield at the EPA, Region 4 Air Planning Branch, 61 Forsyth Street, SW., Atlanta, Georgia 30303-8960.
Copies of the State submittals are available at the following addresses for inspection during normal business hours:
Steven M. Scofield; Regulatory Development Section; Air Planning Branch; Air, Pesticides and Toxics Management Division; U.S. Environmental Protection Agency Region 4; 61 Forsyth Street, SW.; Atlanta, Georgia 30303-8960. Mr. Scofield can also be reached by phone at (404) 562-9034 or by electronic mail at
For additional information see the direct final rule which is published in the Final Rules section of this
Forest Service, USDA.
Notice of meeting.
Due to travel restrictions presently in effect as a result of unusually high Federal wildfire fighting costs, the Intergovernmental Advisory Committee (IAC) will have a conference call (in lieu of a formal meeting) that is scheduled from 11 a.m.-12:30 p.m. on September 10, 2002. The conference line phone number for the call is 208-334-9840. The primary purpose of the call is to provide an update on recent events regarding implementation of the Northwest Forest Plan (NWFP). Agenda items to be discussed include the latest developments with respect to improving upon the present course of NWFP implementation and future IAC operations. Written comments may be submitted, and interested persons are invited to participate.
Questions regarding this meeting may be directed to Steve Odell, Executive Director, Regional Ecosystem Office, 333 S.W. First Avenue, P.O. Box 3623, Portland, OR 97208 (Phone: 503-808-2165).
Architectural and Transportation Barriers Compliance Board.
Notice of meeting.
The Architectural and Transportation Barriers Compliance Board (Access Board) has scheduled its regular business meetings to take place in Washington, DC, on Tuesday and Wednesday, September 10-11, 2002, at the times and location noted below.
The schedule of events is as follows:
The meetings will be held at the Marriott at Metro Center Hotel, 775 12th Street, NW., Washington, DC.
For further information regarding the meetings, please contact Lawrence W. Roffee, Executive Director, (202) 272-0001 (voice) and (202) 272-0082 (TTY).
At the Board meeting, the Access Board will consider the following agenda items.
• Executive Director's Report.
• Approval of the July 10, 2002 Board Meeting Minutes.
• ADA and ABA Accessibility Guidelines.
All meetings are accessible to persons with disabilities. Sign language interpreters and an assistive listening system are available at all meetings. Persons attending Board meetings are requested to refrain from using perfume, cologne, and other fragrances for the comfort of other participants.
Economic Development Administration (EDA).
To Give All Interested Parties an Opportunity to Comment.
Petitions have been accepted for filing on the dates indicated from the firms listed below.
The petitions were submitted pursuant to section 251 of the Trade Act of 1974 (19 U.S.C. 2341). Consequently, the Department of Commerce has initiated separate investigations to determine whether increased imports into the United States of articles like or directly competitive with those produced by each firm contributed importantly to total or partial separation of the firm's workers, or threat thereof, and to a decrease in sales or production of each petitioning firm.
Any party having a substantial interest in the proceedings may request a public hearing on the matter. A request for a hearing must be received by Trade Adjustment Assistance, Room 7315, Economic Development Administration, Department of Commerce, Washington, DC 20230, no later than the close of business of the tenth calendar day following the publication of this notice.
The Catalog of Federal Domestic Assistance official program number and title of the program under which these petitions are submitted is 11.313, Trade Adjustment Assistance.
International Trade Administration, Department of Commerce.
Notice to Announce Secretary Evans—Business Development Mission to Peru and Chile, December 2-6, 2002.
Secretary of Commerce Donald Evans will lead a senior-level business development mission to Lima, Peru and Santiago, Chile December 2-6, 2002. The focus of the mission will be to help U.S. companies explore business opportunities in Peru, the Andean Region and Chile. The delegation will include approximately 15 U.S.-based senior executives of small, medium and large U.S. firms representing, but not limited to the following sectors: energy, services, machinery and equipment, information and communication technologies. Service exports have become an increasingly important part of U.S. trade with Chile and Peru with opportunities in areas that support the development of their increasingly export-oriented economies.
Applications should be submitted to the Office of Business Liaison by October 2, 2002. Applications received after that date will be considered only if space and scheduling constraints permit.
Office of Business Liaison; Room 5062; Department of Commerce; Washington, DC 20230; Tel: (202) 482-1360; Fax: (202) 482-4054.
Secretary of Commerce Donald Evans will lead a senior-level business development mission to Lima, Peru and Santiago, Chile.
The focus of the mission will be to help U.S. companies explore business opportunities in Peru, the Andean Region and Chile. The delegation will include approximately 15 U.S.-based senior executives of small, medium and large U.S. firms representing, but not limited to the following sectors: energy, services, machinery and equipment, information and communication technologies. Service exports have become an increasingly important part of U.S. trade with Chile and Peru with opportunities in areas that support the development of their increasingly export-oriented economies.
Peru is an economically stable and growing marketplace. With a population of nearly 30 million, an entrepreneurial spirit and a democratic tradition, Peru offers both U.S. exporters and investors an attractive entry to the entire Andean Community. As Peru seeks economic growth within a policy of fiscal prudence, future privatization and development of emerging sectors that take advantage of the Andean Trade Preference Act are creating opportunities in a number of sectors (see above). Transparency in rule-making and customs have been strengthened in the past ten years, and Peru is currently negotiating a bilateral investment treaty with the United States. Currently, the U.S. is Peru's single largest trading partner, accounting for 30% of their imports and 25% of Peru's exports, with two-way trade totaling nearly $4 billion last year.
Peru is an attractive entry to the rest of the Andean region, consisting of Bolivia, Colombia, Ecuador and Venezuela. Combined, these countries have a total marketplace of 112 million people with a combined GDP of 290 billion dollars. With Andean Community harmonization continuing in customs rates and policies, as well as a continual lowering of internal community tariffs, Peru is well situated to take advantage of these benefits.
Chile is one of the Latin American region's most dynamic and promising markets. Its strength and attractiveness lie not in its size (population of 15 million people), but in the energy and
The U.S. and Chile are currently working to conclude a bilateral free trade agreement that will foster economic growth and create higher paying jobs in the United States by reducing and eliminating barriers to trade and investment. The agreement will create improved market opportunities for U.S. goods and services exports, providing important benefits for U.S. workers, farmers, businesses and families. The agreement with Chile will also assist U.S. efforts to create competition among countries for liberalization in the Western Hemisphere, thus furthering our efforts to establish a Free Trade Area of the Americas (FTAA).
The mission will further both U.S. commercial policy objectives and advance specific business interests. It is intended:
• To assist individual U.S. companies pursue export and other new business opportunities in Peru, Chile and the Andean Region, by introducing them to key host government decision-making officials and to potential business partners;
• To assist potential new-to-market firms evaluate the market potential for their products and gain an understanding of how to operate successfully in the commercial environment of Peru and Chile;
• To enhance the dialogue between government and industry on issues affecting the development of U.S.-Peru and U.S.-Chile commercial relations;
• To emphasize the benefits of international trade for improving the standard of living and quality of life; and
• To highlight examples of corporate citizenship and active involvement by U.S. businesses in the communities where they operate in the United States and abroad.
The Business Development Mission will provide participants with exposure to high-level business and government contacts and an understanding of market trends and the commercial environment of Peru and Chile. U.S. Embassy officials will provide detailed briefings on the economic, commercial and political climates, and participants will receive individual counseling on their specific interests from U.S. Commercial Service industry specialists.
Meetings will be arranged as appropriate with senior government officials and potential business partners. Representational events also will be organized to provide mission participants with opportunities to meet Peru and Chile's business and government representatives, as well as U.S. business people living and working in Peru and Chile.
The tentative trip itinerary will be as follows:
The recruitment and selection of private sector participants for this mission will be conducted according to the “Statement of Policy Governing Department of Commerce Overseas Trade Missions” established in March 1997 (
Promotion and recruitment will include, but not be limited to, posting on appropriate Department of Commerce web pages, notification in the
Participating companies must be incorporated in the United States. A company is eligible to participate only if the products and/or services that it will promote (a) are manufactured or produced in the United States; or (b) if manufactured or produced outside the United States, are marketed under the name of a U.S. firm and have U.S. content representing at least 51 percent of the value of the finished good or service.
Companies will be selected for participation in the mission on the basis of:
• Consistency of company's goals with the scope and desired outcome of the mission as described herein;
• Relevance of a company's business and product line to market opportunities in Peru and Chile;
• Seniority of the representative of the designated company;
• Past, present, or prospective international business activity;
• Diversity of company size, type, location, demographics, and traditional under-representation in business;
• Degree of company's commitment to corporate citizenship.
An applicant's partisan political activities (including political contributions) are irrelevant to the selection process.
Applications for the trade mission to Peru and Chile will be made available on or about August 21, 2002. The fee to participate in the mission will be between $6000-$8000 per company. Expenses for travel, lodging, and some meals will be the responsibility of each participant. For additional information on the trade mission or to obtain an application, contact the Department of Commerce Office of Business Liaison at 202-482-1360. Applications should be submitted to the Office of Business Liaison by October 2, 2002, in order to ensure sufficient time to obtain in-country appointments for applicants selected to participate in the mission. Applications received after that date will be considered only if space and scheduling constraints permit.
Contact: Office of Business Liaison, Room 5062, Department of Commerce, Washington, DC 20230, Tel: (202) 482-1360, Fax: (202) 482-4054,
Commission on the Future of the United States Aerospace Industry.
Notice.
This meeting is the fifth in a series of planned public meetings being held by the Commission to carry out its statutory charge with respect to the U.S. civil and military, air and space industry. The focus of this meeting is to deliberate and vote on recommendations to be included in the Commission's final report to Congress and the President.
Section 1092 of the Floyd D. Spence National Defense Authorization Act for Fiscal Year 2001 (Pub. L. 106-398) established the Commission on the Future of the United States Aerospace Industry to study the issues associated with the future of the United States national security; and assess the future importance of the domestic aerospace industry for the economic and national security of the United States. The Commission is governed by the provisions of the Federal Advisory Committee Act, Pub. L. 92-463, as amended (5 U.S.C. Appendix 2), which sets forth standards for the formation of advisory committees and implementing regulations (41 CFR Subpart 101-6.10). All interested parties are welcome to submit written comments at any time.
Tuesday, September 17, 2002; 3 p.m. to 5:30 p.m.
Herbert C. Hoover Building Auditorium, U.S. Department of Commerce, 14th Street and Constitution Avenue, NW., Washington, DC 20230.
Cindy Waters, 1235 Jefferson Davis Highway, Suite 940; Arlington, Virginia 22202; phone 703-602-1515; e-mail
Committee for the Implementation of Textile Agreements (CITA).
Issuing a directive to the Commissioner of customs adjusting limits.
August 29, 2002.
Naomi Freeman, International Trade Specialist, Office of Textiles and Apparel, U.S. Department of Commerce, (202) 482-4212. For information on the quota status of these limits, refer to the Quota Status Reports posted on the bulletin boards of each Customs port, call (202) 927-5850, or refer to the U.S. Customs website at http://www.customs.gov. For information on embargoes and quota re-openings, refer to the Office of Textiles and Apparel website at http://otexa.ita.doc.gov.
Section 204 of the Agricultural Act of 1956, as amended (7 U.S.C. 1854); Executive Order 11651 of March 3, 1972, as amended.
The current limit for Category 442 is being increased for swing, reducing the limit for Category 444 to account for the swing being applied to Category 442.
A description of the textile and apparel categories in terms of HTS numbers is available in the CORRELATION: Textile and Apparel Categories with the Harmonized Tariff Schedule of the United States (see
Dear Commissioner: This directive amends, but does not cancel, the directive issued to you on November 29, 2001, by the Chairman, Committee for the Implementation of Textile Agreements. That directive concerns imports of certain wool textile products, produced or manufactured in Ukraine and exported during the twelve-month period which began on January 1, 2002 and extends through December 31, 2002.
Effective on August 29, 2002, you are directed to adjust the limits for the following categories, as provided for under the terms of the current bilateral textile agreement between the Governments of the United States and Ukraine:
The Committee for the Implementation of Textile Agreements has determined that these actions fall within the foreign affairs exception to the rulemaking provisions of 5 U.S.C. 553(a)(1).
Sincerely,
Department of Education.
The Secretary of Education requests comments on the Free Application for Federal Student Aid (FAFSA) that the Secretary proposes to use for the 2003-2004 year. The FAFSA is completed by students and their families and the information submitted on the form is used to determine the students' eligibility and financial need for financial aid under the student financial assistance programs authorized under Title IV of the Higher Education Act of 1965, as amended, (Title IV, HEA Programs).
Interested persons are invited to submit comments on or before September 30, 2002.
Section 483 of the Higher Education Act of 1965, as amended (HEA), requires the Secretary, “in cooperation with agencies and organizations involved in providing student financial assistance,” to “produce, distribute and process free of charge a common financial reporting form to be used to determine the need and eligibility of a student under” the Title IV, HEA Programs. This form is the FAFSA. In addition, Section 483 authorizes the Secretary to include non-financial data items that assist States in awarding State student financial assistance.
The Secretary requests comments on the draft 2003-2004 FAFSA that has
The Secretary is considering additional skip logic to incorporate the simplified needs test and automatic zero expected family contribution to the FAFSA on the Web product, and requests comments regarding adding this functionality. The Secretary is publishing this request for comment under the provisions of the Paperwork Reduction Act of 1995, 44 U.S. C. 3501
Requests for copies of the submission for OMB review; comment request may be accessed from
(1) Go to IFAP at
(2) Click on “Current SFA Publications”.
(3) Scroll down and click on “FAFSAs and Renewal FAFSAs”.
(4) Click on “By 2003-2004 Award Year”.
(5) Click on “Draft FAFSA Form/Instructions”.
Please note that the free Adobe Acrobat Reader software, version 4.0 or greater, is necessary to view this file. This software can be downloaded for free from Adobe's website:
Comments regarding burden and/or the information collection activity requirements should be directed to Joseph Schubart at (202) 708-9266 or via his internet address
The Department is not bound by any estimates in this notice.
Factors for Emergency grants:
(a) Justification that proposed project will address a valid emergency; consistency of emergency description and proposed project with certifying local official's statement.
(b) Impact of emergency condition on the health and safety of the building occupants or on program delivery (examples: The areas and extent of the facility affected (system(s) involved, e.g., HVAC, roof, floor, windows; the type of space affected, such as instructional, resource, food service, recreational, general support, or other areas); the percentage of building occupants affected by the emergency; and the importance of the facility or affected area to the instructional program).
(c) Project urgency (examples: Risk if not addressed; projected increased future costs; effect of proposed project on the useful life of the facility or the need for major construction; or age and condition of facility and date of last renovation of affected areas). Factors for Modernization grants:
(a) Justification that proposed project is a valid modernization need (example: Building capacity is 300 students; current enrollment is 350. Three additional classrooms are needed to meet State standards re: capacity and 20-to-1 student/teacher ratio).
(b) Impact of modernization challenges on building occupants or program delivery (examples: The percentage of building occupants adversely affected; the areas and extent of the facility affected (type of space affected, such as instructional, resource, food service, recreational, general support, or other areas); and the importance of the facility or affected space to the required instructional program).
(c) Project urgency in fiscal terms (examples: Proposed project will extend useful life of current facility on cost-effective basis, or district can improve program quality with updated facility and delay replacement of facility).
(a) Extent to which the proposed project plan or goal is clearly specified and will address the identified need, mitigate the risks, and provide an immediate improvement.
(b) Extent to which the proposed plan and budget are cost-effective and will extend the useful life of the facility or delay the need for major construction or replacement (examples: Age and condition of facility and date of last renovation of affected areas; reasonableness and completeness of cost estimate; relationship of project costs to projected savings).
(c) District's general financial situation (examples: Available funds from other sources; ability to fund a portion of the project costs with local funds and cover cost over-runs).
(d) If applicable, the justification for why it is more cost-effective for the applicant to rebuild rather than renovate an existing facility.
For section 8003 districts:
(a) Amount of non-taxable Federal property in the applicant district (percentage of Federal property divided by 10); (up to 10 points)
(b) The numbers of federally connected children identified in sections 8003(a)(1)(A), (B), (C), and (D) of the Act in the district (percentage of identified children in district divided by 10); (up to 10 points)
(c) Numbers of federally connected children identified in sections 8003(a)(1)(A), (B), (C), and (D) of the Act in the school facility (percentage of children in school facility divided by 10); (up to 10 points) or
For section 8002 districts:
(d) The amount of non-taxable Federal property in the applicant district (percentage of Federal property divided by 10 and multiplied by 3); (up to 30 points)
(a) The percentage an LEA has used of its bonding capacity. Five points to be
(b) Assessed value of real property per students (applicant LEA's total assessed valuation of real property per pupil as a percentile ranking of all LEAs in the State. Five points to be distributed by providing all five points to LEAs in the poorest quintile and only one point to LEAs in the wealthiest quintile). (up to 5 points)
(c) Total tax rate for capital or school purposes (applicant LEA's tax rate for capital or school purposes as a percentile ranking of all LEAs in the State. If the State authorizes a tax rate for capital expenditures, then these data must be used, otherwise data on the total tax rate for school purposes are used. Five points to be distributed by providing all five points to LEAs in the highest taxing quintile and only one point to LEAs in the lowest quintile). (up to 5 points)
Except as provided in 34 CFR 222.190, all eligible applications in the “first priority” emergency category must be funded before applications in the next priority can be funded. The Secretary will not subject applications in the second, third, and fourth priorities to the panel review process if the need for funds in the first priority and the number of eligible applications received greatly exceeds the $27 million available. Likewise, if the numbers of applications and need for funds in the first and second priorities greatly exceed the available funds, the Secretary will not submit applications from the third and fourth priorities for a panel review. However, as prescribed in section 8007(b) of the Act and the implementing regulations, any unfunded application in any of the four priorities will be retained and considered along with the next fiscal year's pool of applicants.
Catherine Schagh, Impact Aid Program, U.S. Department of Education, 400 Maryland Avenue, SW., FOB6, Washington, DC 20202-6244. Telephone: (202) 260-3858 or via Internet, at:
Individuals who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-888-877-8339.
Individuals with disabilities may obtain this document in an alternative format (
To use PDF you must have adobe Acrobat Reader, which is available free at this site. If you have questions about using PDF, call the U.S. Government Printing Office (GPO). toll free, at 1-888-293-6498; or in the Washington, DC area at (202) 512-1530.
The Department intends to offer further information about the program at the following Internet site:
The official version of this document is the document published in the
Elementary and Secondary Education Act of 1965, Title VIII, as amended by the No Child Left Behind Act of 2001.
Office of Postsecondary Education, Department of Education.
Notice of child care provider loan forgiveness demonstration program for fiscal year (FY) 2002.
The Secretary announces the eligibility criteria and procedures for implementation of the child care provider loan forgiveness demonstration program authorized by section 428K of the Higher Education Act of 1965, as amended (HEA), for FY 2002. Under the demonstration program, some child care providers may have a portion of their student loans forgiven for continued work in certain child care facilities each year up to 5 years.
This notice explains the criteria for both new applicants and for borrowers who have previously applied for, and received, loan forgiveness under this loan forgiveness program during a prior fiscal year. For the purpose of program administration, borrowers who have previously applied for, and received, loan forgiveness under this loan forgiveness program during a prior fiscal year are called “renewal applicants”.
This notice is effective August 29, 2002.
(A) To qualify for the child care provider loan forgiveness demonstration program, an applicant must:
(1) Be a new borrower with eligible loans, in the FFEL or Direct Loan Programs, as defined in the “Program Definitions” section of this notice;
(2) Have received an associate or bachelor's degree in the field of early childhood education or child care that was awarded by an institution of higher education after October 7, 1998; and
(3) After receiving an associate's or bachelor's degree in early childhood education or child care, have worked full-time for at least two consecutive years preceding the year during which forgiveness is requested as a child care provider in a facility that serves a low-income community.
(B) A borrower may not receive benefits for the same child care service under both subtitles D of title I of the National and Community Service Act of 1990 (Americorps) and this demonstration program.
(A) To qualify for further loan forgiveness under the Child Care Provider Loan Forgiveness Demonstration Program, a borrower must:
(1) Have been determined previously to meet the eligibility requirements for a forgiveness as described in this notice and continues to meet those criteria; and
(2) Have completed the third consecutive year of full-time employment as a provider in a child care facility that serves a low-income community.
Mr. Don Watson at the U.S. Department of Education, 830 First Street NE., Washington, DC 20202-5346. Telephone: (202) 377-4008. To receive an application, you may call the Child Care Provider Loan Forgiveness support desk toll free at 1-888-562-7002. You may also write to the Child Care Provider Loan Forgiveness Program to receive an application at, P.O. Box 4639, Utica, NY 13504-4639. In addition, free Internet access to the application and forbearance forms are available, in Adobe Portable Document Format (PDF) at the following site:
If you use a telecommunications device for the deaf (TDD), you may call the Federal Information Relay Service (FIRS) at 1-800-877-8339.
Individuals with disabilities may obtain this document in an alternative format (
This notice announces the continuation of the demonstration program, first implemented in FY 2001, of loan forgiveness for child care providers as authorized under section 428K of the HEA. The HEA authorizes the Secretary, contingent upon the availability of annual appropriations, to undertake a loan forgiveness demonstration program for borrowers under the FFEL and the Direct Loan programs who have received an associate's or bachelor's degree in early childhood education or child care and who are providing full-time child care services in child care facilities that serve certain low income communities. The child care provider loan forgiveness demonstration program is intended to bring more highly trained individuals into the early child care profession and to retain those providers for longer periods of time. The Congress has appropriated $1,000,000 for new applicants under the demonstration program for fiscal year 2002. As described in the notice published in the
Under the demonstration program, new FFEL and Direct Loan borrowers (as defined in the “Program Definitions” section of this notice) may receive forgiveness of up to 100 percent of their total eligible loans made under the FFEL subsidized and unsubsidized Federal Stafford Loan, Direct Subsidized Loan, and Direct Unsubsidized Loan programs. A loan is eligible for forgiveness only if it (1) was made on or after October 7, 1998, the date of enactment of the Higher Education Amendments of 1998, which authorized the program; (2) was received for the purpose of obtaining an associate's or bachelor's degree in early childhood education or child care; and (3) was made before the beginning of qualifying service. Loan forgiveness is provided to eligible borrowers on a progressive basis (
Under section 428K of the HEA, loan forgiveness is available to eligible borrowers on a first-come, first-served basis, contingent upon the availability of funds. Priority for loan forgiveness in subsequent fiscal years is given to borrowers who received loan forgiveness in the preceding fiscal year.
The Secretary is required to evaluate the success of the demonstration program in achieving the statutory goals of attracting and retaining highly trained individuals into the early child care profession. In order to perform this evaluation and to ensure priority for eligible applicants for subsequent-year funding, the Secretary is continuing his practice from last year of committing funds from the current fiscal year to cover the full five years of loan forgiveness for eligible new applicants.
The Secretary has determined that the issuance of regulations to implement the loan forgiveness demonstration program for child care is not necessary at this time. Section 428K of the HEA creates the loan forgiveness for child care providers program as a demonstration program. Funding was provided for the second year of this demonstration program in the Departments of Labor, Health and Human Services, and Education, and Related Agencies Appropriations Act 2002, enacted on January 10, 2002 (Pub. L. 107-116), in which $1,000,000 was appropriated.
In light of the limited amount of funds available and the fact that the loan forgiveness program for child care providers is a demonstration program, the Secretary has decided to issue this notice to continue the loan forgiveness demonstration program for the 2002 application year and to explain the procedures for granting loan forgiveness to new applicants and renewal applicants for the 2002 application year. These procedures are based on the statutory language, and further regulations are not needed at this time.
(A) A borrower employed full-time as a child care provider may receive forgiveness of the borrower's eligible loans in the amount of:
(1) Twenty percent of the total amount of eligible loans after the second consecutive year (24 continuous months) of full-time employment;
(2) Twenty percent of the total amount of eligible loans after the third consecutive year (36 continuous months) of full-time employment; and
(3) Thirty percent of the total amount of eligible loans after each of the fourth and fifth consecutive years (48 and 60 continuous months respectively) of full-time employment.
(B) An eligible borrower not previously participating in the loan forgiveness program who secures an associate's or bachelor's degree in early childhood education or child care after previously graduating from an institution of higher education in an area other than early childhood education is eligible to receive forgiveness of the total amount of eligible loans received for a maximum of two academic years in pursuit of that early childhood education or child care degree, according to the percentages specified in paragraph (A) of this section.
(C) For each year of qualifying service, the Secretary forgives the percentage of the eligible loans plus the proportionate amount of interest that accrues on the loan.
(D) The loan holder does not refund payments that were received from, or paid on behalf of, a borrower who qualifies for loan forgiveness under this section.
(A) After completing the eligible child care service, a borrower may request loan forgiveness from the Secretary on a form approved by the Secretary and accompanied by any required supporting documentation.
(B) The Secretary, after receiving a completed and accurate application:
(1) Makes a loan forgiveness commitment to a qualified new applicant on a first-come, first-served basis according to the date that a complete and accurate application is received and contingent upon the availability of funds; and
(2) Reaffirms the prior commitment for a renewal applicant if the renewal applicant continues to meet the eligibility requirements.
(C) The Secretary notifies applicants of their eligibility or ineligibility for loan forgiveness and the amount that is being forgiven for that application year.
(D) If the Secretary approves the borrower's request for forgiveness of the loan, the Secretary forwards payment of the forgiven amount to the holder of the borrower's largest current outstanding unsubsidized loan, if any, for payment on that loan. If the borrower has no outstanding unsubsidized loans, the Secretary forwards the forgiven amount to the holder of the borrower's largest current outstanding subsidized loan.
(E) If the holder determines that the amount of the loan forgiveness payment received from the Secretary exceeds the remaining balance of the loan to which it is designated, the holder shall apply the remaining balance to another eligible loan of the borrower held by the holder. If the holder does not hold any of the borrower's other eligible loans, the lender shall refund the balance to the Secretary. If applicable, the Secretary then forwards the balance to another holder of the borrower's eligible loans.
(A) At the written request of the borrower, the Secretary or the holder of eligible loans grants forbearance in annual increments to a borrower performing the type of service that would qualify the borrower for loan forgiveness, unless the borrower has been granted a deferment for that period of service.
(B) Before a new applicant receives forbearance for eligible child care service, the borrower must:
(1) Submit documentation to the Secretary or the holder for the period of the annual forbearance request showing the beginning and anticipated ending dates that the borrower is expected to perform, for that year, eligible child care service; and
(2) Certify the borrower's understanding that receiving forbearance for eligible service does not guarantee receipt of loan forgiveness benefits.
(C) Before a renewal applicant receives forbearance for eligible child care service, the renewal applicant must submit documentation to the Secretary or the holder for the period of the annual forbearance request showing the beginning and anticipated ending dates that the borrower is expected to perform, for that year, eligible child care service.
You may view this document, as well as all other Department of Education documents published in the
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20 U.S.C. 1078-11.
Secretary of Education's Commission on Opportunity in Athletics; Department of Education.
Notice of open meeting.
This notice sets forth the schedule and proposed agenda of a forthcoming public meeting of the Secretary of Education's Commission on Opportunity in Athletics (the Commission). The Commission invites comments from the public regarding the application of current Federal standards for ensuring equal opportunity for men and women and boys and girls to participate in athletics under Title IX of the Education Amendments of 1972 (“Title IX”). The meeting will take place in Chicago, Illinois. This meeting will primarily focus on Title IX as it relates to High Schools and Two-Year Colleges; however there will be an opportunity to comment on Title IX in general.
Individuals who will need accommodations for a disability in order to attend the meetings should notify the Commission office no later than September 12, 2002. We will attempt to meet requests after this date, but cannot guarantee availability of the requested accommodation. The meeting site is accessible to individuals with disabilities.
Notice of this meeting is required under section 10(a)(2) of the Federal Advisory Committee Act. DATES: September 17-18, 2002.
The meeting scheduled for September 18, 2002 will consist of review and discussion by the Commissioners of the information from the previous public meetings in preparation for the Commission's forthcoming report to the Secretary of Education. The public is invited to observe this meeting; however there will not be opportunity for public comment.
If you are interested in participating in the public comment period to present comments on the Federal standards for ensuring equal opportunity for men and women to participate in athletics under Title IX at this meeting, you are requested to reserve time on the agenda of the meeting by contacting the Commission office by e-mail or fax.
We request that you submit a request to the Commission office by e-mail or fax. Please include your name, the organization you represent if appropriate, and a brief description of the issue you would like to present. Participants will be allowed approximately 3 to 5 minutes to present their comments, depending on the number of individuals who reserve time on the agenda. At the meeting, participants are also encouraged to submit two written copies of their comments. Persons interested in making comments are encouraged to address the issues and questions discussed under
Given the expected number of individuals interested in providing comments at the meetings, reservations for presenting comments should be made as soon as possible. Persons who are unable to obtain reservations to speak during the meetings are encouraged to submit written comments. Written comments will be accepted at each meeting site or may be mailed to the Commission at the address listed under
In addition to making reservations, individuals attending the public meetings, for security purposes, must be prepared to show photo identification in order to enter the meeting location.
We would like to receive your written comments on the Act by November 29, 2002.
Submit all comments to the Commission using one of the following methods:
1.
2.
3.
See the Commission address under the
The nation is commemorating the 30th anniversary of the passage of Title IX, the landmark legislation prohibiting recipients of Federal funds from discriminating on the basis of sex. Since this legislation was enacted, there has been a dramatic increase in the number of women participating in athletics at the high school and college levels. The Secretary of Education has determined that this anniversary provides an appropriate time to review the application of Title IX to educational institutions' efforts to provide equal opportunity in athletics to women and men. In order to do so, the Secretary established the Commission on Opportunity in Athletics. The Commission will produce a report no later than January 31, 2002, outlining its findings relative to the opportunities for men and women in athletics in order to improve the effectiveness of Title IX. Comments are encouraged on the following priority areas:
1. Are Title IX standards for assessing equal opportunity in athletics working to promote opportunities for male and female athletes?
2. Is there adequate Title IX guidance that enables colleges and school districts to know what is expected of them and to plan for an athletic program that effectively meets the needs and interests of their students?
3. Is further guidance or are other steps needed at the junior and senior high school levels where the availability
4. How should activities such as cheerleading or bowling factor into the analysis of equitable opportunities?
5. How do revenue producing and large-roster teams affect the provision of equal athletic opportunities? The Department has heard from some parties that whereas some men athletes will “walk-on” to intercollegiate teams—without athletic financial aid and without having been recruited—women rarely do this. Is this accurate and, if so, what are its implications for Title IX analysis?
6. In what ways do opportunities in other sports venues, such as the Olympics, professional leagues, and community recreation programs, interact with the obligations of colleges and school districts to provide equal athletic opportunity? What are the implications for Title IX?
7. Apart from Title IX enforcement, are there other efforts to promote athletic opportunities for male and female students that the Department might support, such as public-private partnerships to support the efforts of schools and colleges in this area?
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The official version of this document is published in the
Take notice that on August 15, 2002, Tennessee Gas Pipeline Company (Tennessee), tendered for filing its Negotiated Rate Tariff Filing.
Tennessee's filing requests that the Commission approve a corrected negotiated rate arrangement between Tennessee and Union Light, Heat & Power Company. Tennessee requests that the Commission grant such approval effective August 1, 2002.
Any person desiring to be heard or to protest said filing should file a motion to intervene or a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with sections 385.214 or 385.211 of the Commission's Rules and Regulations. All such motions or protests must be filed in accordance with section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
Take notice that on August 19, 2002, Atlanta Gas Light Company (Atlanta), in compliance with the Commission's July 18, 2002 Order in the above-referenced proceeding, tendered for filing its previously effective Rate Schedule IBSS, along with all related provisions of the Terms of Service of its limited jurisdiction FERC tariff. Atlanta requested an effective date for the tariff sheets of September 1, 2002.
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Section 385.211 of the Commission's Rules and Regulations. All such protests must be filed in accordance with Section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
Take notice that on August 19, 2002, Columbia Gas Transmission Corporation (Columbia) tendered for filing as part of its FERC Gas Tariff, Second Revised Volume No. 1, revised tariff sheets, listed in Appendix A to the filing.
Columbia states that the filing is made to revise various tariff sheets filed in Docket No. RP00-326-000 on July 31, 2001 pursuant to Order No. 637 and Order No. 637-A in compliance with the Commission's July 19, 2002 Order (100 FERC ¶ 61,084).
Columbia states that copies of its filing have been mailed to all firm customers, interruptible customers, parties on the official service list of this proceeding, and affected state commissions.
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426, in accordance with Section 385.211 of the Commission's Rules and Regulations. All such protests must be filed in accordance with Section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
Take notice that on August 14, 2002, Columbia Gas Transmission Corporation (Columbia), 12801 Fair Lakes Parkway, Fairfax, Virginia 22030-0146, filed with the Federal Energy Regulatory Commission (Commission) in Docket No. CP02-426-000, a request pursuant to 157.205 and 157.216 of the Commission's Regulations (18 CFR 157.205 and 157.216) under the Natural Gas Act, for authorization to abandon by sale certain natural gas facilities located in Raleigh and Summers Counties, West Virginia, known as the KA-8 System, to Equitable Gathering, LLC (Equitable)
Columbia and Equitable entered into an agreement in which Columbia will sell the facilities known as the KA-8 System with the rights-of-way and appurtenances, which consists of: Line KA-11 (approximately 0.8 mile of 4-inch pipeline); Line KA-16 (approximately 0.1 mile of 4-inch pipeline); Line KA-7 (approximately 6 miles of 8-inch pipeline); Line KA-8 (approximately 15.5 miles of 8-inch pipeline); Harper Compressor Station (one 280 hp compressor unit); Raleigh Compressor Station (two 140 hp compressor units). The KA-8 System facilities were constructed and operated under certificate approval granted by the Commission in Docket No. CP71-132. The facilities were constructed in the early 1950's to deliver volumes from Columbia's Line KA and local production to the Beckley, West Virginia market. Columbia states that the facilities are no longer an integral part of its transmission system, retaining the facilities is inconsistent with its primary business of transporting and storing natural gas, and the abandonment will reduce its current operating and maintenance expense.
Columbia will sell the facilities to Equitable for the net depreciated book cost at the time of closing, estimated to be $2,000,000. Columbia states that it does not propose to abandon service to any customers, other than the mainline tap consumers shown in Exhibit Z-5 and to those listed on Exhibit Z-4. Columbia states that Equitable has agreed to assume any obligation that Columbia may have to provide service to the customers receiving service through the facilities at the time of closing on terms and conditions acceptable to both Equitable and the customers. Columbia attached as Exhibit Z-6 copies of the letters from its customers agreeing to the abandonment of the KA-8 System.
Any questions concerning this request may be directed to Fredric J. George, Attorney, Columbia Gas Transmission Corporation, P. O. Box 1273, Charleston, West Virginia 25325-1273 at (304) 357-2359 or fax (304) 357-3206.
Any person or the Commission's staff may, within 45 days after issuance of the instant notice by the Commission, file pursuant to Rule 214 of the Commission's Procedural Rules (18 CFR 385.214) a motion to intervene or notice of intervention and, pursuant to section 157.205 of the Regulations under the Natural Gas Act (18 CFR 157.205), a protest to the request. If no protest is filed within the time allowed therefor, the proposed activity shall be deemed to be authorized effective the day after the time allowed for filing a protest. If a protest is filed and not withdrawn within 30 days after the allowed time for filing a protest, the instant request shall be treated as an application for authorization pursuant to section 7 of the Natural Gas Act.
Comments, protests and interventions may be filed electronically via the Internet in lieu of paper. See, 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's web site under the “e-Filing” link. The Commission strongly encourages electronic filings.
Take notice that on August 19, 2002, Eastern Shore Natural Gas Company (Eastern Shore) tendered its filing in compliance with the Commission's July 19, 2002 Order on Compliance with Order Nos. 637, 587-G and 587-L.
Eastern Shore states that copies of its filing has been mailed to its customers and interested state commissions.
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426, in accordance with Section 385.211 of the Commission's Rules and Regulations. All such protests must be filed in accordance with Section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
Take notice that on August 16, 2002 Eastern Shore Natural Gas Company (Eastern Shore) tendered for filing as part of its FERC Gas Tariff, Second Revised Volume No. 1, Substitute Original Sheet No. 193A, proposed to be effective July 1, 2002.
Eastern Shore states that the substitute tariff sheet is being submitted to comply with Commission's Order issued on August 8, 2002 directing Eastern Shore to file a revised tariff sheet within 15 days of its order substituting “Releasing Buyers” for “Replacement Buyers” in the first sentence in Section 29(d)(2) of Eastern Shore's General Terms and Conditions in order to fully incorporate the language required by Order No. 587-N.
Eastern Shore states that copies of its filing has been mailed to its customers and interested state commissions.
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with section 385.211 of the Commission's Rules and Regulations. All such protests must be filed in accordance with section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
Take notice that on August 9, 2002, Entergy Services, Inc. (Entergy) acting as an agent for Entergy louisiana, inc. (Entergy Louisiana), filed with the Federal Energy Regulatory Commission (Commission) an Interconnection and Operating Agreement (the Interconnection Agreement) between Entergy Louisiana and Bayou Verret Energy, L.L.C.
Any person desiring to intervene or to protest this filing should file with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. All such motions or protests should be filed on or before the comment date, and, to the extent applicable, must be served on the applicant and on any other person designated on the official service list. This filing is available for review at the Commission or may be viewed on the Commission's Web site at
Take notice that on August 14, 2002, Equitable Gathering LLC (Equitable), Four Allegheny Center, 9th Floor, Pittsburgh, PA 15212-5255, filed in Docket No. CP02-425-000, an application, pursuant to Section 7(c) of the Natural Gas Act (NGA), as amended, and the Federal Energy Regulatory Commission's (Commission) Rules and Regulations thereunder, for a limited jurisdiction certificate to allow Equitable to utilize certain facilities that Equitable intends to acquire from
Equitable and Columbia entered into an agreement, dated April 11, 2002, in which Columbia will sell and Equitable will purchase the facilities known as the KA-8 System with the rights-of-way and appurtenances, which consists of: Line KA-11 (approximately 0.8 mile of 4-inch pipeline); Line KA-16 (approximately 0.1 mile of 4-inch pipeline); Line KA-7 (approximately 6 miles of 8-inch pipeline); Line KA-8 (approximately 15.5 miles of 8-inch pipeline); Harper Compressor Station (one 280 hp compressor unit); Raleigh Compressor Station (two 140 hp compressor units). Historically, the KA-8 facilities were used by Columbia to transport locally produced gas for delivery into Columbia's mainline system for redelivery to various markets. Additionally, the historical operation of the KA-8 facilities has included the provision of transportation service on behalf of Mountaineer Gas Company (Mountaineer), a local distribution company (LDC) subject to the jurisdiction of the West Virginia Public Service Commission. Such service included deliveries to about 100 field tap customers, and to approximately 8 town border stations at the city of Beckley, West Virginia.
According to Equitable, the agreement between Equitable and Columbia provides for Equitable to continue to provide service to Mountaineer at the field taps and the border stations at Beckley. Equitable states that during the winter operations when local production received into the KA-8 facilities will not be sufficient to meet the needs of the Mountaineer customers, then gas from Columbia's Line KA will flow north into the KA-8 facilities to supplement the local production. Equitable states that Columbia and Equitable have agreed that the Effective Date of the sale of the KA-8 facilities shall not occur until Columbia receives all necessary approvals fro the Commission to abandon such facilities and Equitable receives a limited jurisdiction certificate.
Equitable contends that it will utilize the facilities as part of its primary function of gathering with the occasional delivery of gas received from Columbia to Mountaineer through the gathering facilities being incidental to the primary gathering function of the facilities. Equitable also asks that it not be subjected to all the filing and accounting requirements applicable to interstate pipeline companies. Equitable states that it seeks only a limited jurisdiction certificate and will refuse any certificate that considers the primary purpose of the facilities to be interstate transmission with the full panalopy of regulatory requirements under the NGA. Equitable's application includes a discussion of the primary function of the KA-8 facilities. Columbia will sell the facilities to Equitable for the net depreciated book cost at the time of closing, estimated to be $2,000,000.
Any questions concerning this request may be directed to Gregory S. Davis, President, Equitable Gathering LLC, Four Allegheny Center, 9th Floor, Pittsburgh, PA, 15212-5255 at (412) 395-3000 or fax (412) 395-3155.
There are two ways to become involved in the Commission's review of this project. First, any person wishing to obtain legal status by becoming a party to the proceedings for this project should, on or before September 13, 2002, file with the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426, a motion to intervene in accordance with the requirements of the Commission's Rules of Practice and Procedure (18 CFR 385.214 or 385.211) and the Regulations under the NGA (18 CFR 157.10). A person obtaining party status will be placed on the service list maintained by the Secretary of the Commission and will receive copies of all documents filed by the applicant and by all other parties. A party must submit 14 copies of filings made with the Commission and must mail a copy to the applicant and to every other party in the proceeding. Only parties to the proceeding can ask for court review of Commission orders in the proceeding.
However, a person does not have to intervene in order to have comments considered. The second way to participate is by filing with the Secretary of the Commission, as soon as possible, an original and two copies of comments in support of or in opposition to this project. The Commission will consider these comments in determining the appropriate action to be taken, but the filing of a comment alone will not serve to make the filer a party to the proceeding. The Commission's rules require that persons filing comments in opposition to the project provide copies of their protests only to the party or parties directly involved in the protest.
Persons who wish to comment only on the environmental review of this project should submit an original and two copies of their comments to the Secretary of the Commission. Environmental commenters will be placed on the Commission's environmental mailing list, will receive copies of the environmental documents, and will be notified of meetings associated with the Commission's environmental review process. Environmental commenters will not be required to serve copies of filed documents on all other parties. However, the nonparty commenters will not receive copies of all documents filed by other parties or issued by the Commission (except for the mailing of environmental documents issued by the Commission) and will not have the right to seek court review of the Commission's final order.
Comments, protests and interventions may be filed electronically via the Internet in lieu of paper. See, 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's web site under the “e-Filing” link. The Commission strongly encourages electronic filings.
If the Commission decides to set the application for a formal hearing before an Administrative Law Judge, the Commission will issue another notice describing that process. At the end of the Commission's review process, a final Commission order approving or denying a certificate will be issued.
Take notice that on August 19, 2002, Great Lakes Gas Transmission Limited Partnership (Great Lakes) tendered for filing as part of its FERC Gas Tariff, Second Revised Volume No. 1, the tariff sheets listed on Appendix A to the filing, to be effective October 1, 2002.
Great Lakes states that these tariff sheets are being filed in compliance with the Commission's July 19, 2002 Order on Compliance with Order Nos. 637, 587-G, and 587-L in Docket Nos. RP00-329-000, RP00-606-000, and RP00-606-001 (July 19 Order). In the July 19 Order, the Commission found that pro forma tariff sheets filed by Great Lakes on June 15, 2000 in Docket No. RP00-329-000 generally complied with the requirements of Order No. 637, subject to certain modifications. The Commission also found that filings made by Great Lakes on September 29, 2000 and on November 27, 2000 in Docket Nos. RP00-606-000 and RP00-606-001, respectively, satisfactorily complied with Order Nos. 587-G and 587-L, and accepted these filings subject to certain modifications. Great Lakes was directed to file actual tariff sheets within thirty (30) days of the July 19 Order consistent with the Commission directives and modifications set forth in that Order.
Great Lakes is seeking clarification or rehearing of one requirement of the July 19 Order in a separate filing submitted on the same day as the instant filing. This compliance tariff filing includes actual tariff sheets that incorporate the required modifications, and the proposals and provisions approved by the Commission, with the exception of the modifications that are the subject of Great Lakes' request for clarification or rehearing.
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with section 385.211 of the Commission's Rules and Regulations. All such protests must be filed in accordance with section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
Take notice that on July 1, 2002, Iroquois Gas Transmission System, L.P. (Iroquois) tendered for filing its schedules which reflect calculations supporting the Measurement Variance/Fuel Use Factors utilized by Iroquois during the period January 1, 2002, through June 30, 2002.
Iroquois states that data from the data base during this period had to be verified to ensure accurate and complete information. Iroquois states that the schedules attached to the original filing include calculations supporting each of the three components of Iroquois' composite Measurement Variance/Fuel Use Factor
Any person desiring to be heard or to protest said filing should file a motion to intervene or a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Sections 385.214 or 385.211 of the Commission's Rules and Regulations. All such motions or protests must be filed on or before August 30, 2002. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
Take notice that on August 20, 2002, Midwestern Gas Transmission Company (Midwestern) tendered for filing and acceptance, a firm gas transportation agreement pursuant to Midwestern's Rate Schedule FT-A, Third Revised Sheet No. 7 and Third Revised Sheet No. 273 of Midwestern's FERC Gas Tariff, Third Revised Volume No. 1. The filing sets forth a negotiated rate, non-conforming firm gas transportation agreement between Midwestern and Mirant Americas Energy Marketing, LP (Mirant) that became effective July 1, 2002.
Midwestern states that copies of this filing have been sent to all of Midwestern's contracted shippers and interested state regulatory commissions.
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with section 385.211 of the Commission's Rules and Regulations. All such protests must be filed in accordance with section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
Take notice that on August 19, 2002, Northern Border Pipeline Company (Northern Border) tendered for filing to become part of its FERC Gas Tariff, First Revised Volume No. 1, the following tariff sheet:
Northern Border is filing the revised tariff sheet to comply with the Commission's order at Docket No. RP02-367-000 (100 FERC ¶ 61,125).
Northern Border states that copies of this filing have been sent to all of Northern Border's contracted shippers and interested state regulatory commissions.
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Section 385.211 of the Commission's Rules and Regulations. All such protests must be filed in accordance with section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
Take notice that on August 16, 2002, Petal Gas Storage, L.L.C. (Petal), tendered for filing Compliance Tariff Filing.
Petal's filing is in compliance with the Commission's May 31, 2002, Order regarding a Firm Transportation Service Agreement between Petal and Southern Company Services, Inc., which contains certain deviations from Petal's
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with section 385.211 of the Commission's Rules and Regulations. All such protests must be filed in accordance with Section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
Take notice that on August 19, 2002, PG&E Gas Transmission, Northwest Corporation (GTN) tendered for filing pro forma tariff sheets to modify its incremental fuel roll-down proposal in response to DEK Energy Company's (DEK) and PacifiCorp Power Marketing, Inc.'s (PPM) protests. Following the outcome of the Commission's review of both this filing and the May 1, 2002 filing, GTN will file actual tariff sheets with a November 1, 2002 effective date,
GTN further states that a copy of this filing has been served on GTN's jurisdictional customers and interested state regulatory agencies.
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with section 385.211 of the Commission's Rules and Regulations. All such protests must be filed in accordance with section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
Take notice that on August 15, 2002, Questar Pipeline Company (Questar) proposes that it be permitted to flow through $12,055 in take-or-pay costs to its former sale-for-resale customer Questar Gas Company (formerly Mountain Fuel Supply Company) under the provisions of 25 (Pipeline Supplier Take-or-Pay Buyout/Buydown Billing Recovery) that was terminated December 30, 1999, by Order issued December 22, 1999, in Docket No. RP00-87-000.
Alternatively, should the Commission determine that a specific tariff provision is required, Questar submits for filing and acceptance, pursuant to 18 CFR 154.7, the following tariff sheets to First Revised Volume No. 1 of its FERC Gas Tariff to be effective September 15, 2002:
Any person desiring to be heard or to protest said filing should file a motion to intervene or a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Sections 385.214 or 385.211 of the Commission's Rules and Regulations. All such motions or protests must be filed on or before August 30, 2002. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
On November 20, 2001,
Following issuance of the November 20 Order, the parties to the above-captioned proceedings as well as a number of other entities filed comments and/or requests for rehearing. Some commenters generally supported the SMA as an interim screen. Several filed in opposition to the SMA screen as a measure of market power. Some commenters argue that the Commission committed procedural error by replacing the hub-and-spoke analysis with the interim SMA through case-by-case adjudication, rather than through formal notice-and-comment rulemaking. On the merits, commenters protest, among other things, that the SMA is ill-suited for load-serving entities with capacity committed to serve native load, and that the test should look at uncommitted capacity and should serve only as a screen rather than a definitive analysis for granting market-based rate authority. Commenters also raise substantive and procedural arguments against the mitigation measures established in the November 20 Order, arguing that the mitigation measures are vague, unworkable and poorly tailored. Commenters also address the exemption from the SMA for sales into an RTO/ISO with Commission-approved market monitoring and mitigation. Some commenters oppose the exemption while others suggest the exemption should be expanded to include non-California portions of the WSCC and any market in which participants agree to be bound by an appropriate Commission-approved market monitoring and mitigation plan.
Consistent with our announcement that we would hold a technical conference open to all interested persons, not only parties in the above-captioned dockets, we are hereby establishing a proceeding, Docket No. PL02-8-000, Conference on Supply Margin Assessment Screen, to provide an opportunity for all interested persons to submit comments. In preparation for the technical conference (the date and time of which will be announced in a subsequent notice), the Commission invites all interested persons to submit written comments regarding the SMA screen and related mitigation measures. All comments should include an executive summary; the summary shall not exceed five pages. To conserve time and avoid unnecessary expense, persons with common interests or views are encouraged to submit joint comments. All written comments should be submitted within 60 days from the date of this order and will be placed in the Commission's public files. Comments will be available for inspection at the Commission's Public Reference Room, 888 First Street, NE., Washington DC, 20426, during regular business hours.
Such written comments should be submitted in Docket No. PL02-8-000. A technical conference to discuss the SMA and related mitigation measures will be scheduled on a date to be determined. All future actions with respect to the technical conference will also be taken under Docket No. PL02-8-000.
Comments, papers, or other documents related to this proceeding may be filed in paper format or electronically. However, the Commission strongly encourages electronic filings. Those filing electronically do not need to make a paper filing.
For paper filings, the original and 14 copies of the comments should be submitted to the Office of the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426 and should refer to Docket No. PL02-8-000
Documents filed electronically via the Internet must be prepared in WordPerfect, MS Word, Portable Document Format, or ASCII format. To file the document, access the Commission's website at
All comments will be placed in the Commission's public files and will be available for inspection in the Commission's Public Reference Room at 888 First Street, NE., Washington, DC 20426, during regular business hours. These comments will be available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
Take notice that on August 16, 2002, Tennessee Gas Pipeline Company (Tennessee), tendered for filing as part of its FERC Gas Tariff, Fifth Revised Volume No. 1, Third Revised Sheet No. 338, Fifth Revised Sheet No. 404, Eighth Revised Sheet No. 405, Ninth Revised Sheet No. 405A, Third Revised Sheet No. 405A.01, and Original Sheet No. 405A.02.
Tennessee states that these tariff sheets are being filed to implement more effective creditworthiness safeguards in Article XXVIII of the General Terms and Conditions (GT&C) of its FERC Gas Tariff. Tennessee submits that the revisions are intended to provide the necessary protections to Tennessee and its creditworthy and paying customers from the realistic potential of sudden changes in other customers' financial condition and payment status.
Additionally, Tennessee states that its revised provision will provide customers with the advantage of knowing the necessary requirements and available options for resuming service on Tennessee's system. Furthermore, Tennessee's revised creditworthiness evaluation provision will provide a customer, which loses its creditworthiness, with the flexibility to assess its options in advance and better determine an expedient course of action to limit its exposure. Tennessee requests that the foregoing tariff sheets be made effective on September 16, 2002.
Any person desiring to be heard or to protest said filing should file a motion to intervene or a protest with the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426, in accordance with Sections 385.214 or 385.211 of the Commission's Rules and Regulations. All such motions or protests must be filed in accordance with Section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
Take notice that on August 8, 2002, Tennessee Gas Pipeline Company (Tennessee), tendered for filing a clarification to its Negotiated Rate Tariff Filing of July 25, 2002.
Subsequent to its July 25 filing, Tennessee learned that Rhode Island State Energy Partners, L.P. (RISEP) had merged with Rhode Island State Statutory Energy Trust 2000 (Trust), with the Trust emerging as the surviving entity. Therefore, the negotiated rate arrangement filed on July 25, 2002 is with the Trust and not with RISEP.
Any person desiring to be heard or to protest said filing should file a motion to intervene or a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Sections 385.214 or 385.211 of the Commission's Rules and Regulations. All such motions or protests must be filed on or before August 30, 2002. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
Take notice that on August 15, 2002, Tennessee Gas Pipeline Company (Tennessee), tendered for filing its Negotiated Rate Tariff Filing.
Tennessee's filing requests that the Commission approve a corrected negotiated rate arrangement between Tennessee and Cincinnati Gas & Electric Company. Tennessee requests that the Commission grant such approval effective August 1, 2002.
Any person desiring to be heard or to protest said filing should file a motion to intervene or a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with sections 385.214 or 385.211 of the Commission's Rules and Regulations. All such motions or protests must be filed in accordance with section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
Take notice that on August 16, 2002 Texas Gas Transmission Corporation (Texas Gas) tendered for filing as part of its FERC Gas Tariff, Original Volume No. 1, the following tariff sheets to become effective August 1, 2001:
Texas Gas is submitting these tariff sheets as a part of an errata filing to correct two inadvertent errors in its previous July 29, 2002 compliance filing containing tariff sheets to implement the settlement agreed to and approved in Docket No. RP00-260,
Texas Gas states that copies of the revised tariff sheets are being mailed to Texas Gas's jurisdictional customers and interested state commissions.
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with section 385.211 of the Commission's Rules and Regulations. All such protests must be filed in accordance with section 154.210 of the Commission's Regulations. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
Take notice that on August 15, 2002, Transcontinental Gas Pipe Line Corporation (Transco) tendered for filing a refund report showing that on August 14, 2002, Tansco submitted a report reflecting the flow through of a refund received from Dominion Transmission, Inc.
Transco states that it refunded to its FTNT customer, New York Power Authority, $2,032.67 resulting from the refund of Dominion Transmission, Inc. Annual Overrun/Penalty Revenue Distribution. Transco states that the refund covers the time period from September 1, 2002 to March 31, 2002.
Any person desiring to be heard or to protest said filing should file a motion to intervene or a protest with the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426, in accordance with Sections 385.214 or 385.211 of the Commission's Rules and Regulations. All such motions or protests must be filed on or before August 30, 2002. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. Any person wishing to become a party must file a motion to intervene. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
Take notice that on August 16, 2002, Williams Gas Pipelines Central, Inc. (Williams) tendered for filing as part of its FERC Gas Tariff, Original Volume No. 1, the tariff sheets listed on Appendix A to the filing, to become effective September 1, 2002.
Williams states that the tariff sheets are identical to the tariff sheets filed initially on March 1, 2002 to transition Williams from a monthly allocation pipeline to a daily allocation pipeline. On March 28, 2002, the Commission issued an order accepting the proposed tariff sheets and suspending their effective date until September 1, 2002, subject to refund and to the outcome of Williams' Order No. 637 proceeding in Docket No. RP00-494.
As Williams reserved its right to move the suspended sheets into effect through its March 1, 2002 filing, Williams hereby exercises its reserved rights and with the instant filing, moves the suspended tariff sheets into effect on September 1, 2002, consistent with the Suspension Order.
Williams states that copies of the revised tariff sheets are being mailed to Williams' jurisdictional customers and interested state commissions, as well as those appearing on the official service list for this docket.
Any person desiring to protest said filing should file a protest with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with section 385.211 of the Commission's Rules and Regulations. All such protests must be filed on or before August 30, 3002. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceedings. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
The following filings have been made with the Commission. The filings are listed in ascending order within each docket classification.
Take notice that on August 19, 2002, Pacific Gas and Electric Company (PG&E) and the Modesto Irrigation District (Modesto) tendered for filing a Further Request for Deferral of Consideration of the unexecuted Wholesale Distribution Tariff (WDT) Service Agreement and Interconnection Agreement between Pacific Gas and Electric Company and Modesto Irrigation District filed in FERC Docket No. ER01-833-000 on December 29, 2000. PG&E and Modesto are finalizing the agreements for review and signature, and PG&E therefore is notifying the Commission that executed agreements will not be filed by August 26, 2002, the requested deferral date. PG&E requests that the Commission defer consideration of the proceedings filed in ER01-833-000 to August 26, 2003, 365 days beyond the last request for Deferral in order that the parties may finalize and execute the Agreements.
Copies of this filing have been served upon Modesto, the California Independent System Operator Corporation, and the California Public Utilities Commission.
Take notice that on August 19, 2002, Duke Energy New Smyrna Beach Power Company Ltd., L.L.P. tendered for filing a Notice of Cancellation pursuant to 18 CFR 35.15 (2001), in order to reflect the cancellation of its Market-Based Rate Tariff, designated as Rate Schedule FERC No. 1, and Transmission Capacity Reassignment Tariff, designated as Rate Schedule FERC No. 2, originally accepted for filing in Docket No. ER98-2624-000.
Take notice that on August 19, 2002, pursuant to section 205 of the Federal Power Act and section 35.12 of the Commission's regulations, 18 CFR 35.12 (2001), the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) submitted for filing an Interconnection and Operating Agreement among the City of Perham, Minnesota, the Midwest ISO and Otter Tail Power Company.
A copy of this filing was sent to the City of Perham, Minnesota and Otter Tail Power Company.
Take notice that on August 19, 2002 The Dayton Power and Light Company (Dayton) submitted a service agreement establishing Calpine Energy Services L.P. as a customer under the terms of Dayton's FERC Electric Tariff, Original Volume No. 10.
Dayton requests an effective date of one day subsequent to this filing for the service agreements. Accordingly, Dayton requests waiver of the Commission's notice requirements. Copies of this filing were served upon Calpine Energy Services, L.P. and the Public Utilities Commission of Ohio.
Take notice that on August 19, 2002, Pacific Gas and Electric Company (PG&E) tendered for filing proposed changes in rates for Sacramento Municipal Utility District (SMUD), to be effective July 1, 2002, developed using a rate adjustment mechanism previously agreed by PG&E and SMUD for First Revised PG&E Rate Schedule FERC Nos. 88, 91, and 136.
Copies of this filing have been served upon SMUD, the California Independent System Operator Corporation, and the California Public Utilities Commission.
Take notice that on August 19, 2002, Chattahoochee EMC tendered for filing
This filing consists of the Power Purchase Agreements, dated as of November 1, 2001, between Chattahoochee EMC and each of its 28 member distribution cooperatives (the Members) pursuant to which Chattahoochee EMC will sell power and/or energy to those Members. Chattahoochee EMC is seeking waivers of certain Commission requirements as part of this filing.
Copies of the filing were served upon Altamaha Electric Membership Corporation, Amicalola Electric Membership Corporation, Canoochee Electric Membership Corporation, Carroll Electric Membership Corporation, Central Georgia Electric Membership Corporation, Coastal Electric Membership Corporation, d/b/a Coastal Electric Cooperative, Coweta-Fayette Electric Membership Corporation, Excelsior Electric Membership Corporation, Flint Electric Membership Corporation, d/b/a Flint Energies, GreyStone Power Corporation, An Electric Membership Corporation, Habersham Electric Membership Corporation, Hart Electric Membership Corporation, Irwin Electric Membership Corporation, Jackson Electric Membership Corporation, Lamar Electric Membership Corporation, Little Ocmulgee Electric Membership Corporation, Middle Georgia Electric Membership Corporation, Mitchell Electric Membership Corporation, Ocmulgee Electric Membership Corporation, Oconee Electric Membership Corporation, Okefenoke Rural Electric Membership Corporation, Planters Electric Membership Corporation, Rayle Electric Membership Corporation, Sawnee Electric Membership Corporation, Slash Pine Electric Membership Corporation, Sumter Electric Membership Corporation, Tri-County Electric Membership Corporation, and Upson County Electric Membership Corporation.
Take notice that on August 19, 2002, Southern Company Services, Inc., acting on behalf of Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company (collectively, Southern Companies), filed Revision No. 2 to the Agreement for Network Integration Transmission Service for Tennessee Valley Authority under Southern Companies' Open Access Transmission Tariff to Add a Delivery Point. Revision No. 2 provides that transmission service under the referenced service agreement (Service Agreement No. 160) under Southern Companies' Open Access Transmission Tariff (FERC Electric Tariff, Fourth Revised Volume No. 5) (Tariff) is to be provided at one (1) new delivery point, and it specifies the direct assignment facilities charge as well as the distribution facilities charge associated with the new delivery point.
Take notice that on August 16, 2002, ISO New England (the ISO) tendered for filing with the Federal Energy Regulatory Commission (Commission) a Market Report for Quarter 3.
E. Any person desiring to intervene or to protest this filing should file with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. All such motions or protests should be filed on or before the comment date, and, to the extent applicable, must be served on the applicant and on any other person designated on the official service list. This filing is available for review at the Commission or may be viewed on the Commission's web site at
The following filings have been made with the Commission. The filings are listed in ascending order within each docket classification.
Take notice that on August 16, 2002, UAE Lowell Power LLC tendered for filing their triennial market power updates in support of authorization to engage in wholesale sales of electric energy at market-based rates.
Take notice that on August 13, 2002, Neptune Regional Transmission System, LLC (Neptune), filed with the Federal Energy Regulatory Commission (Commission), a motion to modify certain provisions of the Commission's orders in the proceeding in Docket No. ER01-2099-000: Neptune Regional Transmission System, LLC, 96 FERC ¶ 61,147 (2001), order on reh'g, 96 FERC ¶ 61,326 (2001), order on clarification, 98 FERC ¶ 61,140 (2002).
Neptune requests that the Commission amend its prior orders to permit Neptune to negotiate to sell long-term Transmission Scheduling Rights (TSRs) outside of an open season process, that the Commission permit affiliate participation in the initial allocation or sale of TSRs as well as in the secondary market for TSRs, and that the Commission clarify that the deadline for recalling TSRs lost in the “use it or lose it” process can be identical to the deadline under the Standard Market Design tariff for changing transmission schedules.
Neptune claims that the open season process is impractical and unnecessary to achieving Commission goals, that there are no market power concerns present with respect to allowing affiliate participation in the initial allocation or sale of TSRs, that the open season requirement and affiliate restrictions are inconsistent with the Commission's Standard Market Design, and that TSR holders should be allowed to exercise their recall rights within the same time-frames as a market participant would be
Take notice that on August 16, 2002, Boston Edison Company (BECo), in compliance with the Federal Energy Regulatory Commission's (Commission) Order dated March 15, 2002 and in accordance with its own letter to the Commission dated July 18, 2002 tendered a further compliance filing relative to its Rate Schedule No. 167 for service to the Town of Wellesley, Massachusetts. The tendered compliance filing is intended to replace BECo's prior compliance filing dated July 9, 2002. BECo requests and May 31, 2002 effective date.
Copies of the filing were served upon the Town of Wellesley, Massachusetts, and the Massachusetts Department of Telecommunications and Energy.
Take notice that on August 19, 2002, the American Electric Power Service Corporation (AEPSC) tendered for filing an Amended Interconnection and Parallel Operation Agreement between Southwestern Electric Power Company (SWEPCO), Entergy Power Ventures, L.P., Northeast Texas Electric Cooperative, Inc., and EN Services, L.P., in compliance with the Order Conditionally Accepting for Filing Interconnection Agreement, as Modified, and Directing Compliance Filing, Dockets Nos. ER02-711-000, 001, issued July 19, 2002. The agreement is pursuant to the AEP Companies' Open Access Transmission Service Tariff (OATT) that has been designated as the Operating Companies of the American Electric Power System FERC Electric Tariff Second Revised Volume No. 6, effective June 15, 2000.
SWEPCO requests an effective date of March 5, 2002. Copies of SWEPCO's filing have been served upon Entergy Power ventures, LP, Northeast Texas Electric Cooperative, Inc., EN Services, L.P. and the Public Utility Commission of Texas.
Take notice that on August 16, 2002, Nevada Power Company (Nevada Power) tendered for filing its compliance filing making the changes to the unexecuted Interconnection and Operation Agreement between Nevada Power and Gen West, LLC required by the Federal Energy Regulatory Commission's July 19, 2002 Order in this docket.
Take notice that on August 19, 2002, Virginia Electric and Power Company d/b/a/ Dominion Virginia Power supplemented its initial July 29, 2002 filing in this matter, filing revised tariff sheets to revise a job title set forth in Attachment N to Virginia Electric and Power Company's FERC Electric Tariff, Second Revised Volume No. 5 (OATT) addressing Dominion Virginia Power's Generator Interconnection Procedures.
Dominion Virginia Power requests that the revised tariff sheets become effective on August 20, 2002.
Take notice that on August 15, 2002, Niagara Mohawk Power Corporation (Niagara Mohawk) tendered for filing its Second Refund Report in the above-referenced proceeding in conformance with the requirements of the July 2, 2002 Order of the Federal Energy Regulatory Commission (Commission) in this proceeding.
Copies of the filing have been served on all parties listed on the official service list maintained by the Commission for this proceeding.
E. Any person desiring to intervene or to protest this filing should file with the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. All such motions or protests should be filed on or before the comment date, and, to the extent applicable, must be served on the applicant and on any other person designated on the official service list. This filing is available for review at the Commission or may be viewed on the Commission's web site at
The staff of the Federal Energy Regulatory Commission (FERC or Commission) has prepared a Draft Environmental Impact Statement (DEIS) on the natural gas pipeline facilities proposed by Iroquois Gas Transmission System, L.P. (Iroquois) in the above-referenced docket.
The DEIS was prepared to satisfy the requirements of the National Environmental Policy Act. The staff concludes that approval of the proposed project with the appropriate mitigating measures as recommended, would have limited adverse environmental impact. The DEIS also evaluates alternatives to the proposal, including system alternatives; major route alternatives; and route variations, and requests comments on them.
The DEIS addresses the potential environmental effects of the construction and operation of the following facilities:
• 29.1 miles of 20-inch-diameter pipeline in New Haven County, Connecticut, and Suffolk County, New York;
• a new meter station along the proposed ELI pipeline at about milepost (MP) 29.1;
• ancillary facilities including a marine tap interconnection and facilities for the attachment of a pig launcher in Long Island Sound in Connecticut state waters; three mainline valves (MPs 17.5, 22.7, and 29.1), and one pig receiving facility housed within the meter station layout at the project terminus at MP 29.1;
• a new 20,000 horsepower compressor station at Iroquois' existing
• new piping, compressor and piping modifications, and ancillary facilities to accept natural gas from the Algonquin Gas Transmission (AGT) Company's AGT System at a proposed new Iroquois compressor station in Brookfield, Fairfield County, Connecticut (note: Iroquois is currently pursuing a separate FERC Certificate for the compressor station under Docket No. CP02-31-000);
• a discharge gas cooler to be added to the proposed new compressor station in Dover, Duchess County, New York (note: Iroquois received a separate FERC Certificate for the compressor station under Docket Nos. CP00-232-000 and -001, but has not built this facility yet); and
• temporary pipe and storage yards, staging areas, access roads, etc., to be used only during construction of the proposed facilities.
The purpose of the proposed facilities would be to transport about 175,000 dekatherms per day of firm transportation service to expanding markets on Long Island, New York.
Any person wishing to comment on the DEIS may do so. To ensure consideration prior to a Commission decision on the proposal, it is important that we receive your comments before the date specified below. Please carefully follow these instructions to ensure that your comments are received in time and properly recorded:
• Send an original and two copies of your comments to: Secretary, Federal Energy Regulatory Commission, 888 First St., NE., Room 1A,
Washington, DC 20426;
• Label one copy of the comments for the attention of Gas Branch 2, PJ11.2
• Reference Docket No. CP02-52-000; and
• Mail your comments so that they will be received in Washington, DC on or before October 18, 2002.
Please note that we are continuing to experience delays in mail deliveries from the U.S. Postal Service. As a result, we will include all comments that we receive within a reasonable time frame in our environmental analysis of this project. Also, the Commission encourages electronic filing of any comments or interventions or protests to this proceeding. See 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's web site at
We will announce in a future notice, the location and time of at least one local public meeting to receive comments on the DEIS.
After these comments are reviewed, any significant new issues are investigated, and modifications are made to the DEIS, a Final Environmental Impact Statement (FEIS) will be published and distributed by the staff. The FEIS will contain the staff's responses to timely comments filed on the DEIS.
Comments will be considered by the Commission but will not serve to make the commentor a party to the proceeding. Any person seeking to become a party to the proceeding must file a motion to intervene pursuant to Rule 214 of the Commission's Rules of Practice and Procedures (18 CFR 385.214).
Anyone may intervene in this proceeding based on this DEIS. You must file your request to intervene as specified above.
The DEIS has been placed in the public files of the FERC and is available for distribution and public inspection at: Federal Energy Regulatory Commission, Public Reference and Files Maintenance Branch, 888 First Street, NE., Room 2A, Washington, DC 20426, (202) 502-8371.
A limited number of copies are available from the Public Reference and Files Maintenance Branch identified above. In addition, copies of the DEIS have been mailed to Federal, State and local agencies, public interest groups, individuals who have requested the DEIS, newspapers, and parties to this proceeding.
Additional information about the proposed project is available from the Commission's Office of External Affairs, at 1-866-208-FERC (3372) or on the FERC Internet website (www.ferc.gov) using the “FERRIS” link to information in this docket number.
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection:
a.
b.
c.
d.
e.
f.
g.
h.
i.
All documents (original and eight copies) should be filed with Magalie R. Salas, Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. Comments, protests, and interventions may be filed electronically via the Internet in lieu of paper; see 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's web site under the “e-Filing” link. The Commission strongly encourages electronic filings. Please include the project number (P-
The Commission's Rules of Practice and Procedure require all interveners filing documents with the Commission to serve a copy of that document on each person in the official service list for the project. Further, if an intervener files comments or documents with the Commission relating to the merits of an issue that may affect the responsibilities of a particular resource agency, they must also serve a copy of the document on that resource agency.
j.
The project would have an estimated annual generation of 21.7 GWH.
k. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
l. Preliminary Permit—Anyone desiring to file a competing application for preliminary permit for a proposed project must submit the competing application itself, or a notice of intent to file such an application, to the Commission on or before the specified comment date for the particular application (see 18 CFR 4.36). Submission of a timely notice of intent allows an interested person to file the competing preliminary permit application no later than 30 days after the specified comment date for the particular application. A competing preliminary permit application must conform with 18 CFR 4.30(b) and 4.36.
m. Preliminary Permit—Any qualified development applicant desiring to file a competing development application must submit to the Commission, on or before a specified comment date for the particular application, either a competing development application or a notice of intent to file such an application. Submission of a timely notice of intent to file a development application allows an interested person to file the competing application no later than 120 days after the specified comment date for the particular application. A competing license application must conform with 18 CFR 4.30(b) and 4.36.
n. Notice of Intent—A notice of intent must specify the exact name, business address, and telephone number of the prospective applicant, and must include an unequivocal statement of intent to submit, if such an application may be filed, either a preliminary permit application or a development application (specify which type of application). A notice of intent must be served on the applicant(s) named in this public notice.
o. Proposed Scope of Studies under Permit—A preliminary permit, if issued, does not authorize construction. The term of the proposed preliminary permit would be 36 months. The work proposed under the preliminary permit would include economic analysis, preparation of preliminary engineering plans, and a study of environmental impacts. Based on the results of these studies, the Applicant would decide whether to proceed with the preparation of a development application to construct and operate the project.
p. Comments, Protests, or Motions to Intervene—Anyone may submit comments, a protest, or a motion to intervene in accordance with the requirements of Rules of Practice and Procedure, 18 CFR 385.210, .211, .214. In determining the appropriate action to take, the Commission will consider all protests or other comments filed, but only those who file a motion to intervene in accordance with the Commission's Rules may become a party to the proceeding. Any comments, protests, or motions to intervene must be received on or before the specified comment date for the particular application.
q. Filing and Service of Responsive Documents—Any filings must bear in all capital letters the title “COMMENTS”, “NOTICE OF INTENT TO FILE COMPETING APPLICATION”, “COMPETING APPLICATION”, “PROTEST”, “MOTION TO INTERVENE”, as applicable, and the Project Number of the particular application to which the filing refers. Any of the above-named documents must be filed by providing the original and the number of copies provided by the Commission's regulations to: The Secretary, Federal Energy Regulatory Commission, 888 First Street, NE,Washington, DC 20426. An additional copy must be sent to Director, Division of Hydropower Administration and Compliance, Federal Energy Regulatory Commission, at the above-mentioned address. A copy of any notice of intent, competing application or motion to intervene must also be served upon each representative of the Applicant specified in the particular application.
r. Agency Comments—Federal, state, and local agencies are invited to file comments on the described application. A copy of the application may be obtained by agencies directly from the Applicant. If an agency does not file comments within the time specified for filing comments, it will be presumed to have no comments. One copy of an agency's comments must also be sent to the Applicant's representatives.
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection:
a.
b.
c.
f.
h.
i.
All documents (original and eight copies) should be filed with Magalie R. Salas, Secretary, Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426. Comments, protests, and interventions
The Commission's Rules of Practice and Procedure require all interveners filing documents with the Commission to serve a copy of that document on each person in the official service list for the project. Further, if an intervener files comments or documents with the Commission relating to the merits of an issue that may affect the responsibilities of a particular resource agency, they must also serve a copy of the document on that resource agency.
j.
The project would have an estimated annual generation of 5 GWH.
k. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
l.
m.
n.
o.
p.
q.
r.
Take notice that the following hydroelectric application has been filed with the Commission and is available for public inspection:
a.
b.
c.
d.
e.
f.
g.
h.
i.
All documents (original and eight copies) should be filed with Magalie R. Salas, Secretary, Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426. Comments, protests, and interventions may be filed electronically via the Internet in lieu of paper; see 18 CFR 385.2001(a)(1)(iii) and the instructions on the Commission's web site under the “e-Filing” link. The Commission strongly encourages electronic filings. Please include the project number (P-12216-000) on any comments or motions filed.
The Commission's Rules of Practice and Procedure require all interveners filing documents with the Commission to serve a copy of that document on each person in the official service list for the project. Further, if an intervener files comments or documents with the Commission relating to the merits of an issue that may affect the responsibilities of a particular resource agency, they must also serve a copy of the document on that resource agency.
j.
The project would have an estimated annual generation of 2.9 GWH.
k. This filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website at
l.
m.
n.
o.
p.
q.
r.
Pursuant to Rule 601 of the Commission's Rules of Practice and Procedure, 18 CFR 385.601, the Dispute Resolution Service will convene a Conference on Wednesday and Thursday, August 28th and 29th, 2002, to discuss how Alternative Dispute Resolution processes and procedures may assist the participants in resolving disputes arising in the above-docketed proceeding. The conference will be held at the Southern Natural Gas Company, 1900 Fifth Avenue., North, Birmingham, AL. (205)325-3854, beginning at 9 a.m. on August 28 and ending at approximately 5 p.m. on August 29.
Steven A. Shapiro and Deborah Osborne, acting for the Dispute
Take notice that an informal settlement conference will be convened in this proceeding commencing at 10 am on September 4th and 5th, 2002, at the offices of the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC, 20426, for the purpose of exploring the possible settlement of the above-referenced dockets.
Any party, as defined by 18 CFR 385.102(c), or any participant as defined by 18 CFR 385.102(b), is invited to attend. Persons wishing to become a party must move to intervene and receive intervenor status pursuant to the Commission's regulations (18 CFR 385.214).
For additional information, please contact or Thomas J. Burgess (202) 502-6058 or Dawn K. Martin (202) 502-8661.
The Federal Communications Commission, as part of its continuing effort to reduce paperwork burden invites the general public and other Federal agencies to take this opportunity to comment on the following information collection(s), as required by the Paperwork Reduction Act of 1995, Public Law 104-13. An agency may not conduct or sponsor a collection of information unless it displays a currently valid control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act (PRA) that does not display a valid control number. Comments are requested concerning (a) whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's burden estimate; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology.
Written comments should be submitted on or before October 28, 2002. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contact listed below as soon as possible.
Direct all comments to Judith Boley Herman or Leslie Smith, Federal Communications Commission, Room 1-C804 or Room 1-A804, 445 12th Street, SW., Washington, DC 20554 or via the Internet to
For additional information or copies of the information collection(s), contact Judith Boley Herman at 202-418-0214 or via the Internet at
The Commission is revising this information collection to include and gather information from other services.
The Federal Communications Commission, as part of its continuing effort to reduce paperwork burden invites the general public and other Federal agencies to take this opportunity to comment on the following information collection(s), as required by the Paperwork Reduction Act of 1995, Public Law 104-13. An agency may not conduct or sponsor a collection of information unless it displays a currently valid control number. No person shall be subject to any penalty for failing to comply with a collection of information subject to the Paperwork Reduction Act (PRA) that does not display a valid control number. Comments are requested concerning (a) whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's burden estimate; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of
Persons wishing to comment on this information collection should submit comments October 28, 2002. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contact listed below as soon as possible.
Direct all comments to Judy Boley Herman, Federal Communications Commission, 445 12th Street, SW., Room 1-C804, Washington, DC 20554 or via the internet to
For additional information or copies of the information collections contact Judy Boley Herman at 202-418-0214 or via the internet at
Federal Communications Commission.
Federal Supply Service, GSA.
Notice of final issuance of the GSA Non-Express Small Package Tender of Service.
The General Services Administration (GSA), in compliance with 41 U.S.C. 418b, is publishing the GSA Non-Express Small Package Tender of Service (SPTOS) which may be accessed as described in the Supplementary Information of this notice. The SPTOS establishes a uniform basis for buying routine non-express small package transportation service. GSA's solicitation and acceptance of small package rates and charges provides highly competitive pricing, which in certain cases includes the solicitation and acceptance of rates specific to an individual agency that accommodate that agency's particular traffic characteristics. GSA's Federal customer agencies benefit from the SPTOS, which leverages the Government's buying power to provide agencies standardized, cost effective, non-express small package transportation services.
August 29, 2002.
Mr. Raymond Price, Transportation Program Branch by phone 703-305-7536 or by e-mail at
The SPTOS was published in the
Centers for Medicare and Medicaid Services, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Centers for Medicare and Medicaid Services (CMS) (formerly known as the Health Care Financing Administration (HCFA), Department of Health and Human Services, is publishing the following summary of proposed collections for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, access CMS Web Site address at
Centers for Medicare and Medicaid Services, HHS.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Centers for Medicare and Medicaid Services (CMS) (formerly known as the Health Care Financing Administration (HCFA), Department of Health and Human Services, is publishing the following summary of proposed collections for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, access CMS Web Site address at
Centers for Medicare and Medicaid Services.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Centers for Medicare and Medicaid Services (CMS) (formerly known as the Health Care Financing Administration (HCFA), Department of Health and Human Services, is publishing the following summary of proposed collections for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, access CMS Web site address at
Centers for Medicare and Medicaid Services.
In compliance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Centers for Medicare and Medicaid Services (CMS) (formerly known as the Health Care Financing Administration (HCFA), Department of Health and Human Services, is publishing the following summary of proposed collections for public comment. Interested persons are invited to send comments regarding this burden estimate or any other aspect of this collection of information, including any of the following subjects: (1) The necessity and utility of the proposed information collection for the proper performance of the agency's functions; (2) the accuracy of the estimated burden; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
To obtain copies of the supporting statement and any related forms for the proposed paperwork collections referenced above, access CMS Web site address at
OMB Human Resources and Housing Branch, Attention: Brenda Aguilar, New Executive Office Building, Room 10235, Washington, DC 20503.
In compliance with the requirement for opportunity for public comment on proposed data collection projects (section 3506(c)(2)(A) of Title 44, United States Code, as amended by the Paperwork Reduction Act of 1995, Pub. L. 104-13), the Health Resources and Services Administration (HRSA) publishes periodic summaries of proposed projects being developed for submission to OMB under the Paperwork Reduction Act of 1995. To request more information on the proposed project or to obtain a copy of the data collection plans and draft instruments, call the HRSA Reports Clearance Officer on (301) 443-1129.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology.
The HRSA, Office of Special Programs (OSP), Division of Transplantation (DoT) is planning a study to identify and evaluate practices related to organ procurement organization (OPO) and hospital structures and processes associated with high rates of organ donation. The study sample will include nine OPOs and 54 affiliated hospitals. (The OPO sample will be chosen first, followed by a corresponding sample of hospitals that have affiliations with the chosen OPOs.)
The study consists of two phases, of which only Phase 2 will require OMB Clearance. Phase 1 will involve an examination of secondary data sources to obtain descriptive information on the universe of OPOs and a subset of hospitals that have the potential for organ procurement activities. Phase 2 will involve data collection from more than nine hospitals through surveys and site visits to identify practices of OPO, hospital, and OPO-hospital interactions that are associated with higher rates of organ donation.
Hospitals included in the sample are likely to be, though not necessarily limited to, those with Trauma I and II designations, because the majority of organ donations occur in these types of hospitals. Data collection instruments for the hospital sample will include: (1)
The
The data collected will provide HRSA with a better understanding of the structural characteristics and practices of OPOs and hospitals associated with higher rates of referrals, consent, organ recovery, and organs transplanted. Results will inform future research, policy, and practice aimed at improving rates of organ donation as emphasized by U.S. Department of Health and Human Services Secretary Tommy G. Thompson's Gift of Life Initiative.
Send comments to Susan G. Queen, Ph.D., HRSA Reports Clearance Officer, Room 11A-33, Parklawn Building, 5600 Fishers Lane, Rockville, MD 20857. Written comments should be received within 60 days of this notice.
National Institutes of Health, Public Health Service, DHHS.
Notice.
The inventions listed below are owned by agencies of the U.S. Government and are available for licensing in the U.S. in accordance with 35 U.S.C. 207 to achieve expeditious commercialization of results of federally-funded research and development. Foreign patent applications are filed on selected inventions to extend market coverage for companies and may also be available for licensing.
Licensing information and copies of the U.S. patent applications listed below may be obtained by writing to the indicated licensing contact at the Office of Technology Transfer, National Institutes of Health, 6011 Executive Boulevard, Suite 325, Rockville, Maryland 20852-3804; telephone: 301/496-7057; fax: 301/402-0220. A signed Confidential Disclosure Agreement will be required to receive copies of the patent applications.
This invention provides: (1) Isolated and purified antiviral peptides or antiviral proteins named Scytovirins isolated and purified from aqueous extracts derived from the cyanobacteria, Scytonema varium; (2) an antibody which binds an epitope of Scytovirin isolated and purified from Scytonema varium; (3) a purified nucleic acid molecule that comprises a sequence which encodes an amino acid sequence homologous to Scytovirin; (4) a vector comprising the isolated and purified nucleic acid molecule and a host cell or organism comprising the vector; (5) a conjugate comprising the peptide and an effector component; and (6) a method of inhibiting prophylactically and therapeutically a viral infection. Thus, this invention may represent potential new therapeutics for treatment of retroviral infections, including AIDS.
Hair loss (alopecia) is a condition that afflicts millions of men and women. Countless therapies and concoctions have been devised to battle the effects of receding hairlines. None of these are universally effective, and many have met with, at best, dubious success.
The present invention provides the basis for the development of a safe and effective treatment for hair loss. It describes the novel use of naturally occurring, actin-binding, peptides to activate hair follicles. In animal studies, topical application of such peptides increased the number of active hair follicles at least two-fold. After application three times a week, new hair growth was observed as early as on day 7, and was retained with additional applications. This invention may lead to a treatment for a condition that affects a large percentage of the population.
Many Americans die each year of congestive heart failure occurring from a variety of causes including cardiomyopathy, myocardial ischemia, congenital heart disease and valvular heart disease resulting in cardiac cell death and myocardial dysfunction. As cardiomyocytes are not replaced in adult myocardial tissue, physiologic demands on existing, healthy cardiomyocytes leads to their hypertrophy. Heart transplants have been the only recourse for patients in end-stage heart disease however this is complicated by lack of donors, tissue incompatibility and high cost.
An alternative approach to heart transplantation is to generate cardiomyocytes from stem cells
This invention discloses a novel isolated population of stem cells, called
The subject invention is directed to the cDNA sequence and the deduced amino acid sequence of the human Maxp1 gene. Maxp1 is frequently down-regulated in primary human tumors. Accordingly, a vector comprising the cDNA sequence, a host cell comprising such a vector, a method of using the vector, such as one comprising a cDNA sequence in which the C-terminal Ras binding site has been mutated or deleted, or the polypeptide (or fragment thereof, such as one in which the C-terminal Ras binding site has been mutated or deleted) in the prophylactic and therapeutic treatment of cancer, a method of assaying small molecules for the ability to stimulate Maxp1 growth inhibitory function in cancer cells that remain positive for Maxp1 expression, and the assessment of the levels of Maxp1 mRNA or protein in the diagnosis, characterization and prognosis of cancer are additional, non-limiting embodiments of the invention.
Further embodiments include: (a) Diagnosis and prediction of tumor characteristics, (b) gene therapy to restore Nore1/Maxp1 function in tumor cells which have lost protein expression, (c) the use of small molecules to simulate Nore1/Maxp1 growth inhibitory function in tumor cells which remain positive for Nore1/Maxp1 expression, (d) the use of protein fragments/small molecules based on Nore1/Maxp1 structure to bind and inhibit the function of mutant Ras oncoproteins, and (e) a specific polyclonal antibody that works in westerns and in immunohistochemistry.
Notice is hereby given of the cancellation of the National Cancer Institute Director's Consumer Liaison Group, September 5, 2002, 2 p.m. to September 5, 2002, 4 p.m., 6116 Executive Blvd, Rockville, MD, 20852 which was published in the
The meeting is cancelled due to scheduling conflicts.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the meeting of the President's Cancer Panel.
The meeting will be closed to the public in accordance with the provisions set forth in section 552b(c)(9)(B), Title 5 U.S.C., as amended because the premature disclosure of information and the discussions would likely to significantly frustrate implementation of recommendations.
Any interested person may file written comments with the committee by forwarding the statement to the Contact Person listed on this notice. The statement should include the name, address, telephone number and when applicable, the business or professional affiliation of the interested person.
Information is also available on the Institute's/Center's home page:
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of a meeting of the National Eye Advisory Eye Council.
The meeting will be opened to the public as indicated below, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of th emeeting.
The meeting will be closed to the public in accordance with the provisions set forth in section 552b(c)(9)(B), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Information is also available on the Institute's/Center's home page:
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of a meeting of the National Advisory Council on Alcohol Abuse and Alcoholism.
The meeting will be open to the public as indicated below, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and/or contract proposals and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications and/or contract proposals, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Information is also available on the Institute's/Center's home page; silk.nih.gov/silk/niaaa1/about/roster.htm, where an agenda and any additional information for the meeting will be posted when available.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of a meeting of the National Advisory Dental and Craniofacial Research Council.
The meeting will be open to the public as indicated below, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and/or contract proposals and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications and/or contract proposals, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Information is also available on the Institute's/Center's home page:
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of a meeting of the National Advisory Child Health and Human Development Council.
The meeting will be open to the public as indicated below, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
In the interest of security, NIH has instituted stringent procedures for entrance into the building by non-government employees. Persons without a government I.D. will need to show a photo I.D. and sign-in at the security desk upon entering the building.
Information is also available on the Institute's/Center's home page:
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The contract proposals and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the contract proposals, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The contract proposals and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the contract proposals, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the
Pursuant to section 10(a) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of a meeting of the Recombinant DNA Advisory Committee.
The meeting will be open to the public, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting.
In the interest of security, NIH has instituted stringent procedures for entrance into the building by non-government employees. Persons without a government I.D. will need to show a photo I.D. and sign-in at the security desk upon entering the building.
Information is also available on the Institute's/Center's home page:
OMB's “Mandatory Information Requirements for Federal Assistance Program Announcements” (45 FR 39592, June 11, 1980) requires a statement concerning the official government programs contained in the Catalog of Federal Domestic Assistance. Normally NIH lists in its announcements the number and title of affected individual programs for the guidance of the public. Because the guidance in this notice covers virtually every NIH and Federal research program in which DNA recombinant molecule techniques could be used, it has been determined not to be cost effective or in the public interest to attempt to list these programs. Such a list would likely require several additional pages. In addition, NIH could not be certain that every Federal program would be included as many Federal agencies, as well as private organizations, both national and international, have elected to follow the NIH Guidelines. In lieu of the individual program listing, NIH invites readers to direct questions to the information address above about whether individual programs listed in the Catalog of Federal Domestic Assistance are affected.
National Institutes of Health, Public Health Service, DHHS.
Notice.
This is notice, in accordance with 35 U.S.C. 209(c)(1) and 37 CFR 404.7(a)(1)(i), that the National Institutes of Health (NIH), Department of Health and Human Services, is contemplating the grant of an exclusive license worldwide to practice the invention embodied in: U.S. Patent Application Serial No. 60/334,130, filed November 30, 2001, entitled, “P2X
Only written comments and/or application for a license, which are received by the NIH Office of Technology Transfer on or before October 28, 2002 will be considered.
Requests for a copy of the patent applications, inquiries, comments and other materials relating to the contemplated license should be directed to: Marlene Shinn, Technology Licensing Specialist, Office of Technology Transfer, National Institutes of Health, 6011 Executive Boulevard, Suite 325, Rockville, MD 20852-3804; Telephone: (301) 496-7056, ext. 285; Facsimile: (301) 402-0220; e-mail:
The P2X
The prospective exclusive license will be royalty-bearing and will comply with the terms and conditions of 35 U.S.C. 209 and 37 CFR 404.7. The prospective exclusive license may be granted unless, within 90 days from the date of this published Notice, NIH receives written evidence and argument that establishes that the grant of the license would not be consistent with the requirements of 35 U.S.C. 209 and 37 CFR 404.7.
Properly filed competing applications for a license filed in response to this notice will be treated as objections to the contemplated license. Comments and objections submitted in response to this notice will not be made available for public inspection, and, to the extent permitted by law, will not be released under the Freedom of Information Act, 5 U.S.C. 552.
National Institutes of Health, Public Health Service, DHHS.
Notice.
This is notice, in accordance with 35 U.S.C. 209(c)(1) and 37 CFR 404.7(a)(1)(i), that the National Institutes of Health (NIH), Department of Health and Human Services, is contemplating the grant of an exclusive license worldwide to practice the invention embodied in: U.S. Patent Application Serial No. 60/192,039, filed March 24, 2000, now converted into PCT application number PCT/US01/09395 filed March 23, 2001 entitled, “Antiprogestins with Partial Agonist Activity” to Dimera Inc., having a place of business in the state of Oregon. The field of use may be limited to anti-anginal protection/therapy and female reproduction therapies. The United States of America is the assignee of the patent rights in this invention.
Only written comments and/or application for a license, which are received by the NIH Office of Technology Transfer on or before October 28, 2002 will be considered.
Requests for a copy of the patent applications, inquiries, comments and other materials relating to the contemplated license should be directed to: Marlene Shinn, Technology Licensing Specialist, Office of Technology Transfer, National Institutes of Health, 6011 Executive Boulevard, Suite 325, Rockville, MD 20852-3804; Telephone: (301) 496-7056, ext. 285; Facsimile: (301) 402-0220; e-mail:
This technology relates to the results that two derivatives of the potent glucocorticoid dexamethasone show partial agonist activity under a variety of conditions. These steroids have demonstrated affinities for the cell free progesterone receptor that are consistent with their whole cell action arising under conditions where other reported partial progestins were inactive. Of these new antiprogestins that are described in this invention, both Dex-Mes and Dex-ox would be both extremely useful for mechanistic studies in tissue culture systems. Dex-ox is chemically unreactive, while both exhibit considerable amounts of agonist activity under certain circumstances and are partial agonist for glucocorticoid receptors.
The prospective exclusive license will be royalty-bearing and will comply with the terms and conditions of 35 U.S.C. 209 and 37 CFR 404.7. The prospective exclusive license may be granted unless, within 60 days from the date of this published Notice, NIH receives written evidence and argument that establishes that the grant of the license would not be consistent with the requirements of 35 U.S.C. 209 and 37 CFR 404.7.
Properly filed competing applications for a license filed in response to this notice will be treated as objections to the contemplated license. Comments and objections submitted in response to this notice will not be made available for public inspection, and, to the extent permitted by law, will not be released under the Freedom of Information Act, 5 U.S.C. 552.
National Institutes of Health, Public Health Service, DHHS.
Notice.
This is notice, in accordance with 35 U.S.C. 209(c)(1) and 37 CFR 404.7(a)(1)(i), that the National Institutes of Health (NIH), Department of Health and Human Services, is contemplating the grant of a an exclusive license to practice the invention embodied in: United States Patent Application 09/835,124 and its foreign equivalents entitled “Virus-Like Particles for the Induction of Autoantibodies” filed on April 13, 2001, with priority back to U.S. S/N 60/105,132, filed October 21, 1998, to Virionics Corporation, having a place of business in Odenton, Maryland. The patent rights in this invention have been assigned to the United States of America.
Only written comments and/or application for a license which are received by the NIH Office of Technology Transfer on or before October 28, 2002 will be considered.
Requests for a copy of the patent application, inquiries, comments and other materials relating to the contemplated license should be directed to: Peter Soukas, Office of Technology Transfer, National Institutes of Health, 6011 Executive Boulevard, Suite 325, Rockville, MD 20852-3804; e-mail:
This invention claims compositions and methods for producing antibodies to tolerogens (self-antigens normally exposed to B cells that fail to induce an antibody response.) The compositions of the invention comprise multiple copies of a tolerogen (or at least one B cell epitope of a tolerogen) chimerized to capsomeric structures or capsid proteins in an orderly manner. The disclosed compositions can be utilized as prophylactic or therapeutic vaccines against self antigens or antigens of infectious agents. The invention could potentially replace any treatment utilizing chronic administration of a monoclonal antibody that reacts with a self-antigen.
The prospective exclusive license will be royalty bearing and will comply with the terms and conditions of 35 U.S.C. 209 and 37 CFR 404.7. The prospective exclusive license may be granted unless, within 60 days from the date of this published Notice, NIH receives written evidence and argument that establishes that the grant of the license would not be consistent with the requirements of 35 U.S.C. 209 and 37 CFR 404.7.
The field of use may be limited to Human Papilloma Virus-Like Particles vaccines against Hepatitis B Virus (HBV), Hepatitis C Virus (HCV), Vascular Endothelial Growth Factor (VEGF) and breast cancer (Her2/neu).
Properly filed competing applications for a license filed in response to this notice will be treated as objections to the contemplated license. Comments and objections submitted in response to this notice will not be made available for public inspection, and, to the extent permitted by law, will not be released under the Freedom of Information Act, 5 U.S.C. 552.
Office of the Assistant Secretary for Public and Indian Housing, HUD.
Notice of redelegation of authority.
In this notice, the Assistant Secretary for Public and Indian Housing redelegates to the Director of the Special Applications Center authority to review and approve or disapprove: (1) Demolition or disposition applications pursuant to section 18 of the United States Housing Act of 1937 and 24 CFR part 970; and (2) agreements for the taking of public housing property in eminent domain proceedings, and conducting all activities related to such review, approval and disapproval with exceptions.
August 12, 2002.
Ainars Rodins, Office of Public and Indian Housing, Department of Housing and Urban Development, Special Applications Center, Chicago, IL (312) 353-6236. (This is not a toll-free number.) This number may be accessed via TTY by calling the Federal Information Relay Service at 1-800-877-8339. Comments or questions can be submitted through the Internet to
Under section 18 of the United States Housing Act of 1937 (42 U.S.C. 1437
Under the Annual Contributions Contract and Declaration of Trust, the Secretary has an interest in public housing projects that require his or her joinder as a party in eminent domain proceedings.
The Secretary has elsewhere delegated to the Assistant Secretary for Public and Indian Housing (PIH) the authority to administer the Department's programs relating to public housing (see the delegation of authority published in the
Accordingly, the Assistant Secretary for PIH redelegates that authority, as follows:
The Assistant Secretary for PIH redelegates the following authority to the Director of the Special Applications Center (SAC), except as provided in Section B. below:
1. To review and approve or disapprove applications for the demolition or disposition of public housing projects pursuant to section 18 of the 1937 Act and the implementing regulations at 24 CFR part 970, and to conduct all activities related to such review, and approval or disapproval of such applications.
2. To review and approve or disapprove agreements for the taking of public housing property in eminent domain proceedings and conduct all activities related to such review, and approval or disapproval of such agreements.
1. The authority redelegated does not include the authority to waive regulations; and
2. The Director of the SAC may exercise the authority to disapprove an application for demolition or disposition or an agreement for the taking of public housing property in eminent domain proceedings on the grounds that the application or agreement is prohibited by or inconsistent with applicable Federal law only with the concurrence of the Assistant Secretary for PIH or his or her designee.
The authority redelegated in Section A may not be further redelegated except to an official authorized to act for the Director of the SAC in his or her absence.
The redelegation of authority from the Assistant Secretary for PIH to PIH Directors and Deputy Directors in the field, published in the
Fish and Wildlife Service, Interior.
Notice; request for comments.
The U.S. Fish and Wildlife Service will submit the collection of information listed below to OMB for approval under the provisions of the Paperwork Reduction Act. A copy of the information collection requirement is included in this notice. If you wish to obtain copies of the proposed information collection requirement, related forms, and explanatory material, contact the Service Information Collection Clearance Officer at the address listed below.
You must submit comments before the 30 day deadline.
Send your comments on specific requirements to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attention: Department of the Interior Desk Officer, 725 17th Street, NW., Washington, DC 20503, and to Anissa Craghead, Information Collection Clearance Officer, U.S. Fish and Wildlife Service, ms 222-ARLSQ, 4401 N. Fairfax Drive, Arlington, VA 22203, (703) 358-2445.
To request a copy of the information collection request, explanatory information and related forms, contact Anissa Craghead at (703) 358-2445, or electronically to
The Office of Management and Budget (OMB) regulations at 5 CFR 1320, which implement provisions of the Paperwork Reduction Act of 1995 (Pub. L. 104-13), require that interested members of the public and affected agencies have an opportunity to comment on information collection and recordkeeping activities (
Federal agencies may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control number for this collection of information is 1018-0010.
The Migratory Bird Treaty Act (16 U.S.C. 703-711) and Fish and Wildlife Act of 1956 (16 U.S.C. 742d) designate the Department of the Interior as the key agency responsible for the wise management of migratory bird populations frequenting the United States and for the setting of hunting regulations that allow appropriate harvests that are within the guidelines that will allow for those populations' well being. These responsibilities dictate the gathering of accurate data on various characteristics of migratory bird populations. The Mourning Dove Call-Count Survey is an essential part of the migratory bird management program. The survey is a cooperative effort between us and State wildlife agencies. It is conducted each spring by State and Service biologists to provide the necessary data to determine the population status of the mourning dove. The survey results are then used to help guide us and the States in the annual promulgation of regulations for hunting mourning doves. Survey data are also used to plan and evaluate dove management programs and provide specific information necessary for dove research. If this survey were not used, there would be no way to determine the population status of mourning doves prior to setting regulations.
We invite comments concerning this renewal on: (1) Whether the collection of information is necessary for the proper performance of our migratory bird management functions, including whether the information will have practical utility; (2) the accuracy of our estimate of the burden of the collection of information; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and, (4) ways to minimize the burden of the collection of information on respondents. The information collections in this program are part of a system of record covered by the Privacy Act (5 U.S.C. 552(a)).
Sincerely,
Fish and Wildlife Service, Interior.
Notice; request for comments.
The U.S. Fish and Wildlife Service will submit the collection of information listed below to OMB for approval under the provisions of the Paperwork Reduction Act. A copy of the information collection requirement is included in this notice. If you wish to obtain copies of the proposed information collection requirement, related forms, and explanatory material, contact the Service Information Collection Clearance Officer at the address listed below.
You must submit comments before the 30 day deadline.
Send your comments on specific requirements to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attention: Department of the Interior Desk Officer, 725 17th Street, NW., Washington DC 20503, and to Anissa Craghead, Information Collection Clearance Officer, U.S. Fish and Wildlife Service, ms 222-ARLSQ, 4401 N. Fairfax Drive, Arlington, VA 22203, (703) 358-2445.
To request a copy of the information collection request, explanatory information and related forms, contact Anissa Craghead at (703) 358-2445, or electronically to
The Office of Management and Budget (OMB) regulations at 5 CFR 1320, which implement provisions of the Paperwork Reduction Act of 1995 (Pub. L. 104-13), require that interested members of the public and affected agencies have an opportunity to comment on information collection and recordkeeping activities (
Federal agencies may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control number for this collection of information is 1018-0019.
The Migratory Bird Treaty Act (16 U.S.C. 703-711) and Fish and Wildlife Act of 1956 (16 U.S.C. 742d) designate the Department of the Interior as the key agency responsible for the wise management of migratory bird populations frequenting the United States and for the setting of hunting regulations that allow appropriate harvests that are within the guidelines that will allow for those populations' well being. These responsibilities dictate the gathering of accurate data on
We invite comments concerning this renewal on: (1) Whether the collection of information is necessary for the proper performance of our migratory bird management functions, including whether the information will have practical utility; (2) the accuracy of our estimate of the burden of the collection of information; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and, (4) ways to minimize the burden of the collection of information on respondents. The information collections in this program are part of a system of record covered by the Privacy Act (5 U.S.C. 552(a)).
Sincerely,
National Park Service, Interior.
Notice of October 17, 2002 meeting.
This notice sets forth the date of the October 17, 2002 meeting of the Gettysburg National Military Park Advisory Commission.
The public meeting will be held on October 17, 2002 from 7 p.m. to 9 p.m.
John A. Latschar, Superintendent, Gettysburg National Military Park, 97 Taneytown Road, Gettysburg, Pennsylvania 17325.
The meeting will be open to the public. Any member of the public may file with the Commission a written statement concerning agenda items. The statement should be addressed to the Gettysburg National Military Park Advisory Commission, 97 Taneytown Road, Gettysburg, Pennsylvania 17325.
Notice is hereby given in accordance with the Federal Advisory Committee Act that a meeting of the Na Hoapili O Kaloko Honokohau, Kaloko-Honokohau National Historical Park Advisory Commission will be held at 1 p.m., September 26, 2002 at Kaloko-Honokohau National Historical Park headquarters, 73-4786 Kanalani St. Suite 14, Kailua-Kona, Hawaii.
The agenda will include Revisions to Park Brochure, Finalized Location of Canoe Halau, Preliminary Plan for Cultural Live-In Center, Training Programs, Commission Vacancies, and General Management Plan.
The meeting is open to the public. Minutes will be recorded for documentation and transcribed for dissemination. Minutes of the meeting will be available to the public after approval of the full Advisory Commission. Transcripts will be available after 30 days of the meeting.
For copies of the minutes, contact Kaloko-Honokohau National Historical Park at (808) 329-6881.
Nominations for the following properties being considered for listing in the National Register were received by the National Park Service before August 3, 2002. Pursuant to section 60.13 of 36 CFR part 60 written comments concerning the significance of these properties under the National Register criteria for evaluation may be forwarded by United States Postal Service, to the National Register Historic Places, National Park Service, 1849 C St.
A request for REMOVAL has been made for the following resources:
National Park Service, Interior.
Notice.
Notice is hereby given in accordance with the provisions of the Native American Graves Protection and Repatriation Act (NAGPRA), 43 CFR 10.10 (a)(3), of the intent to repatriate cultural items in the possession of the U.S. Department of Justice, Federal Bureau of Investigation (FBI), Louisville, KY, that meet the definition of “unassociated funerary object” under Section 2 of the Act.
This notice is published as part of the National Park Service’s administrative responsibilities under NAGPRA, 43 CFR 10.2 (c). The determinations within this notice are the sole responsibility of the museum, institution, or Federal agency that has control of these cultural items. The National Park Service is not responsible for the determinations within this notice.
On February 18, 1999, a search warrant was executed at the home of Sean Adam Long near Madisonville, KY. Twenty-six items were recovered by FBI agents during the search that have been determined to meet the definition of unassociated funerary objects. These cultural items are 14 animal bones, 1 item made from animal bone, 1 stone tubular pipe fragment, 1 fragment of a Caborn-Welborn ceramic pot (Late Mississippian Period), 1 coarse shell-tempered ceramic vessel with strap handles and with soot on exterior, 1 polished and drilled shell gorget, 1 polished bone tube, 1 box turtle carapace fragment, 1 marine gastropod, 1 Mississippian Plain water bottle, 1 polished stone atlatl weight, 1 cannel coal bead, and 1 black stone gorget.
In an interview with FBI officials, Mr. Long indicated that the above-mentioned items were originally recovered from specific burial sites located in Kentucky.
A detailed assessment of the unassociated funerary objects was made by University of Louisville Staff Archaeologist Philip J. DiBlasi in consultation with representatives of the Absentee-Shawnee Tribe of Indians of Oklahoma; Delaware Nation, Oklahama; Delaware Tribe of Indians, Oklahoma; Eastern Band of Cherokee Indians of North Carolina; Eastern Shawnee Tribe of Oklahoma; Miami Tribe of Oklahoma; Peoria Tribe of Indians of Oklahoma; and Shawnee Tribe, Oklahoma.
Archeological evidence indicates that these items were most likely buried during the Prehistoric period (before A.D. 1740). Archeological and historical evidence indicates that the Native American population that lived in Kentucky during the Prehistoric period is ancestral to the present-day Delaware Nation, Oklahoma; Delaware Tribe of Indians, Oklahoma; Eastern Band of Cherokee Indians of North Carolina; Miami Tribe of Oklahoma; and Peoria Tribe of Indians of Oklahoma.
On March 7, 2001, Sean Adam Long pleaded guilty in U.S. District Court in Owensboro, KY to three counts of illegal trafficking in Native American human remains [18 U.S.C. 1170 (a)] and one count of knowingly making a materially false, fictitious, or fraudulent statement or representation [18 U.S.C. 1001]. A single count of trafficking in interstate or foreign commerce in archaeological resources the excavation, removal, sale, purchase, exchange, transportation or receipt of which was wrongful under State or local law [16 U.S.C. 470ee (c)] was dismissed in return for Long’s plea to making a false statement to FBI agents.
Based on the above-mentioned information, FBI officials determined that, pursuant to 43 CFR 10.2 (d)(2)(ii), these 26 cultural items are reasonably believed to have been placed with or near individual human remains at the time of death or later as part of a death rite or ceremony and are believed to have been removed from specific burial sites of Native American individuals. FBI officials determined that, pursuant to 43 CFR 10.2 (e), there is a relationship of shared group identity that can be reasonably traced between these unassociated funerary objects and the Delaware Nation, Oklahoma; Delaware Tribe of Indians, Oklahoma; Eastern Band of Cherokee Indians of North Carolina; Miami Tribe of Oklahoma; and Peoria Tribe of Indians of Oklahoma.
Two other items seized during the search of Mr. Long’s residence do not appear to meet the statutory definition of “associated funerary object.” Officials of the FBI have determined, pursuant to standard practice regarding personal property, Manual of Administrative Operations and Procedures, Sect. 2-4.4.1 (5), that these two items are subject to return to the appropriate Indian tribe.
This notice has been sent to officials of the Absentee-Shawnee Tribe of Indians of Oklahoma; Delaware Nation, Oklahoma; Delaware Tribe of Indians, Oklahoma; Eastern Band of Cherokee Indians of North Carolina; Eastern Shawnee Tribe of Oklahoma; Miami Tribe of Oklahoma; Peoria Tribe of Indians of Oklahoma; and Shawnee Tribe, Oklahoma. Representatives of any other Indian tribe that believes itself to be culturally affiliated with these unassociated funerary objects should contact Randy Ream, Assistant United States Attorney, 510 West Broadway, 10th Floor, Louisville, KY 40202, phone (502) 582-5911, before September 30, 2002. Repatriation of these unassociated funerary objects to the Delaware Nation, Oklahoma; Delaware Tribe of Indians, Oklahoma; Eastern Band of Cherokee Indians of North Carolina; Miami Tribe of Oklahoma; and Peoria Tribe of Indians of Oklahoma may begin after that date if no additional claimants come forward.
National Park Service, Interior.
Notice.
Notice is hereby given in accordance with the Native American Graves Protection and Repatriation Act (NAGPRA), 43 CFR 10.10 (a)(3), of the intent to repatriate a cultural item in the possession of the Hood Museum of Art, Dartmouth College, NH, that meets the definition of “sacred object” and “object of cultural patrimony” under Section 2 of the Act.
This notice is published as part of the National Park Service’s administrative responsibilities under NAGPRA, 43 CFR 10.2 (c). The determinations within this notice are the sole responsibility of the museum, institution, or Federal agency that has control of these cultural items. The National Park Service is not responsible for the determinations within this notice.
The cultural item is a tunic, or shirt, made from trade cloth and two panels of a Chilkat robe, or approximately one half of a complete robe (Hood Museum of Art accession number 159.1.14291). The Hood Museum of Art’s records identify the tunic as having come from Angoon, AK, and as having been made prior to the 1882 bombardment of Angoon.
Axel Rasmussen originally collected the tunic while he was superintendent of schools in Wrangell, AK, during the late 1920s through 1937. After Mr. Rasmussen’s death in 1945, his collection of Northwest Coast objects was dispersed. The collection was reassembled by Earl Stendahl and a part of it was sold to the Portland Art Museum, Portland, OR. The remainder of the collection was deposited with Doris Meltzer, a New York City dealer, to sell. Some of the items that Ms. Meltzer did not sell were given to the Dartmouth College Museum, now the Hood Museum of Art, between 1959 and 1966. The tunic was given to the museum in 1959.
In 1995, a delegation of Tlingit visited the Hood Museum of Art for consultation on the museum’s collections. At that time, a raven crest was identified in the design of the tunic, and the representative from Angoon related the story of how two brothers, Kanaalku and Kichnaalx, of Yeil Hit (Raven House) of the Deisheetaan Clan of the Kootznoowoo Tribe, inherited a Chilkat robe that, in order for both to use it, was cut up and made into two tunics.
Based on the above-mentioned information, officials of the Hood Museum of Art have determined that, pursuant to 43 CFR 10.2 (d)(3), this cultural item is a specific ceremonial object needed by traditional Native American religious leaders for the practice of traditional Native American religions by their present-day adherents. Officials of the Hood Museum of Art also have determined that, pursuant to 43 CFR 10.2 (d)(4), this cultural item has ongoing historical, traditional, or cultural importance central to the tribe itself, and may not be alienated, appropriated, or conveyed by any individual. Lastly, officials of the Hood Museum of Art have determined that, pursuant to 43 CFR 10.2 (e), there is a relationship of shared group identity that can be reasonably traced between this sacred object/object of cultural patrimony and the Angoon Community Association, representing the Deisheetaan Clan of the Kootznoowoo Tribe of the Admiralty Island of Angoon, AK, and Kootznoowoo Incorporated.
This notice has been sent to officials of the Deisheetaan Clan, Kootznoowoo Incorporated, Kootznoowoo Cultural and Educational Foundation, and the Central Council of the Tlingit & Haida Indian Tribes. Representatives of any other Indian tribe that believes itself to be culturally affiliated with this sacred object/object of cultural patrimony should contact Kellen G. Haak, Collections Manager/Registrar and Repatriation Coordinator, Hood Museum of Art, Dartmouth College, Hanover, NH 03755, telephone (603) 646-3109, before September 30, 2002. Repatriation of this sacred object/object of cultural patrimony to the Central Council of the Tlingit & Haida Indian Tribes on behalf of the Kootznoowoo Cultural and Educational Foundation, Kootznoowoo Incorporated, and the Deisheetaan Clan may begin after that date if no additional claimants come forward.
National Park Service, Interior.
Notice.
Notice is hereby given under the Native American Graves Protection and Repatriation Act, 43 CFR 10.10 (a)(3), of the intent to repatriate a cultural item in the possession of the Hood Museum of Art, Dartmouth College, Hanover, NH, that meets the definition of “unassociated funerary object” under Section 2 of the Act.
This notice is published as part of the National Park Service’s administrative responsibilities under NAGPRA, 43 CFR 10.2 (c). The determinations within this notice are the sole responsibility of the museum, institution, or Federal agency that has control of this cultural item. The National Park Service is not responsible for the determinations within this notice.
The cultural item is a ball-headed, wooden “war club” (Catalog number 37.5.5370) with a carved diamond pattern and red and green paint on the handle.
In 1937, this war club was donated to the Dartmouth College Museum, now the Hood Museum of Art, by Charles Bethune.
The exact circumstances of the war club’s collection are not known. Donor information states that this war club was collected from a grave in an unknown location. Donor information also identifies this war club as “Seneca”. The Hood Museum of Art is not in possession or control of any human remains from this burial. Officials of the Seneca Nation of New York and the Tonawanda Band of Seneca Indians of New York have indicated that this club is stylistically consistent with other known Seneca war clubs, and that the placement of funerary objects with an individual’s remains was a common Seneca practice during the historic era. As a highly prized, personal object of power, a war club would have been a type of object traditionally placed with its deceased owner. Representatives of the Seneca-Cayuga Tribe of Oklahoma were consulted and agreed that the object should be repatriated to the Seneca Nation of New York and the Tonawanda Band of Seneca Indians of New York.
Based on the above-mentioned information, officials of the Hood Museum of Art have determined that, pursuant to 43 CFR 10.2 (d)(2)(ii), this cultural item is reasonably believed to have been placed with or near individual human remains at the time of death or later as part of the death rite or ceremony and is believed, by a preponderance of the evidence, to have been removed from a specific burial site of an Native American individual. Officials of the Hood Museum of Art also have determined that, pursuant to 43 CFR 10.2 (e), there is a relationship of shared group identity that can be reasonably traced between this unassociated funerary object and the Seneca Nation of New York and the Tonawanda Band of Seneca Indians of New York.
This notice has been sent to officials of the Cayuga Nation of New York, Oneida Nation of New York, Oneida Tribe of Indians of Wisconsin, Onondaga Nation of New York, St. Regis Band of Mohawk Indians of New York, Seneca Nation of New York, Seneca-Cayuga Tribe of Oklahoma, Tonawanda Band of Seneca Indians of New York, and Tuscarora Nation of New York. Representatives of any other Indian tribe that believes itself to be culturally affiliated with this unassociated funerary object should contact Kellen G. Haak, Collections Manager/Registrar and Repatriation Coordinator, Hood Museum of Art, Dartmouth College, Hanover, NH 03755, telephone (603) 646-3109, before September 30, 2002. Repatriation of this unassociated funerary object to the Seneca Nation of New York and the Tonawanda Band of Seneca Indians of New York may begin after that date if no additional claimants come forward.
National Park Service, Interior.
Notice.
Notice is hereby given under the Native American Graves Protection and Repatriation Act, 43 CFR 10.10 (a)(3), of the intent to repatriate a cultural item in the possession of the Houston Museum of Natural Science, Houston, TX, that meets the definition of Asacred object@ under Section 2 of the Act.
This notice is published as part of the National Park Service=s administrative responsibilities under NAGPRA, 43 CFR 10.2 (c). The determinations within this notice are the sole responsibility of the museum, institution, or Federal agency that has control of these cultural items. The National Park Service is not responsible for the determinations within this notice.
The cultural item is a paho, or prayer stick. The paho is made from two sticks, painted green, approximately 22 centimeters long, four feathers (three turkey feathers and one buteo hawk feather), and the twine that holds the sticks and feathers together.
In the 1950s, Eleanor Searle McCullum was given the paho by a member of the Porter Timeche family. In November 1991, Mrs. McCullum donated the paho to the Houston Museum of Natural Science.
Museum records indicate that this item was given to the donor by a Hopi person and that it is a Hopi object, which is consistent with its style and construction. Consultation with representatives of the Hopi tribe confirm that this is a Hopi object. During consultations, the Hopi tribal representatives stated that this paho is needed by traditional Native American religious leaders for the practice of their traditional Native American religion by their present-day adherents.
Authorities of the United States Fish and Wildlife Service in Albuquerque, NM, have been contacted regarding applicability of the Migratory Bird Treaty Act to this transfer and concur that the transfer may take place without a permit.
Based on the above-mentioned information, officials of the Houston Museum of Natural Science have determined that, pursuant to 43 CFR 10.2 (d)(3), this cultural item is a specific ceremonial object needed by traditional Native American religious leaders for the practice of traditional Native American religions by their present-day adherents. Officials of the Houston Museum of Natural Science also have determined that, pursuant to 43 CFR 10.2 (e), there is a relationship of shared group identity that can be reasonably traced between this item and the Hopi Tribe of Arizona.
This notice has been sent to officials of the Hopi Tribe of Arizona. Representatives of any other Indian tribe that believes itself to be culturally affiliated with these objects should contact Dirk Van Turenhout, Curator of Anthropology, Houston Museum of Natural Science, One Hermann Circle Drive, Houston, TX 77030-1799, telephone (713) 639-4674 before September 30, 2002. Repatriation of these objects to the Hopi Tribe of Arizona may begin after that date if no additional claimants come forward.
National Park Service, Interior.
Notice.
Notice is hereby given in accordance with provisions of the Native American
This notice is published as part of the National Park Service’s administrative responsibilities under NAGPRA, 43 CFR 10.2 (c). The determinations within this notice are the sole responsibility of the museum, institution, or Federal agency that has control of these Native American human remains and associated funerary objects. The National Park Service is not responsible for the determinations within this notice.
A detailed assessment of the human remains was made by the Minnesota Indian Affairs Council professional staff in consultation with representatives of the Mille Lacs Band of the Minnesota Chippewa Tribe, Minnesota.
In 1965, human remains representing three individuals were removed from the Petaga Point site (21-ML-11), Mille Lacs County, MN, during archeological excavations conducted by L.R. Cooper of the University of Minnesota. No known individuals were identified. The three associated funerary objects are two copper coils (578.61) and one piece of birch bark.
Based on material culture present at the Petaga Point site (21-ML-11), these burials have been identified as postcontact cemetery burials related to the Mille Lacs Band of Ojibwe. These human remains are from within the present reservation and the ceded aboriginal territory of the Mille Lac Band of the Minnesota Chippewa Tribe, Minnesota. Traditionally, members of the tribe have wrapped human remains in birch bark before interring them. Birch bark was associated with the burial and is considered additional evidence that the human remains were ancestors of the present-day Mille Lac Ojibwe.
In 1949, human remains representing four individuals were removed from the Kathio School or Vineland Bay site (21-ML-7), Mille Lacs County, MN, by L.A. Wilford of the University of Minnesota. No known individuals were identified. The remains of one individual were recovered from a burial. The remains of three other individuals were recovered from a feature near the burial. The 1325 associated funerary objects recovered from the feature near the burial are 1 bear skull (301-9), 17 bear bones (301), 80 deer bones (301), 16 deer teeth (301), 75 fish bones (301), 42 turtle bones (301), 1 rabbit skull (301), 23 pieces of bird bone (301), 6 beaver bones (301), 18 beaver teeth (301), 4 bone tools (301), 840 pieces of unidentifiable medium to large mammal bones (301), 14 unidentifiable medium to large mammal skull bone fragments (301), 2 elk bones (301), 3 canine bones (301), 81 burnt bone fragments (301), 2 pottery rim sherds (301), 6 pottery sherds (301), 3 pieces of bark (301), 90 pieces of unidentifiable small to medium mammal bones (301), and 1 large mammal cranial fragment (301).
In 1966, human remains representing one individual were removed from the Kathio School or Vineland Bay site (21-ML-7), Mille Lacs County, MN, by O.E. Johnson of the University of Minnesota. No known individuals were identified. The 108 associated funerary objects are 17 pottery sherds (606-55), 2 projectile points (606-55), 17 lithic flakes (606-55), 8 pieces of fire-cracked rock (606-55), 1 quartz scraper (606-55), 1 quartz piece (606-55), 2 pieces of burnt clay (606-55), 29 pieces of burnt bone (606-55), 17 pieces of fish bone (606-55), and 14 fragments of large mammal bone (606-55).
In 1967, human remains representing eight individuals were removed from the Kathio School or Vineland Bay site (21-ML-7), Mille Lacs County, MN, by D. Dickinson of the University of Minnesota. No known individuals were identified. The 104 associated funerary objects consist of human hair, 13 dog skull fragments (638), 1 copper breast plate with wood (638), 1 hide flesher, 1 bone awl (638-202), 11 unidentified bone fragments (638-186, 638-206), 1 burnt bone fragment, 1 siltstone scraper, 52 lithic flakes (638-201, 638-193,638-243), 2 fish bone fragments, 1 deer bone, 1 small blue bead,, 1 rusted iron bracelet (638-190), 1 copper bracelet (638-203), 1 woven cloth from a burial (638-163), 1 piece of bark, 1 piece of quartz (638-197), 1 copper fragment (638-194), 1 piece of copper (638-192), 1 bird bone (638-246), 1 copper tube bead (638-244), 1 bear tooth (638-234), 6 ceramic sherds, and 3 projectile points (638-199, 638-245, 638-248).
Based on material culture present at the Kathio School or Vineland Bay site (21-ML-7), these burials have been identified as postcontact cemetery burials related to the Mille Lacs Band of Ojibwe. These human remains are from within the present reservation and the ceded aboriginal territory of the Mille Lac Band of the Minnesota Chippewa Tribe, Minnesota. The funerary objects found with these human remains are traditionally the items that Ojibwe people put into burials and are considered additional evidence that the human remains were ancestors of the present-day Mille Lacs Ojibwe.
In 1966, human remains representing four individuals were removed from Strawberry Hill (21-ML-14), Mille Lacs County, County, MN, by T. Dahlquist and J. Kaufert of the University of Minnesota. No known individuals were identified. No associated funerary objects are present.
Based on oral traditions and historic documents, Strawberry Hill is recognized as an historic Ojibwe cemetery. It is within the current reservation and the ceded aboriginal territory of the Mille Lacs Band of Ojibwe.
Based on the above-mentioned information, officials of the Bureau of Indian Affairs and the Minnesota Indian Affairs Council have determined that, pursuant to 43 CFR 10.2 (d)(1), the human remains listed above represent the physical remains of 20 individuals of Native American ancestry. Officials of the Bureau of Indian Affairs and the Minnesota Indian Affairs Council also have determined that, pursuant to 43 CFR 10.2 (d)(2), the 1540 objects listed above are reasonably believed to have been placed with or near individual human remains at the time of death or later as part of the death rite or ceremony. Lastly, officials of the Bureau of Indian Affairs and the Minnesota Indian Affairs Council have determined that, pursuant to 43 CFR 10.2 (e), there is a relationship of shared group identity that can be reasonably traced between these Native American human remains and associated funerary objects and the Mille Lacs Band of the Minnesota Chippewa Tribe, Minnesota.
This notice has been sent to officials of the Mille Lacs Band of the Minnesota Chippewa Tribe, Minnesota and the Minnesota Chippewa Tribe, Minnesota. Representatives of any other Indian tribe that believes itself to be culturally affiliated with these human remains and associated funerary objects should contact James L. Jones, Cultural Resource Specialist, Minnesota Indian Affairs Council, 1819 Bemidji Avenue, Bemidji, MN 56601; telephone (218) 755-3825, before September 30, 2002. Repatriation of the human remains and associated funerary objects to the Mille Lacs Band of the Minnesota Chippewa Tribe, Minnesota may begin after that date if no additional claimants come forward.
National Park Service, Interior.
Notice.
Notice is hereby given in accordance with provisions of the Native American Graves Protection and Repatriation Act (NAGPRA), 25 U.S.C. 3003 (d) and 43 CFR 10.9, of the completion of an inventory of human remains and associated funerary objects in the possession of the Colorado Historical Society, Denver, CO.
This notice is published as part of the National Park Service’s administrative responsibilities under NAGPRA, 43 CFR 10.2 (c). The determinations within this notice are the sole responsibility of the museum, institution, or Federal agency that has control of these Native American human remains. The National Park Service is not responsible for the determinations within this notice.
A detailed assessment of the human remains and associated funerary objects was made by Colorado Historical Society professional staff in consultation with representatives of the Southern Ute Indian Tribe of the Southern Ute Reservation, Colorado; Ute Indian Tribe of the Uintah & Ouray Reservation, Utah; and Ute Mountain Tribe of the Ute Mountain Reservation, Colorado, New Mexico & Utah.
On June 8-9, 1995, the remains of four individuals were removed from site 5FN1210, also known as the Coaldale-Fox burial or Office of Archaeology and Historic Preservation (OAHP) Burial Number 106. Site 5FN1210 is located on private land near Coaldale in Fremont County, CO. Three of the human remains were originally discovered in disturbed fill dirt during the construction of a reservoir. The Fremont County Sheriff's department sent these three human remains to Dr. Michael Hoffman of Colorado College, who confirmed them to be Native American. OAHP staff subsequently excavated site 5FN1210 under a State of Colorado archaeological permit and recovered the remains of a fourth individual from a burial pit. Dr. Jim Wanner of the University of Northern Colorado confirmed that all four individuals were Native American. No known individuals were identified. The 12 associated funerary objects are 3 bone beads, 1 bone awl, 2 incised tubular bone beads, 3 pieces of animal bone, 1 rabbit bone treated with ocher, 1 endscraper, and 1 flake.
In November, 1995, the Colorado Historical Society completed an inventory of the human remains and associated funerary objects from 5FN1210 as required by 25 U.S.C. 3003 (b)(1). At that time, officials of the Colorado Historical Society determined that, pursuant to 25 U.S.C. 3001 (9), the above-mentioned human remains represented four individuals of Native American ancestry. Officials of the Colorado Historical Society also determined that, pursuant to 25 U.S.C. 3001 (3), the 12 objects listed above are reasonably believed to have been placed with or near individual human remains at the time of death or later as part of the death rite or ceremony. Finally, officials of the Colorado Historical Society determined that, pursuant to 25 U.S.C. 3001 (2), there was not sufficient evidence to trace a relationship of shared group identity between the human remains and associated funerary objects and any present-day Indian tribe or Native Hawaiian organization. The Colorado Historical Society provided an inventory of these culturally unidentifiable human remains and associated funerary objects to the Departmental Consulting Archeologist as required under 43 CFR 10.9 (e)(6).
Through ongoing consultations with Native American tribes, along with research conducted by the Colorado Historical Society, additional evidence regarding cultural affiliation of these human remains and associated funerary objects was identified. Based on stratigraphic and artifactual evidence, the remains and associated funerary objects of these four individuals are estimated to date approximately from 2,000 to 500 years before present. The preponderance of the evidence, including archeology, ethnohistory, history, geography, and oral traditions, indicates that a relationship of shared group identity can be reasonably traced between these human remains and associated funerary objects and the Southern Ute Indian Tribe of the Southern Ute Reservation, Colorado. More specifically, in his 1996 concluding report on the site, Kevin Black reported contextual association of charcoal with the remains in the partially undisturbed burial pit. According to Southern Ute traditional historian Alden Naranjo, fires often accompanied Ute burial ceremonies. Mr. Naranjo notes that Ute mortuary practices were diverse and depended on seasonal, topographical, and environmental factors. Archeological evidence indicates that these persons were interred in a manner consistent with known Ute mortuary practices. Importantly, the discovery site lies within the well-documented residential use areas of the Capote and Moache Ute bands. After the Ute agreement of 1880, the Capote and Moache bands were removed to southern Colorado and came to comprise, along with other Ute bands, what is now known as the Southern Ute Indian Tribe of the Southern Ute Reservation, Colorado.
Based on the above-mentioned information, officials of the Colorado Historical Society have determined that, pursuant to 43 CFR 10.2 (d)(1), the human remains listed above represent the physical remains of four individuals of Native American ancestry. Officials of the Colorado Historical Society also have determined that, pursuant to 43 CFR 10.2 (d)(2), the 12 funerary objects listed above are reasonably believed to have been placed with or near individual human remains at the time of death or later as part of the death rite or ceremony. Lastly, pursuant to 43 CFR 10.2 (e), and in accordance with 25 U.S.C. 3005 (a)(4), officials of the Colorado Historical Society have determined that there is a relationship of shared group identity that can be reasonably traced between these Native American human remains and the Southern Ute Indian Tribe of the Southern Ute Reservation, Colorado.
This notice has been sent to officials of the Apache Tribe of Oklahoma; Arapahoe Tribe of the Wind River Reservation, Wyoming; Cheyenne-Arapaho Tribes of Oklahoma; Cheyenne River Sioux Tribe of the Cheyenne River Reservation, South Dakota; Comanche Indian Tribe, Oklahoma; Crow Creek Sioux Tribe of the Crow Creek Reservation, South Dakota; Crow Tribe of Montana; Fort Sill Apache Tribe of Oklahoma; Hopi Tribe of Arizona; Jicarilla Apache Tribe of the Jicarilla Apache Indian Reservation, New Mexico; Kiowa Indian Tribe of Oklahoma; Mescalero Apache Tribe of the Mescalero Reservation, New Mexico; Navajo Nation, Arizona, New Mexico & Utah; Northern Cheyenne Tribe of the Northern Cheyenne Indian Reservation, Montana; Oglala Sioux Tribe of the Pine Ridge Reservation, South Dakota; Pawnee Nation of Oklahoma; Pueblo of Acoma, New Mexico; Pueblo of Cochiti, New Mexico; Pueblo of Isleta, New Mexico; Pueblo of Jemez, New Mexico; Pueblo of Laguna, New Mexico; Pueblo of Nambe, New Mexico; Pueblo of Picuris, New Mexico; Pueblo of Pojoaque, New Mexico; Pueblo of San Felipe, New Mexico; Pueblo of San Ildefonso, New Mexico; Pueblo of San Juan, New Mexico; Pueblo of Sandia,
Representatives of any other Indian tribe that believes itself to be culturally affiliated with these human remains should contact Anne W. Bond, Director of Collections and Exhibitions, Colorado Historical Society, 1300 Broadway, Denver, CO 80203-2137, telephone (303) 866-4691, before September 30, 2002. Repatriation of the human remains to the Southern Ute Indian Tribe of the Southern Ute Reservation, Colorado, may begin after that date if no additional claimants come forward.
National Park Service, Interior.
Notice.
Notice is hereby given in accordance with provisions of the Native American Graves Protection and Repatriation Act (NAGPRA), 43 CFR 10.9, of the completion of an inventory of human remains and associated funerary objects in the possession of the U.S. Department of Defense, Department of the Army, Fort Benning, GA.
This notice is published as part of the National Park Service’s administrative responsibilities under NAGPRA, 43 CFR 10.2 (c). The determinations within this notice are the sole responsibility of the museum, institution, or Federal agency that has control of these Native American human remains and associated funerary objects. The National Park Service is not responsible for the determinations within this notice.
A detailed assessment of the human remains was made by U.S. Army installation staff, U.S. Army Engineer District, St. Louis, Mandatory Center of Expertise for the Curation and Management of Archaeological Collections in consultation with representatives of the Alabama-Coushatta Tribes of Texas; Alabama-Quassarte Tribal Town, Oklahoma; Chickasaw Nation, Oklahoma; Coushatta Tribe of Louisiana; Kialegee Tribal Town, Oklahoma; Miccosukee Tribe of Indians of Florida; Muskogee (Creek) Nation of Oklahoma; Poarch Band of Creek Indians of Alabama; Seminole Nation of Oklahoma; Seminole Tribe of Florida; and Thlopthlocco Tribal Town, Oklahoma.
In 1938, human remains representing one individual were removed from Lawson Field (site 9Ce1), also known as Kashita Town, Chattahoochee County, GA, by Gordon Willey of the National Park Service. No known individual was identified. The 165 associated funerary objects are 4 copper bells, 4 iron bell parts, 11 copper buttons and button backs, 30 ceramic sherds, 8 copper coil fragments, 1 fragment of rust-stained fabric, 2 shell bead necklaces, 1 glass bead necklace, 56 additional glass beads, 1 iron adze, 1 iron hammer head, 2 iron files, 9 iron knife fragments, 1 iron nail and 3 iron nail fragments, 2 iron spikes, 1 iron spike fragment, 1 iron bullet mold fragment, 2 iron gun hammers, 1 unidentified L-shaped iron object, 18 additional iron fragments, 1 quartzite knife, 1 lump of clay, 1 shell pin fragment, 1 wood fragment, and 2 water-worn pebbles. The human remains and associated funerary objects were housed at the Columbus Museum of Arts and Sciences, Columbus, GA, until 1999, when they were transferred to the Mandatory Center of Expertise for the Curation and Management of Archaeological Collections, St. Louis, MO, for rehabilitation. In July 2001, these human remains and associated funerary objects were transferred to Fort Benning, GA.
Charles H. Fairbanks, in his 1940 report entitled “Archaeological Site Report on the Lawson Field,” identified site 9Ce1 as Kasihta, one of the principal towns of the Lower Creeks in the 18th century. He attributed the burial to the late 18th century or early 19th century.
In 1958, human remains representing one individual were removed from the Quartermaster site (9Ce42), Chattahoochee County, GA, by Mr. Ed McMichael and Sergeant David Chase. No known individual was identified. The one associated funerary object is a small piece of green-tinted fabric. Mr. McMichael and Sergeant Chase found the burial while investigating prehistoric features encountered by construction workers at this site. The human remains were housed at the Riverbend Research Laboratory, University of Georgia, Columbus, GA, until 1999, when they were transferred to the Mandatory Center of Expertise for the Curation and Management of Archaeological Collections, St. Louis, MO, for rehabilitation. In July 2001, these human remains were transferred to Fort Benning, GA.
The site has been dated as Late Woodland (A.D. 100-900) to historic (late 17th-early 18th century) by numerous features encountered during further excavation. In 1971, human remains representing two individuals were removed from the Oswichee Creek site (9Ce66), Chattahoochee County, GA, by Sergeant Chase and two Columbus College students, who had seen the burial eroding at the site. No known individuals were identified. The 194 associated funerary objects include 3 shell disks, 62 shell beads and bead fragments, 58 ceramic sherds, 16 charcoal fragments, 6 fired clay fragments, 39 faunal fragments, 6 chert flakes, 1 quartz flake, 1 chert drill fragment, 1 chert projectile point fragment, and 1 sandstone fragment. Part of the human remains and most of the associated funerary objects were housed by the Columbus Museum of Arts and Sciences, Columbus, GA, and the rest of the human remains and three associated funerary objects were housed by the Riverbend Research Laboratory, University of Georgia, in Columbus, GA. In 1999, the remains and funerary objects from both institutions were transferred to the Mandatory Center of Expertise for the Curation and Management of Archaeological Collections, St. Louis, MO, for rehabilitation. In July 2001, these human remains and funerary objects were transferred to Fort Benning, GA.
The burial has been tentatively attributed to the earliest Mississippian component of the site, or about A.D. 900.
In the late 1970s, human remains representing a minimum of three individuals were removed from Auburn's site A (9Ce125),
Site 9CE125 consists of four components. Dates for these components include Middle Woodland (300 B.C.-A.D. 100), Early Mississippian (A.D. 900-1250), Late Mississippian (A.D. 1400-1550), and historic.
In 1959, human remains representing two individuals were removed from Upatoi Bridge, Opossum Creek (9Me41), Muscogee County, GA, by Sergeant Chase, after they had been uncovered during landscaping work. No known individuals were identified. The 118 associated funerary objects recovered from burial fill are 55 ceramic sherds, 48 chert flakes, 2 quartz flakes, 4 unidentified lithic flakes, 1 chert biface, 1 chert projectile point, and 7 charcoal fragments. These human remains and associated funerary objects were housed at the Riverbend Research Laboratory, University of Georgia, Columbus, GA, until 1999, when they were transferred to the Mandatory Center of Expertise for the Curation and Management of Archaeological Collections, St. Louis, MO, for rehabilitation. In July 2001, these human remains were transferred to Fort Benning, GA.
The burial has been dated to the Late Woodland (A.D. 100-900) component of the site.In 1958 and 1959, human remains representing three individuals were removed from Yuchi Town (site 1RU63), Russell County, AL, by Sgt. David Chase after the burials were discovered during the Smithsonian Institution’s River Basin Survey work on the Chattahoochee River. No known individuals were identified. The one associated funerary object is a shallow reconstructed ceramic bowl. These human remains and associated funerary object were housed at Southeastern Archeological Services, Athens, GA, until 1999, when they were transferred to the Mandatory Center of Expertise for the Curation and Management of Archaeological Collections, St. Louis, MO, for rehabilitation. In July 2001, these human remains and associated funerary object were transferred to Fort Benning, GA.
In 1962 and 1963, additional human remains representing a minimum of 13 individuals were removed from the Yuchi Town site (1RU63) and given to the Columbus Museum of Arts and Sciences by Harold Huscher of the Smithsonian Institution. No known individuals were identified. The 933 associated funerary objects present are 558 ceramic sherds and fragments, 2 reconstructed ceramic objects, 1 antler fragment, 2 belt buckle fragments, 4 brass button fragments, 6 brick fragments, 4 charcoal fragments, 16 chert flakes, 1 chert biface fragment, 1 chert projectile point, 4 clumps of potters clay, 1 copper aglet, 36 daub fragments, 199 faunal remains and fragments, 1 glass bead fragment, 4 glass bottle fragments, 4 glass fragments, 2 gunflint fragments, 1 lead fragment, 1 leaf fragment, 37 lithic flakes and fragments, 47 shell fragments, and 1 wood fragment. The human remains and associated funerary objects were housed at the Columbus Museum of Arts and Sciences, Columbus, GA, until 1999, when they were transferred to the Mandatory Center of Expertise for the Curation and Management of Archaeological Collections, St. Louis, MO, for rehabilitation. In July 2001, these human remains and associated funerary objects were transferred to Fort Benning, GA. Additional remains and associated funerary objects were noted in the original field notes, but these materials were removed by Mr. Huscher to the Smithsonian Institute. These materials were unavailable for review by the Mandatory Center of Expertise for the Curation and Management of Archaeological Collections.
The Yuchi Town site is believed to represent the remains of a well-populated Yuchi (or Uchee) settlement that was documented by European-Americans who visited the area in the late 18th century. It has been described as the "mother town" of the Yuchi east of the Mississippi during the 18th and early 19th centuries (Schnell, Frank T. 1982. Cultural Resources Investigations of Site 1Ru63 and 9Ce66 Fort Benning, Alabama and Georgia. Submitted to U.S. Army Corps of Engineers, Savannah District, p. 4-7; Elliott, Daniel T., Jeffrey L. Holland, Phil Thomason, Michael Emric, and Richard W. Stoops, Jr. 1995. Historic Preservation Plan for the Cultural Resources on U.S. Army Installations at Fort Benning Military Reservation, Chattahoochee and Muscogee Counties, Georgia, and Russell County, Alabama. Garrow and Associates, Atlanta, p. 82). There also appears to have been an unidentified 17th century Creek town at the same location (Elliott and others, 1995:147). Human remains from the site are believed to primarily represent Yuchi individuals; however some burials may represent individuals from earlier occupations of the site.
An inventory of the human remains and associated funerary objects and review of the accompanying documentation indicates that the area encompassing Fort Benning was probably occupied or used aboriginally and/or historically by the Yuchi and Muscogee-speaking people generally identified as Creek by English colonists and subsequent settlers. Fort Benning is located in part on land adjudicated to the Creek by the Indian Claims Commission. Creek groups occupied the Fort Benning vicinity from the late 17th century through the early 19th century; the Yuchi entered the area in the 18th century. The Seminole are descendants of a combination of Florida tribes identified by Spanish explorers and colonists, Creek groups who migrated to Florida in the 18th century, and escaped African-American slaves. The Yuchi are not currently Federally recognized as a separate tribe, but are a distinct cultural entity within the Federally recognized Muscogee (Creek) Nation of Oklahoma. They are currently seeking Federal recognition.
Based on the above-mentioned information, officials at Fort Benning and the U.S. Army installation staff, U.S. Army Engineer District, St. Louis, Mandatory Center of Expertise for the Curation and Management of Archaeological Collections have determined that, pursuant to 43 CFR 10.2 (d)(1), the human remains listed above represent the physical remains of 25 individuals of Native American ancestry. Officials at Fort Benning and the U.S. Army installation staff, U.S. Army Engineer District, St. Louis, Mandatory Center of Expertise for the Curation and Management of Archaeological Collections have also determined that, pursuant to 43 CFR 10.2 (d)(2), the 1551 funerary objects listed above are reasonably believed to have been placed with or near individual human remains at the time of death or later as part of the death rite or ceremony. Lastly, officials at Fort Benning and the U.S. Army installation staff, the U.S. Army Engineer District, St. Louis, Mandatory Center of Expertise for the Curation and Management of Archaeological Collections have determined that, pursuant to 43 CFR 10.2 (e), there is a relationship of shared
This notice has been sent to officials of the Alabama-Coushatta Tribes of Texas; the Alabama-Quassarte Tribal Town, Oklahoma; the Coushatta Tribe of Louisiana; the Kialegee Tribal Town, Oklahoma; the Miccosukee Tribe of Indians of Florida; the Muscogee (Creek) Nation, Oklahoma; the Poarch Band of Creek Indians of Alabama; the Seminole Nation of Oklahoma; the Seminole Tribe of Florida; and the Thlopthlocco Tribal Town, Oklahoma. Representatives of any other Indian tribe that believes itself to be culturally affiliated with these human remains and associated funerary objects should contact Dr. Christopher E. Hamilton, Cultural Resource Manager, Fort Benning, GA 31905-5000, telephone (706) 545-2377, before September 30, 2002. Repatriation of the human remains and associated funerary objects to the Alabama-Coushatta Tribes of Texas; the Alabama-Quassarte Tribal Town, Oklahoma; the Coushatta Tribe of Louisiana; the Kialegee Tribal Town, Oklahoma; the Miccosukee Tribe of Indians of Florida; the Muscogee (Creek) Nation, Oklahoma; the Poarch Band of Creek Indians of Alabama; the Seminole Nation of Oklahoma; the Seminole Tribe of Florida; and the Thlopthlocco Tribal Town, Oklahoma, may begin after that date if no additional claimants come forward.
National Park Service, Interior.
Notice.
Notice is hereby given in accordance with the provisions of the Native American Graves Protection and Repatriation Act (NAGPRA), 43 CFR 10.9, of the completion of an inventory of Native American human remains and associated funerary object in the possession of the U.S. Department of Justice, Federal Bureau of Investigation (FBI), Louisville, KY.
This notice is published as part of the National Park Service’s administrative responsibilities under NAGPRA, 43 CFR 10.2 (c). The determinations within this notice are the sole responsibility of the museum, institution, or Federal agency that has control of these Native American human remains and associated funerary objects. The National Park Service is not responsible for the determinations within this notice.
A detailed assessment of the human remains was made by University of Louisville Staff Archaeologist Philip J. DiBlasi in consultation with representatives of the Absentee-Shawnee Tribe of Indians of Oklahoma; Delaware Nation, Oklahoma; Delaware Tribe of Indians, Oklahoma; Eastern Shawnee Tribe of Oklahoma; Miami Tribe of Oklahoma; Peoria Tribe of Indians of Oklahoma; and Shawnee Tribe, Oklahoma.
On January 27, 1999, a human cranium was recovered by FBI agents from Sean Adam Long. These human remains were purchased from Mr. Long by FBI agents acting in an undercover capacity. On February 18, 1999, a search warrant was executed at Mr. Long’s home near Madisonville, KY. Additional human remains were recovered by FBI agents during the search. The human remains consist of two human crania and two human teeth. One associated funerary object was also recovered during the search. Osteological assessment of the human remains recovered on January 27 and February 18, 1999, indicate that they represent five individuals of Native American ancestry. No known individuals were identified.
A label on the interior of the box in which one cranium was recovered reads ”Caldwell County.” Information provided by Mr. Long indicates these human remains were excavated from an archeological site in Caldwell County, KY. Osteological evidence indicates that these human remains were most likely buried during the Prehistoric period (before A.D. 1740). Archeological and historical evidence indicates that the Native American population that lived in Caldwell County, KY during the Prehistoric period is ancestral to the present-day Delaware Nation, Oklahoma; Delaware Tribe of Indians, Oklahoma; and Peoria Tribe of Indiana of Oklahoma.
Information provided by Mr. Long indicates that the two teeth representing two individuals were excavated from archeological sites in western Kentucky. Osteological evidence indicates that these human remains were most likely buried during the Prehistoric period (before A.D. 1740). Archeological and historical evidence indicates that the Native American population that lived in western Kentucky during the Prehistoric period is ancestral to the present-day Delaware Nation, Oklahoma; Delaware Tribe of Indians, Oklahoma; and Peoria Tribe of Indians of Oklahoma.
The associated funerary object recovered on February 18, 1999, consists of fragments of one spherical shaped pottery vessel. The vessel is 4-5 inches in diameter and has two strap handles. Vessels of this type are almost exclusively found with sub-adults buried during the Mississipian period (A.D. 1250-1700). This funerary object is believed to have been associated with the human remains recovered from a site in western Kentucky. Archeological and historical evidence indicates that the Mississipian period population that lived in western Kentucky is ancestral to the present-day Delaware Nation, Oklahoma; Delaware Tribe of Indians, Oklahoma; and Peoria Tribe of Indiana of Oklahoma.
The determination of cultural affiliation for the remains of the two other individuals is included in a separate Federal Register notice.
On March 7, 2001, Sean Adam Long pleaded guilty in U.S. District Court in Owensboro, KY to three counts of illegal trafficking in Native American human remains [18 U.S.C. 1170 (a)] and one count of knowingly making a materially false, fictitious, or fraudulent statement or representation [18 U.S.C. 1001]. A single count of trafficking in interstate or foreign commerce in archaeological resources the excavation, removal, sale, purchase, exchange, transportation or receipt of which was wrongful under State or local law [16 U.S.C. 470ee (c)]
Based on the above-mentioned information, FBI officials determined that, pursuant to 43 CFR 10.2 (d)(1), the human remains listed above represent the physical remains of three individuals of Native American ancestry. FBI officials also determined that, pursuant to 43 CFR 10.2 (d)(2)(i), the object listed above is reasonably believed to have been placed with or near individual human remains at the time of death or later as part of a death rite or ceremony and to have been made exclusively for burial purposes. Lastly, FBI officials determined that, pursuant to 43 CFR 10.2 (e), there is a relationship of shared group identity that can be reasonably traced between the three Native American human remains and one associated funerary object from and the Peoria Tribe of Indians of Oklahoma; Delaware Nation, Oklahoma; and Delaware Tribe of Indians, Oklahoma.
This notice has been sent to officials of the Absentee-Shawnee Tribe of Indians of Oklahoma; Delaware Nation, Oklahama; Delaware Tribe of Indians, Oklahoma; Eastern Shawnee Tribe of Oklahoma; Miami Tribe of Oklahoma; Peoria Tribe of Indians of Oklahoma; and Shawnee Tribe, Oklahoma. Representatives of any other Indian tribe that believes itself to be culturally affiliated with these human remains and associated funerary object should contact Randy Ream, Assistant United States Attorney, 510 West Broadway, 10th Floor, Louisville, KY 40202, phone (502) 582-5911, before September 30, 2002. Repatriation of the human remains and associated funerary object to the Peoria Tribe of Indians of Oklahoma; Delaware Nation, Oklahoma; and Delaware Tribe of Indians, Oklahoma may begin after that date if no additional claimants come forward.
National Park Service, Interior.
Notice.
Notice is hereby given in accordance with provisions of the Native American Graves Protection and Repatriation Act (NAGPRA), 43 CFR 10.9, of the completion of an inventory of human remains and associated funerary objects in the possession of the Museum of Natural History and Planetarium, Roger Williams Park, Providence, RI.
This notice is published as part of the National Park Service’s administrative responsibilities under NAGPRA, 43 CFR 10.2 (c). The determinations within this notice are the sole responsibility of the museum, institution, or Federal agency that has control of these Native American human remains and associated funerary objects. The National Park Service is not responsible for the determinations within this notice.
A detailed assessment of the human remains were made by Museum of Natural History and Planetarium, Roger Williams Park, professional staff in consultation with representatives of the Osage Nation of Oklahoma and the Quapaw Tribe of Indians, Oklahoma.
In 1937, human remains representing one individual were removed from an unknown location in the Ozark Mountains, AR, by Otto Spring, Kent Spring, Charles H. Williams, Paul Santee, Harry Barton, and Fred Tebo. These human remains were received at an unknown date between 1937 and 1959 by Louis Pierce, of Providence, RI. Albert E. Hagenberg, a resident of Warwick, RI, acquired the human remains from the estate of Louis Pierce and sold them to the Museum of Natural History and Planetarium, Roger Williams Park, in 1959. No known individual was identified. No associated funerary objects are present.
The human remains consist of a thoracic vertebra with an embedded projectile point. The projectile point is characteristic of points made by people living in the Ozark Mountains during the last 3,000 years. Historical evidence, material culture, and oral history indicate that this region is part of the traditional territory of the Osage Nation of Oklahoma.
Based on the above-mentioned information, officials of the Museum of Natural History and Planetarium, Roger Williams Park, have determined that, pursuant to 43 CFR 10.2 (d)(1), the human remains listed above represent the physical remains of one individual of Native American ancestry. Officials of the Museum of Natural History and Planetarium, Roger Williams Park, also have determined that, pursuant to 43 CFR 10.2 (e), there is a relationship of shared group identity that can be reasonably traced between these Native American human remains and the Osage Nation of Oklahoma.
This notice has been sent to officials of the Osage Nation of Oklahoma and Quapaw Tribe of Indians, Oklahoma. Representatives of any other Indian tribe that believes itself to be culturally affiliated with these human remains should contact Marilyn Massaro, Curator of Collections, Museum of Natural History and Planetarium, Roger Williams Park, Providence, RI 02905, telephone (401) 785-9457, before September 30, 2002. Repatriation of the human remains to the Osage Nation of Oklahoma may begin after that date if no additional claimants come forward.
30-Day notice of information collection under review: Extension of a currently approved collection, Mental Health and Community Safety Initiative Application Kit.
The Department of Justice (DOJ), Office of Community Oriented Policing Services (COPS) has submitted the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection is published to obtain comments from the public and affected agencies. This proposed information collection was previously published in the
The purpose of this notice is to allow for an additional 30 days for public comment until September 30, 2002. This process is conducted in accordance with 5 CFR 1320.10.
Written comments and/or suggestions regarding the items contained in this notice, especially the estimated public burden and associated response time, should be directed to The Office of Management and Budget, Office of Information and Regulatory Affairs, Attention Department of Justice Desk
Request written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agencies estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
(1)
(2)
(3)
(4)
(5)
(6)
If additional information is required contact: Mrs. Brenda E. Dyer, Deputy Clearance Officer, United States Department of Justice, Information Management and Security Staff, Justice Management Division, Suite 1600, Patrick Henry Building, 601 D Street NW., Washington, DC 20530.
Pursuant to section 1008 of the Controlled Substances Import and Export Act (21 U.S.C. 958(i)), the Attorney General shall, prior to issuing a registration under this Section to a bulk manufacturer of a controlled substance in Schedule I or II and prior to issuing a regulation under section 1002(a) authorizing the importation of such a substance, provide manufacturers holding registrations for the bulk manufacture of the substance an opportunity for a hearing.
Therefore, in accordance with § 1301.34 of Title 21, Code of Federal Regulations (CFR), notice is hereby given that on May 9, 2002, Applied Science Labs, Inc., A Division of Alltech Associates, Inc., 2701 Carolean Industrial Drive, State College, Pennsylvania 16801, made application by renewal to the Drug Enforcement Administration to be registered as an importer of the basic classes of controlled substances listed below:
The firm plans to import these controlled substances for the manufacture of reference standards.
Any manufacturer holding, or applying for, registration as a bulk manufacturer of these basic classes of controlled substances may file written comments on or objections to the application described above and may, at the same time, file a written request for a hearing on such application in accordance with 21 CFR 1301.43 in such form as prescribed by 21 CFR 1316.47.
Any such comments, objections or requests for a hearing may be addressed, in quintuplicate, to the Deputy Assistant Administrator, Office of Diversion Control, Drug Enforcement Administration, United States Department of Justice, Washington, DC 20537, Attention: DEA Federal Register Representative (CCR), and must be filed no later than (30 days from publication).
This procedure is to be conducted simultaneously with and independent of the procedures described in 21 CFR 1301.34(b), (c), (d), (e), and (f). As noted in a previous notice at 40 CFR 43745-46 (September 23, 1975), all applicants for registration to import the basic classes of any controlled substances in Schedule I or II are and will continue to be required to demonstrate to the Deputy Assistant Administrator, Office of Diversion Control, Drug Enforcement Administration that the requirements for such registration pursuant to 21 U.S.C. 958(a), 21 U.S.C. 823(a), and 21 CFR 1301.34(a), (b), (c), (d), (e), and (f) are satisfied.
30-Day Notice of Information Collection Under Review; ABC change of Address Form and Special Filing Instructions for ABC Class Members; Form I-855.
The Office of Management and Budget (OMB) approval is being sought for the information collection listed below. This proposed information collection was previously published in the
The purpose of this notice is to allow an additional 30 days for public comments. Comments are encouraged and will be accepted until; September 30, 2002. This process is conducted in accordance with 5 CFR 1320.10.
Written comments and/or suggestions regarding the item(s) contained in this notice, especially regarding the estimated public burden and associated response time, should be directed to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attention: Department of Justice Desk Officer, Washington, DC 20503. Comments may also be submitted to the Department of Justice (DOJ), Justice Management Division, Information Management and Security Staff, Attention: Department Clearance Officer, Patrick Henry Building, 601 D Street, NW., Suite 1600, Washington, DC 20530. Comments may also be submitted to DOJ via facsimile to 202-514-1534.
Written comments and suggestions from the public and affected agencies should address one or more of the following four points:
(1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Overview of this information collection:
(1)
(2)
(3)
(4)
(5)
(6)
If you have additional comments, suggestions, or need a copy of the proposed information collection instrument with instructions, or additional information, please contact Mr. Richard A. Sloan, 202-514-3291, Director, Regulations and Forms Services Division, Immigration and Naturalization Service, U.S. Department of Justice, Room 4034, 425 I Street, NW., Washington, DC 20536.
If additional information is required contact: Mr. Robert B. Briggs, Clearance Officer, United States Department of Justice, Information Management and Security Staff, Justice Management Division, Patrick Henry Building, 601 D Street, NW., Suite 1600, Washington, DC 20530.
30-Day notice of information collection under review: Change of address; Form I-697.
The Department of Justice, Immigration and Naturalization Service (INS) has submitted the following information collection request to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995. The information collection was previously published in the
The purpose of this notice is to allow an additional 30 days for public comments. Comments are encouraged and will be accepted until September 30, 2002. This process is conducted in accordance with 5 CFR 1320.10.
Written comments and/or suggestions regarding the items contained in this notice, especially regarding the estimated public burden and associated response time, should be directed to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attention: Department of Justice Desk Officer, 725 17th Street, NW., Room 10235, Washington, DC 20530.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information should address one or more of the following four points:
(1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Overview of this information collection:
(1)
(2)
(3)
(4)
(5)
(6)
If you have additional comments, suggestions, or need a copy of the proposed information collection instrument with instructions, or additional information, please contact Richard A. Sloan 202-514-3291, Director, Regulations and Forms Services Division, Immigration and Naturalization Service, U.S. Department of Justice, Room 4304, 425 I Street, NW., Washington, DC 20536. Additionally, comments and/or suggestions regarding the item(s) contained in this notice, especially regarding the estimated public burden and associated response time may also be directed to Mr. Richard A. Sloan.
If additional information is required contact: Mr. Robert B. Briggs, Clearance Officer, United States Department of Justice, Information Management and Security Staff, Justice Management Division, Patrick Henry Building, 601 D Street, NW., Suite 1600, Washington, DC 20530.
30 Day notice of information collection under review: Registration for classification as refugee; Form I-590.
The Department of Justice, Immigration and Naturalization Service (INS) has submitted the following information collection request to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995. The information collection was previously published in the
The purpose of this notice is to allow an additional 30 days for public comments. Comments are encouraged and will be accepted until September 30, 2002. This process is conducted in accordance with 5 CFR 1320.10.
Written comments and/or suggestions regarding the items contained in this notice, especially regarding the estimated public burden and associated response time, should be directed to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attention: Department of Justice Desk Officer, 725-17th Street, NW., Room 10235, Washington, DC 20530.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information should address one or more of the following four points:
(1) Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
(2) Evaluate the accuracy of the agencies estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
Overview of this information collection:
(1)
(2)
(3)
(4)
(5)
(6)
If you have additional comments, suggestions, or need a copy of the proposed information collection instrument with instructions, or additional information, please contact Richard A. Sloan, 202-514-3291, Director, Regulations and Forms Services Division, Immigration and Naturalization Service, U.S. Department of Justice, Room 4304, 420 I Street, NW., Washington, DC 20536. Additionally, comments and/or suggestions regarding the item(s) contained in this notice, especially regarding the estimated public burden and associated response time may also be directed to Mr. Richard A. Sloan.
If additional information is required contact: Mr. Robert B. Briggs, Clearance Officer, United States Department of Justice, Information Management and Security Staff, Justice Management Division, 601 D Street, NW., Patrick Henry Building, Suite 1600, 1001 G Street, NW., Washington, DC 20530.
Employment Standards Administration, Labor.
Notice.
The Department of Labor, as part of its continuing effort to reduce paperwork and respondent burden, conducts a preclearance consultation program to provide the general public and Federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995 (PRA95) [44 U.S.C. 3506(c)(2)(A)]. This program helps to ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized,
Written comments must be submitted to the office listed in the addressee section below on or before October 28, 2002.
Ms. Patricia A. Forkel, U.S. Department of Labor, 200 Constitution Ave., NW., Room S-3201, Washington, DC 20210, telephone (202) 693-0339, fax (202) 693-1451, e-mail
The Energy Employees Occupational Illness Compensation Program Act of 2000, as amended (EEOICPA or Act), 42 U.S.C. 7384
The Department of Labor is particularly interested in comments which:
* Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
* Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
* Enhance the quality, utility and clarity of the information to be collected; and
* Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
The Department of Labor seeks the approval of this information collection in order to carry out its responsibility to establish eligibility for benefits to those persons seeking compensation under EEOICPA. There is no standardized form or format associated with the information request, and each private entity may determine the most convenient methodology to respond. The OWCP will accept responses via e-mail, telephone, FAX or mail.
Comments submitted in response to this notice will be summarized and/or included in the request for Office of Management and Budget approval of the information collection request; they will also become a matter of public record.
Mine Safety and Health Administration, Labor.
Notice.
The Department of Labor, as part of its continuing effort to reduce paperwork and respondent burden, conducts a preclearance consultation program to provide the general public and Federal agencies with an opportunity to comment on the continuing collection of information in accordance with the Paperwork Reduction Act of 1995 (PRA95) [44 U.S.C. 3506(c)(2)(A)]. This program helps to ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized, collection instruments are clearly understood, and the impact of collection requirements on respondents can be properly assessed.
Currently, the Mine Safety and Health Administration (MSHA) is soliciting comments concerning the proposed extension of the information collection related to the Noise Exposure Assessment; Audiometric Testing, Evaluation, and Records and Training in all Mines. MSHA is particularly interested in comments which:
• Evaluate whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
A copy of the information collection request can be obtained by contacting the employee listed below in the
Submit comments on or before October 28, 2002.
Send comments to David L. Meyer, Director, Office of Administration and Management, 1100 Wilson Boulevard, Room 2125, Arlington, VA 22209-3939. Commenters are encouraged to send their comments on a computer disk, or via Internet e-mail to
Jane Tarr, Management Analyst, Records Management Group, U.S. Department of Labor, Mine Safety and Health Administration, Room 2171, 1100 Wilson Boulevard, Arlington, VA 22209-3939. Ms. Tarr can be reached at
Noise is one of the most pervasive health hazards in mining. Exposure to hazardous sound levels results in the development of occupational noise-induced hearing loss (NIHL), a serious physical, psychological, and social problem. NIHL can be distinguished from aging and medical factors, diagnosed, and prevented. NIHL is among the “top ten” leading occupational diseases and injuries.
For many years, the risk of acquiring an NIHL was accepted as an inevitable consequence associated with mining occupations. Miners use mechanized equipment and work under conditions that often expose them to hazardous sound levels. But MSHA standards, OSHA standards, military standards, and others around the world have been established in recognition of the controllability of this risk. Records of miner exposures are necessary so that mine operators and MSHA can evaluate the need for and effectiveness of engineering controls, administrative controls, and personal protective equipment to protect miners from harmful levels of exposure.
Records of miner exposures are necessary so that mine operators and MSHA can ensure that engineering controls, administrative controls, and personal protective equipment are used to protect miners from harmful levels of exposure. However, the Agency believes that extensive records for this purpose now maintained by the coal mining sector are not needed, Part 62 replaced these requirements with a performance-oriented approach to monitoring. The final rule expanded notification of exposure information to miners to assist them in becoming more active participants in hearing conservation efforts.
Hearing tests of miners are offered and if a miner takes the test mine operators are required to compile and maintain a record of each audiometric test. Detection of a hearing loss can trigger certain protective actions under Part 62. The record will be used by mine operators and MSHA to verify that the testing was done and the required actions implemented.
Part 62 also requires the mine operator to provide training to overexposed miners about the hazards of noise exposure, hearing protector selection and use, the hearing test program, and the operator's noise controls. Records of training are needed to confirm that miners receive the information they need to become active participants in hearing conservation efforts. There is no existing requirement for such records; however, training records required under other MSHA regulations are used for similar purposes.
Comments submitted in response to this notice will be summarized and/or
In accordance with the Federal Advisory Committee Act (Pub. L. 92-463, as amended) the National Science Foundation announces the following meeting.
Nuclear Regulatory Commission.
Finding of No Significant Impact.
The U.S. Nuclear Regulatory Commission (NRC) proposes to accept the license amendment for the NRC Materials License SUA-1358 to authorize the licensee, International Uranium (USA) Corporation (IUSA), to allow for the receipt and processing of material from the Maywood facility located in Maywood, New Jersey, at IUSA's White Mesa uranium mill, located near Blanding, Utah. An Environmental Assessment was performed by the NRC staff in accordance with the requirements of 10 CFR part 51. The conclusion of the Environmental Assessment is a Finding of No Significant Impact (FONSI) for the proposed licensing action.
Mr. William von Till, Fuel Cycle Facilities Branch, Division of Fuel Cycle Safety and Safeguards, Office of Nuclear Material Safety and Safeguards, U.S. Nuclear Regulatory Commission, Mail Stop T-8A33, Washington, DC 20555. Telephone (301) 415-6251, e-mail
Materials License SUA-1358 was originally issued by NRC on August 7, 1979, Pursuant to Title 10, Code of Federal Regulations (10 CFR), part 40, “Domestic Licensing of Source Material.” The IUSA site is licensed by the NRC under Materials License SUA-1358 to possess byproduct material in the form of uranium waste tailings and other uranium byproduct waste generated by the licensee's milling operations, as well as other source material from multiple locations. Some of these locations include material from Formerly Utilized Sites Remedial Action Program (FUSRAP) sites managed by the U.S. Army Corps of Engineers (USACE). These materials have similar chemical, physical, and radiological composition to conventional mill tailings. The mill is currently operating.
The NRC staff performed an appraisal of the environmental impacts associated with the receipt and processing of materials from the Maywood facility at the White Mesa mill, in accordance with 10 CFR part 51, Licensing and Regulatory Policy Procedure for Environmental Protection. A draft Environmental Assessment was sent to the State of Utah Department of Environmental Quality (DEQ) and Ute Mountain Utes by letter dated September 21, 2001, and was made public. The NRC staff received multiple comments from the public, the Utah DEQ, and the Ute Mountain Ute tribe. Based on some of the comments concerning potential groundwater impacts, the NRC staff requested that IUSA provide additional information regarding the potential for groundwater seepage to occur while the Maywood material would be temporarily stored on the ore pad. IUSA conducted a series of infiltration permeability tests on the ore pad soils and addressed the NRC staff concerns by letter dated July 1, 2002. In addition IUSA addressed issues concerning dust control by letters dated February 15, 2002, and March 11, 2002. In conducting its appraisal, the NRC staff considered the following: (1) Information contained in previous environmental evaluations of the White Mesa project; (2) information contained in the IUSA's amendment application dated June 15, 2001, June 22, 2001, August 3, 2001, and supplemented by letters dated, November 19, 2001, December 6, 2001, December 10, 2001, March 11, 2002, and July 1, 2002; (3) information derived from NRC staff site visits and inspections of the White Mesa mill site, and (4) comments from and conversations with the State of Utah Department of Environmental Quality (DEQ), the Ute Mountain Ute tribe, and the public. The results of the staff's appraisal are documented in an Environmental Assessment.
The NRC staff has examined the actual and potential environmental impacts associated with the receipt and processing of the proposed Maywood material, and has determined that the action is (1) consistent with requirements of 10 CFR part 40, (2) will not be inimical to the public health and safety, and (3) will not have long-term detrimental impacts on the environment. The following statements support the FONSI and summarize the conclusions resulting from the staff's environmental assessment:
1. An acceptable environmental and effluent monitoring program is in place to monitor effluent releases and to detect whether applicable regulatory limits are exceeded. Radiological
2. Present and potential environmental impacts from the receipt and processing of the Maywood material were assessed. By letter dated August 5, 2002, the U.S. Department of the Interior, Fish and Wildlife Service, concurred with the staff's determination of “No Effect” for threatened and endangered species, and critical habitat. No significant impacts have been identified as a result of this action. Therefore, the staff has determined that the risk factors for health and environmental hazards are insignificant.
The action that the NRC is considering is approval of an amendment request to a source material license issued pursuant to 10 CFR part 40. The alternatives available to the NRC are:
1. Approve the license amendment request as submitted; or
2. Amend the license with such additional conditions as are considered necessary or appropriate to protect public health and safety and the environment; or
3. Deny the request.
Based on its review, the NRC staff has concluded that the environmental impacts associated with the proposed action do not warrant either the limiting of IUSA's future operations or the denial of the license amendment. The NRC staff has concluded that there are no significant environmental impacts associated with the proposed action. Therefore, alternatives with equal or greater impacts need not be evaluated. Additionally, in the Technical Evaluation Report prepared for this action, the staff has reviewed the licensee's proposed action with respect to the criteria for the receipt and processing of alternate feed material, specified in NRC's formal guidance entitled “Guidance on the Use of Uranium Mill Feed Material other than Natural Ores,” and has no basis for denial of the proposed action. Therefore, the staff considers that Alternative 1 is the appropriate alternative for selection.
The NRC staff has prepared an Environmental Assessment for the proposed receipt and processing of Maywood Material for NRC Source Material License SUA-1358. On the basis of this assessment, the NRC staff has concluded that no significant environmental impact will result for the proposed action, and therefore, preparation of an Environmental Impact Statement is not warranted.
The Environmental Assessment and other documents related to this proposed action are available for public inspection and copying at the NRC Public Document Room, U.S. Nuclear Regulatory Commission Headquarters, Room 0-1F21, 11555 Rockville Pike, Rockville, MD 20852.
Members of the public may provide comments on the subject application within 30 days of the publication of this notice in the
For the U.S. Nuclear Regulatory Commission.
The U.S. Nuclear Regulatory Commission (NRC) is considering issuance of an amendment to Title 10 of the Code of Federal Regulations (10 CFR) part 50, § 50.90 for Facility Operating License No. NPF-12, issued to South Carolina Electric & Gas Company (SCE&G, the licensee), for operation of the Virgil C. Summer Nuclear Station (VCSNS), located in Fairfield County, South Carolina. As required by 10 CFR 51.21, the NRC is issuing this environmental assessment and finding of no significant impact.
The proposed action would increase the spent fuel pool (SFP) storage capacity by replacing all 11 existing rack modules with 12 new storage racks. The rerack will increase the storage capacity from 1,276 storage cells to 1,712 storage cells. The new racks will have Boral neutron-absorbing material instead of the degrading Boraflex used in the existing racks.
The proposed action is in accordance with the licensee's application dated July 24, 2001, as supplemented by letters dated April 4, 2002, May 7, 2002, June 17, 2002, July 2, 2002, July 15, 2002, and July 25, 2002.
SCE&G currently expects VCSNS to lose the capacity for full-core offload during refueling operations in 2008 (after Cycle 17). SCE&G has evaluated spent fuel storage options that have been licensed by the NRC and are currently feasible for use at the VCSNS site. The evaluation concluded that reracking the SFP is currently the most cost-effective alternative. Reracking would increase storage capacity and maintain the plant's capability to accommodate a full-core discharge until the end of Cycle 24 in 2018.
Spent resins are generated by the processing of SFP water through the SFP purification system. The licensee predicts that the installation of the new racks will generate slightly more resin from the new, increased capacity rack installation; therefore, the licensee may more frequently change-out the SFP purification system during the reracking operation. In order to keep the SFP water reasonably clear and clean and thereby minimize the generation of spent resins, the licensee will vacuum the floor of the SFP as necessary to remove any radioactive crud, sediment, and other debris before the new fuel rack modules are installed. The filters from this underwater vacuum will be a minor source of solid radioactive waste. However, the licensee does not expect that the increase in storage capacity of the SFP will result in a significant change in the long-term generation of solid radioactive waste at VCSNS.
The disposal of the used spent fuel racks will result in a one-time
The storage of additional spent fuel assemblies in the SFP is not expected to affect the releases of radioactive gases from the SFP. Gaseous fission products such as krypton-85 and iodine-131 are produced by the fuel in the core during reactor operation. Small amounts of these fission gases are released to the reactor coolant from the small number of fuel assemblies that develop leaks during reactor operation. During refueling operations, some of these fission products enter the SFP and are subsequently released into the air. Since the frequency of refuelings, and therefore the number of freshly off-loaded spent fuel assemblies stored in the SFP at any one time, will not increase, there will be no increase in the amounts of gaseous fission products released to the atmosphere as a result of the increased SFP fuel storage capacity.
The increased heat load on the SFP from the storage of additional spent fuel assemblies could potentially increase the SFP evaporation rate. However, based on previous reracks at other facilities, this increased evaporation rate is not expected to significantly increase the amount of gaseous tritium released from the pool. Thus, the licensee does not expect the concentrations of airborne radioactivity in the vicinity of the SFP to significantly increase due to the expanded SFP storage capacity. This is consistent with the operating experience to date with previous SFP expansions. Gaseous effluents from the spent fuel storage area are combined with other station exhausts and monitored before release. Past SFP area contributions to the overall site gaseous releases have been insignificant and should remain negligible with the increased capacity. The impact of any increases in site gaseous releases should be negligible, and the resultant doses to the public will remain very small fractions of the 10 CFR part 20 and 10 CFR part 50, appendix I, dose limits.
The release of radioactive liquids will not be affected directly as a result of the SFP expansion. The SFP ion exchanger resins remove soluble radioactive materials from the SFP water. When the resins are changed out, the small amount of resin sluice water is processed by the radioactive waste system before release to the environment. As stated above, the frequency of resin change out may increase slightly during the installation of the new racks. However, the increase in the amount of liquid effluents released to the environment as a result of the proposed SFP expansion is expected to be negligible.
The NRC staff has reviewed the licensee's plan for the modification of the VCSNS spent fuel racks with respect to occupational radiation exposure. As stated above, the licensee plans to remove the 11 existing fuel racks and install 12 new racks in the SFP. Based on the lessons learned from a number of facilities that have performed similar operations in the past and their experience with reracks, the licensee estimates that the collective occupational worker dose for the proposed fuel rack project will be between 6 and 12 person-rem.
All of the operations involved in the removal of existing racks and the installation of the new fuel racks will be governed by procedures. These procedures are based on the principle of keeping doses as low as reasonably achievable (ALARA), consistent with the requirements of 10 CFR part 20. The radiation protection department will prepare a radiation work permit (RWP) for the various in-pool and out-of-pool jobs. The RWP and supporting job procedures will establish requirements for timely external radiation and airborne surveys, personal protective clothing and equipment, individual monitoring devices, and other access and work controls consistent with good radiation protection practices and 10 CFR part 20 requirements. Continuous health physics technician (HPT) coverage will be provided and maintained when a diver is in the pool, and when any potentially contaminated object is being removed from the pool. Each member of the project team will receive radiation protection training on the reracking operations consistent with the requirements of 10 CFR part 19. Project-specific training will include hot particle hazards and the potential for extremity doses from working in the fuel pool or with the old racks (
For out-of-pool work activities, all workers will be provided with thermoluminescence dosimeters (TLDs) and electronic alarm dosimeters. Additional personal monitoring devices (
The VCSNS SFP rerack project will use qualified underwater divers for both rack removal and installation. No divers will be allowed in the SFP during any movement of spent fuel to ensure that these divers are not exposed to high and very high radiation sources (
An underwater vacuum system will be used to supplement the installed SFP filtration system so that the levels of radiation and contamination, including hot particles and debris, can be reduced before diving operations. The SFP floor dive area will be vacuum-cleaned with long-handled tools from above the pool. Final radiation surveys and visual inspection by underwater camera will be performed before any diving activities. These actions to identify and control hot particles and debris should effectively minimize the potential for unplanned diver exposures from these sources.
Before the old fuel racks are removed from the pool, they will be cleaned underwater using high-pressure washing. After cleaning, while the racks are still over the pool, radiation surveys will be performed to determine if further decontamination is needed before the racks are prepared for shipment off-site. The racks will be bagged remotely to minimize potential worker contamination and maintain doses ALARA. Once properly packaged in approved shipping containers, the racks will be shipped in accordance with Department of Transportation and NRC regulations. The licensee will use the existing SFP filtration system during fuel rack installation to maintain water clarity in the SFP. These engineering controls and handling procedures will help minimize the spread of contamination (
The storage of additional spent fuel assemblies in the SFP, and the reduction in minimum cooling time from 100 hours down to 72 hours before fuel movement, will result in negligible increases in the external dose rates on the refueling floor and in accessible areas adjacent to the SFP. Existing normally accessible areas around the fuel storage pool are designated Radiation Zone II. That designation will be maintained with the external dose rates remaining less than 2.5 mrem/hr. The maximum dose rates outside the concrete walls of the SFP will remain less than 0.01 mrem/hr. The area most impacted by the pool rerack is the fuel transfer canal (FTC), assuming it to be drained and empty. Assuming an empty FTC, to keep radiation levels below 2.5 mrem/hr, procedures will require that no fuel except old fuel be stored near the gate slot to the FTC. Normally, the FTC will be filled with water.
On the basis of our review of the VCSNS proposal, the NRC staff concludes that the SFP rerack can be performed in a manner that will ensure that doses to the workers will be maintained ALARA. The NRC staff finds the projected dose for the project of about 6 to 12 person-rem to be appropriate and in the range of doses for similar SFP modifications at other plants, and therefore acceptable.
The design-basis FHA analysis postulates that a spent fuel assembly is dropped during refueling, damaging all of the rods in the assembly plus 50 additional rods in an adjacent assembly (a total of 314 rods). The design of the fuel handling equipment makes it very likely that a dropped assembly would result in the release of fission products. The accident analysis assesses whether design features for mitigating environmental releases meet certain design criteria. At VCSNS, this accident could happen inside the containment (CNMT) or in the fuel handling building (FHB), and SCE&G has evaluated both cases.
The SCE&G analyses assume that core inventory is based on 5-percent by weight initial enrichment fuel and extended operation at 2958 MWt power. The core inventory was determined using the NRC-sponsored SCALE computer code suite. SCE&G considered five fuel burnup exposures ranging from 35,000 MWt/MTU to 70,000 MWt/MTU. (This assessment does not address operation above a burnup of 62,000 MWt/MTU.) Since individual radionuclides reach peak equilibrium values at different rates, the highest specific inventory of each contributing radionuclide in any of the burnup ranges was used in the analyses. A decay period of 72 hours between reactor shutdown and fuel movement was assumed. Since the power level and, hence, the inventory in each assembly varies across the core, a radial peaking factor of 1.7 is applied to the average core inventory. SCE&G assumed that 12 percent of the I-131 inventory of the core was in the fuel rod gap, along with 30 percent of the Kr-85, and 10 percent of all other iodines and noble gases. The radioiodine in the gap was assumed to be 99.75 percent elemental and 0.25 percent organic forms.
SCE&G assumes that all of the gap inventory in the 314 damaged fuel rods is instantaneously released through the water in the reactor cavity or SFP into the CNMT or FHB, respectively. SCE&G assumes that 100 percent of the activity release to the CNMT or FHB is released to the environment in 2 hours. Credit was taken for the FHB purge exhaust charcoal filters, but no credit was taken for the reactor building purge exhaust charcoal filters.
Details on the assumptions found acceptable to the NRC staff are presented in the attached Table. The offsite doses estimated by the licensee for the postulated FHAs were found to be acceptable.
The NRC has completed its evaluation of the proposed action and concludes that the proposed action will not significantly increase the probability or consequences of accidents, no changes are being made in the types of effluents that may be released off site, and there is no significant increase in occupational or public radiation exposure. The incremental 1-year increase in waste is bounded by the plant's original licensing basis and is therefore acceptable. Therefore, there are no significant radiological environmental impacts associated with the proposed action.
With regard to potential nonradiological impacts, the proposed action does not have a potential to affect any historic sites. It does not affect nonradiological plant effluents and has no other environmental impact. Therefore, there are no significant nonradiological environmental impacts associated with the proposed action.
Accordingly, the NRC concludes that there are no significant environmental impacts associated with the proposed action.
According to Holtec Report HI-20112624, “Fuel Storage Expansion at Virgil C. Summer for South Carolina Electric & Gas,” the following alternative actions were considered:
Rod consolidation has been shown to be a potentially feasible technology. Rod consolidation involves disassembly of one [fuel assembly] and the disposal of the fuel assembly skeleton outside of the pool (this is considered a 2:1 compaction ratio). The rods are stored in a stainless steel can that has the outer dimensions of a fuel assembly. The can is stored in the spent fuel racks. The top of the can has an end fixture that matches up
Rod consolidation pilot project campaigns in the past have consisted of underwater tooling that is manipulated by an overhead crane and operated by a maintenance worker. This is a very slow and repetitive process.
The industry experience with rod consolidation has been mixed thus far. The principal advantages of this technology are: The ability to modularize, compatibility with the U.S. Department of Energy (DOE) waste management system, moderate cost, no need of additional land and no additional required surveillance. The disadvantages are: potential gap activity release due to rod breakage; potential for increased fuel cladding corrosion due to some of the protective oxide layer being scraped off; potential interference of the (prolonged) consolidation activity, which might interfere with ongoing plant operation; and lack of sufficient industry experience. The drawbacks associated with consolidation are expected to diminish in time. However, it is the SCE&G's view that rod consolidation technology has not matured sufficiently to make this a viable option for the present VCSNS spent fuel pool limitations.
Dry cask storage is a method of storing spent nuclear fuel in a high capacity container. The cask provides radiation shielding and passive heat dissipation. Typical capacities for pressurized-water reactor fuel range from 21 to 37 assemblies that have been removed from the reactor for at least 5 years. The casks, once loaded, are then stored outdoors on a seismically qualified concrete pad.
The casks, as presently licensed, are limited to 20-year storage service life. Once the 20 years has expired, the cask manufacturer or the utility must recertify the cask or the utility must remove the spent fuel from the container. In the interim, DOE has embraced the concept of multi-purpose canisters obsolescing all existing licensed cask designs. Work is also continuing by several companies, including Holtec International, to provide an [a] multi-purpose canister system that will be capable of long storage, transport, and final disposal in a repository. Holtec International's HI-STAR System can store up to 24 pressurized-water reactor assemblies. It is noted that a cask system makes substantial demands on the resources of a plant. For example, the plant must provide for a decontamination facility where the outgoing cask can be decontaminated for release.
There are several plant modifications required to support cask use. Tap-ins must be made to the gaseous waste system, and chilled water to support vacuum drying of the spent fuel and piping must be installed to return cask water back to the Spent Fuel Pool/Cask Loading Pit. A seismic concrete pad must be made to store the loaded casks. This pad must have a security fence, surveillance protection, a diesel generator for emergency power, and video surveillance for the duration of fuel storage, which may extend beyond the life of the adjacent plant. Finally, the cask park must have facilities to vacuum dry the cask, backfill it with helium, make leak checks, remachine the gasket surfaces if leaks persist, and assemble the cask on-site.
To summarize, based on the required short time schedule, the status of the dry spent fuel storage industry, and the storage expansion costs, the most acceptable alternative for increasing fuel storage capacity at VCSNS is expansion of the wet storage capacity.
As an alternative to the proposed action, the staff considered denial of the proposed action (
The alternative technologies that could create additional storage capacity involve additional fuel handling with increased opportunity for fuel handling accidents, involve higher commutative doses to workers affecting the fuel transfers and would not result in a significant improvement in environmental impacts compared to the proposed reracking modifications.
The action does not involve the use of any different resources than those previously considered in the Final Environmental Statement for VCSNS (NUREG-0719) dated May 1981.
On July 23, 2002, the staff consulted with the South Carolina State official, Mr. Henry Porter of the South Carolina Department of Health and Environmental Control, regarding the environmental impact of the proposed action. The State official had no comments.
On the basis of the environmental assessment, the NRC concludes that the proposed action will not have a significant effect on the quality of the human environment. Accordingly, the NRC has determined not to prepare an environmental impact statement for the proposed action.
For further details with respect to the proposed action, see the licensee's letter dated July 24, 2001, and supplemental letters dated April 4, 2002, May 7, 2002, June 17, 2002, July 2, 2002, July 15, 2002, and July 25, 2002. Documents may be examined, and/or copied for a fee, at the NRC's Public Document Room (PDR), located at One White Flint North, 11555 Rockville Pike (first floor), Rockville, Maryland. Publicly available records will be accessible electronically from the Agencywide Documents Access and Management System (ADAMS) Public Electronic Reading Room on the Internet at the NRC Web site,
For the Nuclear Regulatory Commission.
The U.S. Nuclear Regulatory Commission's (NRC's) Advisory Committee on Nuclear Waste (ACNW) will hold a public-outreach session on September 23, 2002, 5 p.m. to 7 p.m., at the Bob Ruud Community Center, 150 North Highway 160 and Basin Avenue, Pahrump, Nevada. This public-outreach session is a continuation of the ACNW's efforts to gain further insights into stakeholders' concerns and perspectives on the proposed geologic repository at Yucca Mountain, Nevada. There is no set agenda for the public-outreach session, and interested stakeholders will be able to discuss their views with ACNW members individually.
If you have any questions concerning this notice or intend to address the ACNW in the public-outreach session, please contact Michael P. Lee, ACNW Senior Staff Engineer, by telephone (301-415-6677), facsimile (301-415-5589), or e-mail (
Upon Written Request, Copies Available From: Securities and Exchange Commission, Office of Filings and Information Services, Washington, DC 20549-0004.
Notice is hereby given that, pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 350l
Rule 32a-4 [17 CFR 270.32a-4] is entitled “Independent Audit Committees.” The rule exempts a registered management investment company or registered face-amount certificate company (“fund”) fund from the requirements of section 32(a)(2) of the Investment Company Act that shareholders ratify or reject the selection of the fund's independent public accountant if the fund has an audit committee composed wholly of independent directors.
Instead of relying on rule 32a-4, a fund could seek ratification or rejection by shareholders of the selection of its independent public accountant at each annual meeting. Under the rule, a fund is exempt from having to seek shareholder approval of its independent public accountant, if (i) the fund's board of directors establishes an audit committee composed solely of independent directors with responsibility for overseeing the fund's accounting and auditing processes,
As conditions of relying on rule 32a-4, a fund's board of directors must adopt an audit committee charter and must preserve that charter, and any modifications to the charter, permanently in an easily accessible place. The information collection requirement in rule 32a-4 enables the Commission to monitor the duties and responsibilities of an independent audit committee formed by a fund relying on the rule. Commission staff estimates that there are approximately 3,700 management investment companies and face-amount certificate companies that could rely on the rule. We believe that approximately 9.7 percent (360) of those funds have taken advantage of the exemption since adoption of the rule, and approximately 2.7% (100) of the funds that have not already done so choose to rely on the rule each year. For each of those funds choosing for the first time to rely on the rule, we estimate that the adoption of the audit committee charter requires, on average, 1 hour of directors' time, 2.5 hours of professional time and 1 hour of support staff time, for a total one-time burden of burden of 4.5 hours, and an estimated total one-time cost of $555.40, resulting in an annual aggregate time burden of 450 hours and an annual aggregate cost of $55,540.
In addition to the hour burden described above, rule 32a-4 imposes certain costs on those funds that choose to rely on the exemption. These costs are minimal and are justified by the relief provided by the exemption. We estimate that each of the approximately 360 funds currently relying on the rule is required to spend approximately .5 hours annually to comply with the requirement that it preserve permanently its audit committee charters, for an additional annual hour burden of 180 hours, and an additional annual cost for all funds of $12,439.20.
The estimates of average burden hours and costs are made solely for the purposes of the Paperwork Reduction Act, and are not derived from a comprehensive or even a representative survey or study of the costs of Commission rules and forms.
The collections of information required by rule 32a-4 are necessary to obtain the benefits of the rule. The Commission is seeking OMB approval, because an agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid control number.
Written comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the Commission, including whether the information has practical utility; (b) the accuracy of the Commission's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Consideration will be given to comments and suggestions submitted in writing within 60 days of this publication.
Please direct your written comments to Michael E. Bartell, Associate Executive Director, Office of Information Technology, Securities and Exchange Commission, 450 5th Street, NW., Washington, DC 20549.
Pursuant to Rule 431(b)(2) of the Rules of Practice,
In considering whether to accept or reject the Knight Petition, Rule 411(b)(2) of the Rules of Practice
(i) A prejudicial error was committed by the Division in the conduct of the proceeding; or
(ii) The Division's decision embodies:
(A) a finding or conclusion of material fact that is clearly erroneous; or
(B) a conclusion of law that is erroneous; or
(C) an exercise of discretion or decision of law or policy that is important and that the Commission should review.
The Knight Petition does not allege that any prejudicial error was committed by the Division in the conduct of the proceedings, and the Commission finds that no such prejudicial error occurred. Moreover, the Commission finds that the Division's decision does not embody a finding of material fact that is clearly erroneous or a conclusion of law that is erroneous.
In so finding, the Commission notes that it previously has approved of securities being traded pursuant to unlisted trading privileges (“UTP”) and such approval applies generally to floor based exchanges without automatic execution of orders that engage in UTP trading.
In other words, Knight does not challenge the Amex's proposed rules that are the subject of the Division's approval order, but rather objects to the manner in which Amex's market will interact with other markets also trading Nasdaq securities pursuant to UTP. Such concerns are not properly cognizable in the context of the rule filing process for the Amex's trading rules. Rather, the proper venue for Knight's arguments was the notice and approval process for the 12th Amendment to OTC/UTP Plan,
To the extent that Knight does object to the Amex trading rules that were the subject of the Division's order, their objection is that Amex does not provide for automatic executions. As the Division correctly points out in its order, the standards applicable to the Amex proposal do not require that Amex provide automatic execution. We specifically so find and conclude ourselves. The Division considered all comments on the proposed Amex rules including Knight's, addressed them, and correctly applied the applicable standard.
Finally, because these rules—unlike the grant of UTP—do not raise any important issues, the Commission also finds that the Division's decision does not embody an exercise of discretion or a decision of law or policy that is important and that the Commission should review.
By the Commission.
[67 FR 54506, August 22, 2002].
Open meeting.
450 Fifth Street, NW., Washington, DC.
Tuesday, August 27, 2002 at 10 a.m.
Deletion of Item.
The following item will not be considered at the open meeting scheduled for Tuesday, August 27, 2002:
The Commission will consider whether to issue a notice of an application from The Mexico Fund, Inc. (the “Fund”) seeking certain exemptions from the Investment Company Act of 1940.
At times, changes in Commission priorities require alterations in the scheduling of meeting items. For further information and to ascertain what, if any, matters have been added, deleted or postponed, please contact: The Office of the Secretary at (202) 942-7070.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Amex proposes to waive transaction fees on Exchange-Traded Funds (“ETFs”) that are part of an exchange-for-physical transaction (“EFP”). The text of the proposed rule change is available at the Amex and at the Commission.
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for its proposal and discussed any comments it received regarding the proposal. The text of these statements may be examined at the places specified in Item IV below. The Amex has prepared summaries, set forth in Sections A, B and C below, of the most significant aspects of such statements.
The Exchange currently imposes a charge for transactions in ETF products executed on the Exchange. Currently, charges include fees for Registered Options Traders (“ROTs”), Specialists and Customer Broker-Dealers. The current rate for Specialist transactions in these products is $0.0063 per share ($0.63 per 100 shares), capped at $300 per trade (47,619 shares). The current rate for ROT transactions is $0.0073 per share ($.73 per 100 shares), capped at $350 per trade (47,945 shares). Off-floor orders (
The Amex now proposes that transaction fees paid in connection with ETFs be waived for EFP transactions. An EFP is a transaction in which one party buys the cash market and sells the futures market while the opposite party sells the cash market and buys the futures market. The terms of such transactions are privately negotiated. An EFP may be executed on or off the trading floor in the futures market while the cash side of the trade may be executed in the over-the-counter market or on the Exchange. Consistent with the Commodity Exchange Act (“CEA”) and the rules of the Chicago Mercantile Exchange (“CME”), ETFs are currently permitted by the CME to be used as the cash market side of certain stock index futures products. In such case, the cash market product is required to be comparable with respect to the quantity, value or risk exposure to the futures contract utilized.
The Exchange believes that ETF trades in connection with EFPs are taking place off-floor largely due to the imposition of transaction fees. As a result, the Amex has proposed this waiver of ETF transaction fees for those ETFs that are part of an EFP.
However, because the Exchange's billing system is unable to distinguish an ETF transaction that is part of an EFP from any other ETF transaction, a manual procedure has been developed. Specifically, within thirty (30) calendar days of the particular transaction date, a Fee Reimbursement Form must be completed and submitted to the Exchange. Upon acceptance, the Exchange will deliver to that member's clearing firm a reimbursement check in the amount of the transaction fee charged on ETF transactions executed pursuant to an EFP trade as described above.
The Exchange believes that the proposal is consistent with Section 6(b) of the Act
The Exchange does not believe that the proposed rule change will impose any burden on competition.
No written comments were solicited or received with respect to the proposed rule change.
The proposed rule change has become effective pursuant to Section 19(b)(3)(A)(ii) of the Act
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposal is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, NW., Washington, DC 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room. Copies of such filing will also be available for inspection and copying at the principal office of the Amex. All submissions should refer to file number SR-Amex-2002-66 and should be submitted by September 19, 2002.
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to amend its rules to eliminate the “Book Indicator.”
In its filing with the Commission, CBOE included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The CBOE has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange is proposing to eliminate the “Book Indicator.” This indicator is affixed to the CBOE disseminated quotation when an order in the Exchange's book represents the best bid or offer on the Exchange. It alerts brokers and the public that the bid, offer or both are being generated by orders in the book, not by market-maker quotes. The Book Indicator was adopted as part of the Exchange's initiative to provide split-price Retail Automatic Execution System (“RAES”) executions for incoming customer orders when the prevailing best bid (offer) is generated by an existing customer order in the CBOE book.
Now that CBOE disseminates quotes with size, it no longer needs the Book Indicator. Today, in the above example, CBOE's disseminated bid would contain a size of 3 contracts. Thus, the customer would know that an RAES sell order would receive only 3 contracts at the disseminated bid price. This obviates the need for the Book Indicator; therefore CBOE proposes to eliminate it.
The Exchange believes the proposed rule change is consistent with Section 6(b) of the Act
This proposed rule change does not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
No written comments were solicited or received with respect to the proposed rule change.
Within 35 days of the date of publication of this notice in the
(A) By order approve such proposed rule change, or
(B) Institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, NW., Washington, DC 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room. Copies of such filing will also be available for inspection and copying at the principal office of CBOE. All submissions should refer to the File No. SR-CBOE-2002-44 and should be submitted by September 19, 2002.
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
On March 25, 2002, The Depository Trust Company (“DTC”) filed with the Securities and Exchange Commission (“Commission”) proposed rule change SR-DTC-2002-04 pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”).
Under DTC's current procedures for the processing of maturity presentments of money market instruments (“MMIs”) that are in DTC's custody, early on the maturity date (generally around 2 a.m.) DTC initiates deliveries of the maturing paper from the accounts of participants having position in the maturing paper to the MMI participant account of the issuing/paying agent (“IPA”). These maturity presentments are processed as the equivalent of book-entry deliveries versus payment. If the net debit cap or collateralization controls applicable to the IPA's account prevents the delivery from being completed, maturity presentments will “recycle” just as any delivery would. If recycled, the maturity presentment delivery would be completed once additional funds such as settlement obligation prepayments or new issuances are credited to the IPA's account. Attempts to complete deliveries of recycling maturity presentments occur randomly without regard to the identity of the offsetting prepayment/issuance transactions. For example, an issuance of Issuer A's commercial paper (“CP”) into the IPA's account might establish collateral in the IPA's account that could be used to support the processing of a maturity presentment of Issuer B's CP. This arrangement has operated successfully since MMIs first became DTC-eligible in 1990.
DTC's MMI procedures provide that the IPA can “refuse to pay” for maturing paper of a particular issuer by communicating that intention to DTC before 3 p.m. (ET) on the maturity date. This intention will be communicated to all participants by DTC. DTC will then reverse any completed maturity presentments by recrediting them to presenting participants' accounts, which offsets the associated settlement credits in those accounts. DTC will also unwind the following transactions it may have processed earlier that day in the same and other MMIs of that “defaulting issuer': uncompleted maturity presentments; any valued issuances; any periodic income (interest or dividend) and principal presentments; and any reorganization presentments. In addition, DTC will mark down the collateral value of all of the defaulting issuer's MMIs in the system to zero and will block further issuances of that issuer's paper through DTC.
Currently, the Receiver-Authorized Delivery (RAD) function enables each participant to limit and consider certain securities deliveries (those obligating the participant to pay $15 million or more) and certain payment orders (those obligating the participant to pay $1 million or more) which are directed to its account by any other participant before its account is updated. Certain other transactions, including substantially overvalued deliveries and deliveries initiated just prior to cutoff, are automatically subject to the RAD function.
However, under DTC's current procedures, RAD is not available for maturity presentments initiated by DTC on behalf of presenting participants because maturity presentments are known in advance and can generally be presumed to be valid obligations due and payable. Moreover, the processing of maturity presentments occurs early in the processing day in the expectation that the associated money credits posted to the accounts of presenting participants will be available to support the efficient subsequent processing of new MMI issuances. Finally, subjecting all MMI maturities to RAD would impose an operational burden on IPAs who would be required to authorize each maturity presentment in order for the transaction to be completed.
Since the events of September 11, IPAs have raised a concern that in such emergency situations the random nature of DTC's process for updating recycling maturity presentments prevents the IPAs from aligning the funding of maturities with offsetting issuances of the same issue or with decisions to activate back-up lines of credit in order to fund a particular issuer's maturing obligations.
The proposed rule change provides to IPAs in the event of a systemic, operational, or other crisis that could result in MMI maturities not being funded in the normal course a mechanism for dealing with the nonpayment of maturities that does not have the consequences of a “refusal to pay.” Under the proposed rule change, in extraordinary circumstances
Section 17A(b)(3)(F) of the Act requires that the rules of a clearing agency be designed to promote the prompt and accurate clearance and settlement of securities transactions.
On the basis of the foregoing, the Commission finds that the proposed rule change is consistent with the requirements of the Act and in particular with the requirements of Section 17A of the Act and the rules and regulations thereunder applicable.
For the Commission by the Division of Market Regulation, pursuant to delegated authority.
Pursuant to section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The NYSE is proposing to amend Section 102.04 of the Exchange's Listed Company Manual (the “Manual”) to correct an erroneous statutory reference.
Below is the text of the proposed rule change. Proposed new language is
Notwithstanding the foregoing requirement for market value of publicly held shares of $60,000,000, the Exchange will generally authorize the listing of all the Funds in a group of Funds listed concurrently with a common investment adviser or investment advisers who are “affiliated persons”, as defined in Section 2(
• Total group market value of publicly held shares equals in the aggregate at least $200,000,000;
• The group market value of publicly held shares averages at least $45,000,000 per Fund; and
• No one Fund in the group has market value of publicly held shares of less than $30,000,000.
In its filing with the Commission, the NYSE included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The NYSE has prepared summaries, set forth in Sections A, B and C below, of the most significant aspects of such statements.
The Exchange recently amended Section 102.04 of the Manual to permit the concurrent listing of closed-end funds with a common investment adviser or advisers who are “affiliated persons.”
The Exchange believes the proposed rule change is consistent with section 6 of the Act,
The NYSE does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purpose of the Act.
The Exchange has neither solicited nor received written comments on the proposed rule change.
Because the foregoing proposed rule change: (1) Does not significantly affect the protection of investors or the public
A proposed rule change filed under Rule 19b-4(f)(6) under the Act
The Commission, consistent with the protection of investors and the public interest, has determined to make the proposed rule change immediately operative
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change, as amended, is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, NW., Washington, DC 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room. Copies of such filing will also be available for inspection and copying at the principal office of the NYSE.
All submissions should refer to File No. SR-NYSE-2002-25 and should be submitted by September 19, 2002.
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act )
PCX is proposing to amend PCX Rule 3.7 to allow the Exchange to add new series of options when such series are available for trading on one or more other options exchanges and the underlying security met the market price per share requirements at the time that a competing exchange added such series. The text of the proposed rule change is below; new language is italicized.
Rule 3.7(a) The approval of an underlying security for exchange transactions shall be withdrawn by the Exchange if the underlying security fails to meet the then current requirements necessary to maintain such approval or for any reason the Exchange deems necessary. In the event the Exchange withdraws approval, no additional series of option contracts of the class covering that underlying security shall be opened; provided, however, that where exceptional circumstances have caused the noncompliance of an underlying security with Subsection (B) or (C) of Section 1 of Commentary .01 or Section 2 or 3 of Commentary .01 hereunder, the Exchange may, in the interest of maintaining a fair and orderly market or for the protection of investors, open additional series of option contracts of the class covering the subject underlying security.
(b) No change.
Commentary:
.01—No change.
.02—In connection with Rule 3.7(a) and Commentary .01.3 thereto, the Exchange shall direct that no additional series of options contracts of the class covering an underlying security be opened at any time when the market price per share of the subject underlying security is less than $3.00. Subject to Paragraph 3 of Commentary .01 above, the market price per share of the underlying security will be determined as follows:
1. For intra-day series additions, the last reported trade in the primary market in which the security is traded at the time the Exchange determines to add these additional series intra-day;
2. For next-day series additions, the closing price reported in the primary market in which the security is traded on the last trading day preceding the day on which such series additions are authorized; and
3. for expiration series additions, the closing price reported in the primary market in which the security is traded on the last trading day preceding expiration Friday.
.03-.11—No change.
In its filing with the Commission, PCX included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item III below. PCX has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
PCX Rule 3.7 (Withdrawal of Approval of Underlying Securities) specifies continued listing requirements for securities underlying options traded on the Exchange and restricts the Exchange from adding new series of options in the event that the underlying security fails to meet certain criteria. The rule currently provides that the Exchange may not list additional series if,
Although the continued listing requirements are uniform among the five options exchanges, the application of those standards in the current market environment has resulted in situations where not all exchanges may compete in the same options series. For example, if one exchange adds a new options series when the underlying security trades above the $3.00 price threshold, it may continue to trade options on that series even if the price of the underlying security subsequently falls below $3.00. If no other options exchange had added that series when it was eligible for listing, then the first exchange to add the series would be the only one authorized to trade that series despite the fact that members of other exchanges have customer orders to trade that series. Due to the extreme volatility of prices in the marketplace, the PCX would not be able to list actively-traded options series where the price of the underlying security falls below the $3.00 threshold before the Exchange elects to add the series.
To address this situation, the Exchange proposes to adopt a new rule change that would allow it to list additional series that are being quoted by at least one other exchange. The Exchange has narrowly drafted this proposed rule change to address the circumstances where an option series is already available to the investing public, but cannot be added by the Exchange due to timing.
The Exchange believes that this proposal will promote competition in the marketplace by assuring that the Exchange may compete in all series that are quoted by other options exchanges. This will place the Exchange on a level playing field with its competitors.
The Exchange believes that this proposal is consistent with Section 6(b) of the Act,
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
The Exchange has not received any written comments from members or other interested parties.
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposal is consistent with the Act. Persons making written submissions should file six copies thereof with the Secretary, Securities and Exchange Commission, 450 Fifth Street, NW., Washington, DC 20549-0609. Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for inspection and copying in the Commission's Public Reference Room. Copies of such filing will also be available for inspection and copying at the principal office of the PCX. All submissions should refer to File No. SR-PCX-2002-51 and should be submitted by September 19, 2002.
The Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange, and in particular, the requirements of Section 6(b)(5) of the Act.
PCX has requested that the proposed rule change be given accelerated approval pursuant to Section 19(b)(2) of the Act.
It is therefore ordered, pursuant to Section 19(b)(2) of the Act,
For the Commission, by the Division of Market Regulation, pursuant to delegated authority.
National Highway Traffic Safety Administration (NHTSA), Office of Defects Investigation (ODI), DOT.
Notice of public meeting.
This notice announces a public meeting to discuss the manner in which Early Warning Reporting (EWR) information required to be submitted to ODI by motor vehicle and motor vehicle equipment manufacturers will be submitted to, and retained by, the agency. On July 3, 2002, NHTSA issued a final rule implementing the EWR provisions of the Transportation Recall Enhancement, Accountability, and Documentation (TREAD) Act. At this meeting, NHTSA will discuss the methods by which EWR information must be submitted, security for that information, acknowledgement of receipt of that information, and other technical aspects associated with those submissions. The agency will also respond to questions about those issues from the public.
The Agency's public meeting relating to EWR data submission will be held on Wednesday, September 24, 2002, beginning at 10 a.m. in Room 2230 of the United States Department of Transportation, 400 Seventh St., SW (NASSIF Building), Washington, DC 20590.
Julia Goldson at (202) 366-9944 or at
Transcripts of this meeting will be available for public inspection in the DOT Docket Room in Washington, DC, within four weeks after the meeting. The DOT Docket Room is open to the public from 10 a.m. to 5 p.m. The transcript may also be accessed electronically at
We recommend that all visitors arrive at least 45 minutes early to sign in and pass through security checkpoints. Visitors to the building should enter through the Southwest Lobby to sign in and be escorted upstairs.
NHTSA will provide auxiliary aids to participants, as necessary. Any person desiring such auxiliary aids (
CSX Transportation, Inc. (CSXT) has agreed to grant limited bridge trackage rights to Central Michigan Railway Company (CMGN) over approximately 4.0 miles in Saginaw, MI.
The purpose of the trackage rights is to enable CMGN to interchange certain traffic with HESR at approximately Buena Vista Station, about 1 mile east of CSXT's Saginaw yard, thereby promoting operating efficiencies.
As a condition to this exemption, any employees affected by the trackage rights will be protected by the conditions imposed in
This notice is filed under 49 CFR 1180.2(d)(7). If it contains false or misleading information, the exemption is void
An original and 10 copies of all pleadings referring to STB Finance Docket No. 34241, must be filed with the Surface Transportation Board, 1925 K Street, NW., Washington, DC, 20423-0001. In addition, a copy of each pleading must be served on Rose-Michele Weinryb, 1300 19th Street, NW., 5th Floor, Washington, DC, 20036.
Board decisions and notices are available on our Web site at
By the Board, David M. Konschnik, Director, Office of Proceedings.
Federal Energy Regulatory Commission, DOE.
Notice of proposed rulemaking.
The Federal Energy Regulatory Commission (Commission) proposes to amend its regulations under the Federal Power Act (FPA) to modify the
Initial comments are due on October 15, 2002. Comments should include an executive summary that does not exceed 10 pages.
Send comments to: Office of the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426.
In addition to publishing the full text of this document in the
1. This notice of proposed rulemaking represents the third in a series of initiatives undertaken by the Commission to harness the benefits of competitive markets for the nation's electric energy customers, in order to meet our statutory responsibility to assure adequate and reliable supplies of electric energy at a just and reasonable price. In 1996, the Commission issued Order No. 888, which required, as a remedy for undue discrimination, that all public utilities provide open access transmission.
2. Order No. 888 and Order No. 2000 set the foundation upon which to build regional transmission institutions and competitive electricity markets. However, as events have transpired, there remain significant impediments to competitive markets and to the infrastructure needed to meet our electric energy demand. Unduly discriminatory transmission practices have continued to occur and inconsistent design and administration of short-term energy markets has resulted in pricing inefficiencies that can cause rates to be unjust and unreasonable. At the same time, the nature of the electric industry has changed in a way that makes the development of competitive wholesale markets all the more critical. The electric industry has evolved from one characterized by large, vertically integrated utilities to an industry with increasing wholesale trade and increasing numbers of independent buyers and sellers of wholesale power seeking non-discriminatory access to transmission facilities. Public utilities
3. The Commission's objectives in this third rulemaking initiative, therefore, are to remedy remaining undue discrimination and establish a standardized transmission service and wholesale electric market design that will provide a level playing field for all entities that seek to participate in wholesale electric markets. The Commission proposes to provide new choices through a flexible transmission service, and an open and transparent spot market
4. When supply and demand do not support fully competitive markets, market design should provide protection against market power. We seek in this rulemaking to put in place sufficient regulatory backstops to protect customers against the exercise of market power when structures do not support a competitive market. Market monitoring at all times, and market power mitigation when needed, are critical pieces of this initiative.
5. A significant impediment to achieving the full benefits of competition is that there is no single set of rules governing transmission of electric energy. Not only does the Order No. 888
6. To remedy undue discrimination, enhance competition, remove economic inefficiencies and ensure just and reasonable rates, terms and conditions transmission of electric energy, the Commission proposes to: Exercise jurisdiction over the transmission component of bundled retail transactions; modify the existing
7. The proposed Network Access Service would combine features of both existing open access transmission services—the flexibility and resource and load integration of Network Integration Transmission Service; and the reassignment rights of Point-to-Point Transmission Service. It would give a customer the right to transmit power between any points on the transmission system—so long as the transaction is feasible under a security-constrained dispatch.
8. We expect that most if not all entities will become members of RTOs and that the new Network Access Service would be provided through these RTOs. However, this rule may become effective at a time when some transmission owners and operators have not yet become members of functioning RTOs. Thus, we propose that all transmission owners and operators that have not yet joined an RTO must contract with an independent entity to operate their transmission facilities. This proposed rule refers to both the RTO and those independent entities as “Independent Transmission Providers.” An Independent Transmission Provider would have no financial interest, either directly or through an affiliate, as defined in section 2(a)(11) of the Public Utility Holding Company Act (15 U.S.C. 79b(a)(11), in any market participant
9. In addition to creating the new Network Access Service, the revised tariff would include requirements to standardize wholesale electric market design. The fundamental goal of the Standard Market Design requirements, in conjunction with the standardized transmission service, is to create “seamless” wholesale power markets that allow sellers to transact easily across transmission grid boundaries and that allow customers to receive the benefits of lower-cost and more reliable electric supply. For example, currently a supplier that seeks to serve load in a distant state may need to cross several utility systems or independent system operator systems (ISOs), all of which have different rules for such things as reserving and scheduling transmission and scheduling generation. This can either result in an efficient transaction not occurring at all or it can add significant time and costs to the transaction. Standard Market Design seeks to eliminate such impediments.
10. Central to the Standard Market Design concept is its reliance on bilateral contracts entered into between buyers and sellers. The resource adequacy requirement strongly encourages such long-term contracts. The short-term spot markets set out below are intended to complement bilateral procurement. To handle generation imbalances and the procurement of ancillary services, the Commission proposes to require that all Independent Transmission Providers operate markets for energy and for the procurement of certain ancillary services in conjunction with markets for transmission service. These markets would be bid-based, security-constrained spot markets operated in two time frames: (1) A day ahead of real-time operations, and (2) in real time. The adoption of a market-based
11. Several changes required by Standard Market Design promote greater customer access to low-cost power. We note that this may raise concerns that cheap power may leave one region for sale in another, higher-priced region. This can only happen with generation that is not already under contract for purchase. Thus, customers in low-cost regions can ensure that low-cost power “stays home” by contracting for that power. This way, only excess power will leave the region to serve another market.
12. The Commission proposes a pricing policy and process for recovering the costs of new transmission investment so as to develop the infrastructure needed to support competitive markets. The policy builds on the price signals provided by the proposed spot market design. However, there are cases where LMP price signals alone will not encourage all beneficial transmission investments. Therefore, we propose to require market participants to participate in a regional process to identify the most efficient and effective means to maintain reliability and eliminate critical transmission constraints.
13. Even with good market design rules, current supply and demand conditions make a market monitoring and market power mitigation plan necessary. The market power mitigation proposed in this rule would rely on a combination of methods to protect against the exercise of market power by preventing sellers from withholding economical supplies from the market, while permitting prices to reflect true scarcity. The proposed market power mitigation method should be more restrictive at times or places where the exercise of market power is more likely to occur than at times or places where the market is sufficiently competitive.
14. However, because market power mitigation may tend to suppress scarcity prices that signal the need for investment, a companion mechanism besides spot prices is needed. The Commission proposes a resource adequacy requirement to ensure adequate electric generating, transmission and demand response infrastructure, the level of which is to be determined on a regional basis. Recognizing that supply planning and retail customer demand response are the states' responsibility, the Commission proposes a resource adequacy requirement intended to complement existing state programs. In particular, the Commission proposes that an RTO or other regional entity must forecast the region's future resource needs, facilitate regional determination of an adequate future level of resources and assess the adequacy of the plans of load-serving entities
15. In summary, in this proceeding, the Commission, pursuant to its authority under sections 205 and 206 of the Federal Power Act,
(1) Establish a single non-discriminatory open access transmission tariff with a single transmission service (Network Access Service) that is applicable to all users of the interstate transmission grid: wholesale and unbundled retail transmission customers, and bundled retail customers;
(2) Require all public utilities that own, control or operate interstate transmission facilities to become an Independent Transmission Provider, turn over their transmission facilities to an Independent Transmission Provider or contract with an Independent Transmission Provider to operate their facilities. An Independent Transmission Provider is any public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce, that administers the day-ahead and real-time energy and ancillary services markets in connection with its provision of transmission services pursuant to the SMD Tariff, and that is independent (
(3) Require that an Independent Transmission Provider provide transmission services and administer the day-ahead and real-time energy and ancillary services markets;
(4) Establish an access charge to recover embedded transmission costs based on a customer's load ratio share of the Independent Transmission Provider's costs, and would be paid by any customer taking power off the grid;
(5) Use LMP as the system for transmission congestion management and provide tradable financial rights—Congestion Revenue Rights
(6) Establish a preference for the auction of Congestion Revenue Rights, but initially allow regional flexibility for a four-year transition period in determining whether to allocate Congestion Revenue Rights to existing customers or auction such rights such that revenues are allocated to existing customers to hold them financially harmless;
(7) Establish open imbalance energy markets to allow all market participants to buy or sell their imbalances in a fair, efficient and non-discriminatory market. Imbalance markets would be neutral towards fuel sources and treat demand resources on an equal footing with supply;
(8) Permit customers under existing contracts to receive the same level and quality of service under Standard Market Design that they receive under their current contracts, to the greatest extent feasible;
(9) Establish procedures to mitigate market power in the day-ahead and real-time markets required by Standard Market Design and mechanisms for market monitoring;
(10) Establish procedures to assure, on a long-term regional basis, that there are adequate transmission, generation and demand-side resources;
(11) Provide a formal role for state representatives to participate in the
(12) Clarify the obligation of all users of the transmission system to comply with all appropriate standards for ensuring system security and reliability.
16. The Commission's focus is on promoting the development of competitive wholesale markets and we do not intend to interfere with the legitimate concerns of state regulatory authorities. It remains within a state's authority to determine whether or not to provide retail access. Nevertheless, the reforms proposed in this rulemaking will benefit customers in states with or without retail access. In addition, we seek to formally involve state representatives in the decision-making processes of regional entities. We also recognize the need to permit parties to continue to rely on existing contracts and scheduling practices, including those involving hydroelectric power, and these are fully accommodated under Standard Market Design.
17. The Commission recognizes that differences exist throughout the regions of the country; however, the Commission's goal is to remedy undue discrimination by standardizing transmission service and wholesale electric market design as much as possible. We propose to allow certain regional variations, as described
18. Finally, the Commission recognizes that implementation of a revised open access transmission tariff and Standard Market Design on a nationwide basis may take some time. Thus, the Commission proposes a phased compliance process. By July 31, 2003, all public utilities that own, operate or control interstate transmission facilities must file revised open access transmission tariffs (Interim Tariffs) to become effective September 30, 2004, that reflect the inclusion of bundled retail customers as eligible customers. By December 1, 2003, all public utilities that own, control or operate interstate transmission facilities must file revised open access transmission tariffs (SMD Tariffs), to become effective no later than September 30, 2004, or such other time as directed by the Commission, that reflect all of the remaining revisions and requirements of the Final Rule in this proceeding. The Commission and its staff will work with regional organizations and stakeholders in facilitating full and efficient compliance with this rule.
19. Below in Section II we set out the relevant developments in the electric industry. In Section III and Appendix C we explain the need for further reform. In Appendix E, we discuss various allegations of market manipulation strategies encountered in the organized markets and how Standard Market Design will address these strategies. In Section IV we explain our specific remedy for pervasive problems in the industry consistent with our statutory responsibilities. In Section V, we set out the implementation process and dates. Finally, the glossary for the terms used in this document is found in the Definitions section of the SMD Tariff in Appendix B, and the revisions to the Interim Tariff are set out in Appendix A.
20. In April 1996, in Order No. 888, the Commission found that unduly discriminatory and anticompetitive practices existed in the electric industry, and that public utilities that own, control or operate interstate transmission facilities had discriminated against others seeking transmission access. It determined that non-discriminatory open access transmission services, including access to transmission information, and stranded cost recovery were the most critical components of a successful transition to competitive wholesale electricity markets.
21. Order No. 888 required all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to: (1) File open access non-discriminatory transmission tariffs containing certain minimum, non-price terms and conditions, and (2) functionally unbundle wholesale power services from transmission services.
22. The Commission declined to require corporate unbundling at the time of Order No. 888, and stated instead that efforts to remedy undue discrimination should begin by requiring the less intrusive functional unbundling approach.
[W]e see many benefits in ISOs, and encourage utilities to consider ISOs as a tool to meet the demands of the competitive marketplace. As a further precaution against discriminatory behavior, we will continue to monitor electricity markets to ensure that functional unbundling adequately protects transmission customers. At the same time, we will analyze all alternative proposals, including formation of ISOs, and, if it becomes apparent that functional unbundling is inadequate or unworkable in assuring non-discriminatory open access transmission, we will reevaluate our position and decide whether other mechanisms, such as ISOs, should be required.
23. A number of significant developments took place in the electric utility industry following issuance of Order No. 888. All public utilities filed non-discriminatory, open access transmission tariffs stating rates, terms and conditions for comparable
24. Order No. 2000, issued in December 1999, was the Commission's second major step toward establishing competitive wholesale power markets and eliminating residual undue discrimination in interstate transmission services. It identified two broad categories of impediments to competitive electricity markets: (1) The engineering and economic inefficiencies inherent in the current operation and expansion of the transmission grid, and (2) continuing opportunities for transmission owners to unduly discriminate in the operation of their transmission systems so as to favor their own (or their affiliates') power marketing activities.
25. Order No. 2000 encouraged all transmission owners to voluntarily place their transmission facilities in the hands of appropriate RTOs. The Commission stated that RTOs could include ISOs or independent for-profit transmission companies (ITCs). However, all RTOs must meet four minimum characteristics and eight minimum functions that were identified in Order No. 2000, and also must have an open architecture framework that would permit an RTO and its members flexibility to improve their structures over time.
26. Following Order No. 2000, some transmission-owning public utilities began to file proposals to participate in RTOs. The process has been slow for several reasons, one of which is stakeholder uncertainty about what the Commission would require for RTO approval—not only for the RTO scope and independence characteristics, but also regarding such RTO functions as congestion management and market-oriented provision of ancillary services.
27. Order No. 2000 called for RTOs to be in operation across the nation by December 2001. To date, there is only one RTO fully approved by the Commission, the Midwest ISO, which began operating in early 2002.
28. Although progress with Commission-approved RTOs has been slow, regionalization has also occurred through the ISO formation process that was encouraged in Order No. 888. The Northeast and California ISOs are engaged in a process to become Commission-approved RTOs or to join larger RTOs. In eastern North America, close coordination is developing between U.S. and Canadian transmission systems and market designs.
29. In addition to the Midwest ISO, the Commission has provisionally approved other RTOs,
30. The following section and related Appendix C discuss specific features of today's wholesale electricity markets that inhibit the development of competition and efficient regional markets, and identify areas in which the Commission must direct reforms to eliminate remaining undue discrimination and inefficiencies, and ensure just and reasonable rates.
31. Since the issuance of Order Nos. 888 and 2000, it has become clear that additional, mandatory measures are needed to achieve the goals of non-discriminatory transmission access and competition in electricity markets. Vertically integrated transmission owners and operators continue to use their interstate transmission facilities in ways that inhibit competition in wholesale power markets as well as competition in those retail power markets where states have adopted retail choice. The discriminatory preferences that these transmission owners and operators give to their own uses of the interstate transmission grid to serve their retail customers (whether or not they are in retail choice states) results in discrimination against, and in costs being borne by, other wholesale and retail customers who also rely on the interstate transmission facilities to buy power. The discriminatory preferences also create barriers to new sellers that could provide lower-cost power. This could result in higher prices to the native load served by the transmission owner. For example, transmission-dependent utilities
32. The Commission recently has taken additional steps to address some of the remaining impediments to non-discriminatory transmission access and competition in wholesale power markets. For example, the Commission's recently issued Generator Interconnection proposed rule seeks to remove one particular type of undue discrimination occurring in the marketplace—barriers to obtaining interconnections to the interstate transmission grid—so that new generators can compete with vertically integrated transmission providers to serve load.
33. Furthermore, it has become apparent that there are also opportunities to discriminate and to hinder an efficient, competitive marketplace due to the absence of standardization with respect to market rules and practices within and between regional markets. So-called “seams” problems (
34. Finally, innovation that the Commission expected to see with respect to new service offerings has been sporadic and unsteady. Innovations in transmission control and pricing (
35. Most ISOs recently introduced centralized short-term real-time hourly markets and day-ahead markets for energy (
36. The specific reasons for requiring reform are many. Market participants
37. Nevertheless, new problems have been created by some of the market design experiments. In regions of the country where the separation of transmission from generation has been addressed through the creation of ISOs (which, in some instances, have placed nearly all load under a single tariff), market design flaws create inefficiencies in the marketplace and opportunities for the exercise of market power. Conflicting market rules and procedures in neighboring ISOs have created or perpetuated seams problems that impede the economic flow of power from one region to another. All of these problems have hindered the progress towards competitive regional electricity markets. Standard Market Design is intended to address these problems.
38. By differing means, Order Nos. 888 and 2000 attempt to effect open access transmission by reducing the ability of transmission owners that also own generators to act in anticompetitive or unduly discriminatory ways against other generators. In both orders, the Commission attempted to move the electric industry into a competitive wholesale market without mandating corporate restructuring. Through Order Nos. 888 and 2000, the Commission required open access to public utility transmission systems, encouraged the formation of ISOs and, later, RTOs to achieve control of the transmission grid by entities that are independent from generation marketing or sales. However, only limited portions of the country have moved beyond the basic requirements of open access (
39. A large portion of this problem is directly attributable to the continued ability of vertically integrated transmission providers to exercise some degree of transmission market power to advantage their own or affiliated generation. The longer the vertically integrated transmission provider can use access to interconnection or transmission service to delay or prevent entry of competing generators to its service territory, the longer it can profit from its own generation sales with a limited threat of competition. Vertically integrated transmission providers have found numerous ways to delay or prevent entry of competitors, some within the existing rules and some by exceeding reasonable discretion afforded to the transmission provider. All of these are difficult to monitor or prevent with behavioral rules.
40. As part of Standard Market Design, we propose that an Independent Transmission Provider operate all transmission facilities. The requirement for independent control of the transmission grid, preferably by an RTO, resolves these types of problems.
41. Under the current
42. In Standard Market Design, we propose to eliminate the preference for future native load growth. Instead, since Congestion Revenue Rights will be used to assure price certainty, Congestion Revenue Rights will be apportioned based on historical use or by an auction, neither of which grants preference for future load growth by a particular supplier; this approach resolves these concerns.
43. Another type of anticompetitive behavior centers on a vertically integrated transmission provider delaying the processing of a competitor's request for new transmission service or interconnection (including the related system impact or facilities studies). Transmission providers have done so by failing to follow time lines or expansively interpreting the tariff procedures. These delays may be enough to cause the competing generator to lose the sale, particularly if the potential customer is concerned that it may lose service completely if it does not stay with the transmission provider.
44. Under Standard Market Design, these types of delays are resolved through the requirement for an independent entity, preferably an RTO, to perform studies and calculate available transfer capability (ATC),
45. A vertically integrated transmission provider has a structural advantage over many competitors to make economy sales or to serve its own load, primarily because it has a large portfolio of both generators and loads. A competitor with access only to generation outside of the control area and no native load has to identify the delivery point of its power before being able to secure transmission service. But a vertically integrated transmission provider does not have to identify a specific location on the grid to serve its load because its load is dispersed across its entire system. A vertically integrated transmission provider also does not have to identify a single generation location, but can run a combination of its own generators or purchase from lower cost-suppliers inside or outside of its system. It can schedule purchased power to one of its own loads (in place of power from one of its own generators) in order to secure transmission service for the purchase. Later, it can find a buyer for the power and schedule transmission service from one of its internal generators to the load. This often is enough of a scheduling advantage over a competing supplier to ensure that the transmission provider (or its affiliated power marketer) gets the sale.
46. While it is true that all network customers have these same rights and abilities, in many areas of the country the only customer using network service is the vertically integrated transmission provider. Moreover, the vertically integrated transmission provider's size of resources and loads is usually much greater than any other network customer, giving it that much more of an advantage in flexibility. In addition, the vertically integrated transmission provider may have an advantage through access to better or more transmission and other related information.
47. Under Standard Market Design, all transmission service will be provided under a new Network Access Service. Having one service for all customers will eliminate scheduling advantages of competing suppliers.
48. Customers have also alleged that vertically integrated transmission providers have an advantage over competitors in the resolution of energy imbalances. Transmission providers with generation and load of their own can resolve their own energy imbalances through in-kind energy exchanges with neighboring systems. In contrast, other customers of the transmission provider face higher costs if they take service from other suppliers that could balance against each other. This difference gives the transmission provider a competitive advantage over other sellers of power.
49. Under Standard Market Design, all suppliers and loads on a system will resolve imbalances through the same energy imbalance procedures. This will remove any competitive advantage the transmission owner with its own generation and load may have over competing power suppliers.
50. Another source of discrimination is the calculation of Available Transfer Capability. A transmission provider that is not independent calculates its Available Transfer Capability, using its own proprietary data and its own equations. This discretion gives it the ability and the opportunity to discriminate in its own favor against entities that rely upon the OASIS for Available Transfer Capability information. In several cases, the Commission has found that utilities' OASIS postings reflect an inaccurate Available Transfer Capability. Indeed, in response to “serious concerns about the integrity of the postings of ATC” on the OASIS systems of two transmission providers, the Commission required the transmission providers to employ an independent third party to administer their OASIS systems.
51. Under Standard Market Design, an independent entity will calculate Available Transfer Capability and schedule transmission service. This will eliminate this potential for undue discrimination.
52. Manipulation or violation of OASIS posting requirements and the Commission's standards of conduct is another way vertically integrated transmission providers that control their own OASIS sites are able to engage in undue discrimination. This can occur through prohibited off-OASIS communications between the transmission provider and its affiliated market participant,
53. Similarly, control over the design, function and maintenance of OASIS systems may also present opportunities for discrimination. The Commission has been concerned for some time that transmission providers have the ability to impede competition by making their OASIS sites difficult to use, limiting users' access to OASIS and limiting access to information about transmission curtailments and interruptions that would allow the Commission to identify instances of undue discrimination.
54. Under Standard Market Design, an independent entity will operate an OASIS on a regional basis, and thus will remove any advantages one seller may have over another and improve the accuracy of regional Available Transfer Capability postings on the OASIS.
55. The Commission has found instances of transmission providers taking advantage of their ability to reserve interface capability to serve their
56. Under Standard Market Design, entities that want to reserve transfer capability must pay for that capability to reach generation reserves across an interface. Thus, the preferential treatment would be eliminated.
57. The opportunity for anticompetitive behavior arises when transmission providers have discretion to dispatch their own generation to serve their own load in a way that requires transmission service curtailments through the use of transmission loading relief (TLR) procedures.
58. There has been a sharp increase in the number of TLRs used in some regions, suggesting that transmission operators rely upon them to do more than simply relieve emergency transmission overloads.
The increased incidence of TLRs may suggest that some transmission capacity is being oversold. Market participants have attributed a tendency to implement a greater number of TLRs to the commercial reality that transmission providers do not have to refund transmission reservation fees for service curtailed because a TLR is called.
59. When a vertically integrated transmission provider injects power from its own generation onto its own power lines to meet the constantly shifting demands of the load on its system, it has both the opportunity and the incentive to manipulate the transmission system for its own benefit. It can either dispatch generators to create a transmission constraint that prevents a competitor from making a sale that the transmission provider would also like to make, or it can capitalize on legitimate constraints into a load pocket to curtail a competitor's transmission transaction and serve the customer with its own generation instead. The key here is that none of the transmission provider's actions require direct communication with its merchant function or marketing affiliate. A simplified hypothetical example of such anti-competitive behavior is set forth in Appendix C.
60. Several aspects of our proposed remedy address this concern, including the use of LMP to manage congestion and the requirement that transmission facilities be operated by an Independent Transmission Provider.
61. Some of the difficulties that come from having different rules as power moves across the grid are discussed later in the Seams Problems Section III.B.4), where a “seam” is a dividing line between different sets of grid rules.
62. Having two or more different sets of rules governing the operation of a transmission system makes it difficult—if not at times impossible—for that system to support an efficient regional electric power market. If the interstate transmission system is to provide fair and efficient movement of power on behalf of all users of the system, the same general rules must govern such matters as who gets service, who has the right to transmission service when not all service requests can be accepted, how the transmission facility costs are allocated among transmission customers, who gets its transmission curtailed and by how much when a transmission outage prevents all the planned services from being accommodated, who plans the additions to the grid and who pays for these additions.
63. Today there are not only different rules in different public utility systems, but there may be more than one set of rules for transmission owned by a single utility. This is because there are different rules for two types of wholesale transmission service, and the rules for bundled retail transmission service may differ from the rules for wholesale and unbundled retail transmission services.
64. The Commission established an open access transmission tariff under Order No. 888 that provides for two distinct types of wholesale transmission services—Network Integration Transmission Service and Point-to-Point Transmission Service. Network Integration Transmission Service was designed primarily to meet the needs of the transmission customer that wants to integrate many generators and many loads at diverse locations on the public utility's grid; it was intended to be comparable to the service that the public utility provided to its own bundled retail customers. Point-to-Point Transmission Service, as the name implies, was designed primarily for the customer that wants to move power from one discrete location to another.
65. At the time Order No. 888 issued, the Commission recognized the potential for problems with having two wholesale services that could not be truly equal, especially the problem of dealing with claims of undue discrimination between the services.
66. Some parties expressed concern about moving quickly to a single service based on the Capacity Reservation Tariff model, while other parties asserted that, although a single tariff reducing the two services to one was a good policy, there were problems with the particular Capacity Reservation Tariff that was proposed. They recommended that the Commission delay acting on the proposed rule until it learned the best form of single service tariff through industry experience with open access. This is the approach that the Commission in effect followed. Since the two Order No. 888 services were adopted, however, there have been allegations of undue discrimination between customers of the two services as discussed later in this section.
67. There are also different rules for bundled retail transmission service and for wholesale and unbundled retail transmission services. States have historically established the rules for the transmission component of bundled retail transactions, while the Commission has established the rules for wholesale and unbundled retail transmission services.
68. Despite the requirement in Order No. 888 that no transmission customer may have any undue advantage over another, there remain real or perceived advantages for the customers of vertically integrated transmission owners. In many cases, the perceived advantage is one of Network Integration Transmission Service over Point-to-Point Transmission Service, where Network Integration Transmission Service is available to both bundled retail transmission customers and wholesale Network Integration Transmission Service customers, while Point-to-Point Transmission Service is taken primarily for wholesale transmission by independent power producers and marketers.
69. Four prominent examples highlight the alleged advantages that a public utility's bundled retail customers have over wholesale and unbundled retail customers. First, certain reliability practices related to keeping the transmission system balanced may allow a public utility that is responsible for keeping generation and load in balance to obtain lower costs for its own power customers. Second, a transmission-owning public utility may have more
70. The requirement for all services on the transmission grid to be taken under a common set of rates, terms and conditions will resolve these concerns.
71. Due to new transmission usage patterns and the lack of transmission infrastructure improvements, congestion has increased. However, economically sound congestion management plans do not exist in most parts of the country, and transmission customers have been exposed to transmission service interruptions and increasing generation costs due to the risk of interruption. The operating rules that do exist were not designed as a congestion management tool for allocating scarce transmission capacity, but were designed to keep facilities from overloading in an emergency, such as when a transmission facility unexpectedly goes out of service.
72. Currently, under the existing
73. The existing
74. Although the existing
75. Because it is difficult for a single-utility transmission provider to develop a formula that specifies the costs of redispatch and protects transmission customers' interests, generation redispatch has not been used as extensively as it could be used to relieve congestion. A transmission provider will not redispatch generating units if it cannot collect its higher generation costs, and less transmission transfer capability will be available to the energy market.
76. In 1998, the Commission called on public utilities to work with the North American Electric Reliability Council (NERC) to develop a congestion management system based on redispatch.
77. In 1998, Commonwealth Edison Company (ComEd) proposed a similar voluntary redispatch program, which predated NERC's Market Redispatch Program.
78. The overall result of the Order No. 888 congestion management system is that the transmission system is not utilized in the most efficient manner. Customers can be denied access to lower-cost supplies that could be made available if the congestion management and pricing system had an efficient and fair method of recovering the cost of generator redispatch.
79. Managing congestion using an LMP system, coupled with a single transmission service that relies on price (rather than first-come, first-served) to allocate limited transmission capacity, will resolve these problems.
80. A lack of common transmission rules inhibits competition in power markets not only when there are different rules for different customers under one public utility's tariff or one RTO's tariff, but also when there are different rules from one public utility to the next, or from one RTO to the next. The term “seam” has come into common use in the electric power industry over the last several years to refer to a boundary between areas with different transmission or other market rules. Market participants assert that it can be difficult to move power “across a seam” from one area to another.
81. Seams issues include differences in transmission rules as well as differences in power market rules. They include such diverse matters as different operating rules (
82. Market participants have called for a “seamless market,” by which they mean a market whose operation is not encumbered by differences in rules at public utility or RTO boundaries. To achieve a seamless market, some assert that rules may differ but only in ways that the differences are invisible to power sellers and buyers. Others assert that such management of differences rarely works in practice and that the rules must be the same everywhere to achieve a seamless market.
83. The Commission has long recognized the need for more coordination and uniformity throughout a region in transmission matters. Our Regional Transmission Group Policy Statement of 1993
Canadian electricity companies are linked to their counterparts in the U.S. through a number of major connections crossing our common border. We share a truly international electricity grid. This interconnectedness itself enhances our respective energy security, but it also places an onus on our countries to act together to manage the grid. Nowhere is that more important than in the area of electricity reliability. * * * Because uniformity in reliability standards is required to enable effective electricity trade, variations in standards would impede electricity trade and balkanize markets.
84. We set forth in Appendix C a number of examples of differences in rules that can create seams problems, and a discussion of efforts at the Commission or within the industry to address seams problems.
85. The requirement under Standard Market Design for a single tariff and a single market design operating with the same set of rules throughout the entire interconnection resolves the seams problems discussed above.
86. Poorly designed market rules, or market rules with unforeseen or unintended consequences, can have a debilitating effect on markets, market pricing and overall confidence in the markets of the market participants. Moreover, differences in market designs in neighboring regions can also lead to problems such as the exercise of market power through the exploitation of the differences.
87. Wholesale electricity markets are complex, with multiple products traded at multiple locations on different time-frames, while subject to the unique physical characteristics of electricity (
88. In the regions where voluntary, organized ISO markets for energy, transmission and ancillary services have been established under the existing tariff, problems due to the design choices have been characterized as “market design flaws.” A market design flaw is a market rule—including product specification, bid format, auction rules and pricing rules—that allows distortions in the market prices or availability of a product or service, whether energy, ancillary services, transmission service or installed capacity. In the years since the ISO markets have been operating, dozens of market design flaws have been identified, ranging from minor problems that cause temporary inconveniences to major problems that require markets to be re-designed. No region has been exempt from market design flaws of one type or another. We set forth in Appendix C examples of specific design flaws.
89. These problems have resulted in markets that are inefficient and do not produce the lowest reasonable prices for electric power. These problems cannot be resolved on a case-by-case basis because that will maintain and exacerbate the problems due to local differences in rules. Only standardization of electricity market design will solve these problems. In the parts of the country in which markets are most mature, including the Northeast, Midwest and California, there is broad consensus on the principal elements of market design and business practices. A standard market design rule will help advance this process and extend it to other regions. Our goal is to use the Standard Market Design rulemaking to address and remedy many of the market design flaws identified to date and to raise the quality of all electric markets simultaneously.
90. Market rules will need to be flexible and have the ability to evolve over time. However, consistent rules across the entire interconnection based on best practices, coupled with sound market monitoring to promptly identify and correct any design flaws will provide the necessary foundation for future market innovation and improvement.
91. The need to address the instances of discrimination described above is all the more critical given the changing nature of the electric industry. The United States electric power industry is in the middle of a transition from a predominantly monopoly industry to a predominantly competitive industry. The fundamental economic driver of change has been, and continues to be, the reduction of economies of scale in new generation construction, combined with environmental restrictions that encourage gas-fired units. This is due in large part to the introduction during the 1980s of highly efficient gas turbines and combined cycle generators that produce much more electricity from a given amount of gas. A relatively small gas-fired generator can compete effectively with power from a large central generating station. Additionally, small distributed generation is becoming economic, and some renewable energy resources, especially wind power generation, are also on the verge of becoming competitive.
92. Because of these fundamental changes in industry technology, small producers of electricity can compete with large producers, and both the smaller utilities and the retail customers of a number of utilities have demanded access to competing power suppliers in hopes of lowering their electric bills,
93. One hallmark of electric industry restructuring has been the growth of wholesale trade. In the past, wholesale power purchases made up a small fraction of a large vertically integrated utility's power supply, with most of its power needs met by its own generation. Today, however, even large vertically integrated utilities rely increasingly on wholesale purchases for their energy supplies. For example, as shown in Table 1, between 1989 and 2000, generation by investor-owned utilities grew from 2,132 thousand GWh to 2,230 thousand GWh, an increase of less than 5 percent. During this time, wholesale power purchases by these utilities almost tripled. Table 1 also shows that in 1989 wholesale power purchases provided 18 percent of the total electric energy available to investor-owned utilities from both wholesale purchases and their own generation. By 2000, wholesale purchases provided over 37 percent of investor-owned utility electric energy. This percentage has steadily increased since 1989, and is expected to continue to grow as utility-owned plants are sold or retired and new power supplies are acquired competitively in most parts of the country.
Data for 2001 is not yet available. Investor-owned utility purchases include purchases from affiliates.
94. Table 1 demonstrates the increasing importance of competitive wholesale energy acquisition in the United States electric power industry, and the need for this Commission to ensure that transmission, market rules and institutions are reformed as necessary to support the new environment. It also makes clear that a retreat from competitive markets to a cost-regulated vertically integrated world would be difficult—the nation now depends increasingly on wholesale interstate electricity markets.
95. Similar data are presented in Tables 2 and 3 for large public power utilities and generation and transmission cooperatives that generate at least some of their own power.
“Large Public Power Utilities” includes municipals, federal power authorities. Data for 2001 is not yet available.
“Generation & Transmission Cooperatives” includes cooperatives with generation and transmission facilities, but excludes distribution cooperatives. Data for 2001 is not available yet.
96. The transition to competitive electricity markets is characterized by opportunity and uncertainty. The promise of competition is the opportunity to develop more innovative technologies, improve services, lower average electric rates and provide more customer choice than is likely under a strictly regulated monopoly environment. During the transition to competition, these promises are only partly fulfilled, and results vary regionally as a result of different choices about retail restructuring. Additionally, the California electricity crisis of 2000-2001, allegations of improper trading practices, the collapse of Enron Corporation in December 2001 and the deteriorating financial health of many electric suppliers and marketers at this time have added unprecedented uncertainty about, and lack of confidence in, today's electric markets.
97. In addition to general concerns about adequate constraints on the exercise of market power by power sellers, there is uncertainty in the industry about impediments to new generators entering the market, adequacy of incentives to build much needed generation and transmission infrastructure, availability of non-discriminatory transmission service for all sellers and buyers in a regional market and the risk of making long-term commitments when market rules are subject to frequent experiment and change. Differences in market rules between regions make it difficult to transact business across regions and thus also lead to increased uncertainty in the industry and the risk of market manipulation.
98. Investors, generators and transmission providers are reluctant to invest in new generation and transmission infrastructure if the rules for setting energy or transmission prices are not yet known or are subject to frequent revision.
99. The promise of wholesale competition may go unfulfilled—or at best continue to be delayed at great cost—unless many of these uncertainties are resolved. This proposed rule is intended to help resolve generically many of the uncertainties facing the electric power industry and to restore confidence in future power markets.
100. The primary purposes of the Federal Power Act are to curb abusive practices by public utilities and to protect customers from excessive rates and charges. To achieve these ends, section 205 of the Federal Power Act requires that no public utility shall “make or grant any undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage,” with respect to the transmission of electric energy in interstate commerce or wholesale sales.
101. Moreover, the Commission's regulatory authority “clearly carries with it the responsibility to consider, in appropriate circumstances, the anticompetitive effects of regulated aspects of interstate utility operations pursuant to [Federal Power Act sections] 202 and 203, and under like directives contained in [Federal Power Act sections] 205, 206, and 207.”
102. The Court of Appeals for the District of Columbia Circuit reviewed challenges to Order No. 888 and found that the “open access requirement is authorized by and consistent with the [Federal Power Act],” and upheld the order.
103. We find that undue discrimination and anticompetitive behavior persist, as detailed in Section III and Appendix C, in both wholesale and retail transmission of energy. Pursuant to our statutory mandate to remedy undue discrimination and anticompetitive effects in these markets, as interpreted by the Supreme Court, we will apply the requirements of this rule to the transmission component of bundled retail transactions. At a minimum, all transmission service in interstate commerce must be subject to the same non-discriminatory non-rate terms and conditions in order to eliminate undue discrimination in wholesale markets and in retail choice markets. With respect to rates for bundled retail transmission service, however, we will work with states to address difficult transition rate issues.
104. In light of these statutory responsibilities and authorities under the Federal Power Act, we have assessed the state of the electric utility industry and determined that it is necessary to act promptly to provide stability to the industry and to assure that customers receive adequate supplies of electric energy at the lowest reasonable price. During the past six years, the implementation of open access transmission under Order No. 888 has fundamentally altered the landscape of the electric utility industry by removing major discriminatory barriers to the use of the interstate transmission grid and thereby opening the door to competition in wholesale electric power markets. However, even with the Order No. 888 open access
105. We find that:
(1) the operation of the Commission's
(2) public utilities that own, operate or control transmission facilities and also participate in power markets continue to possess substantial transmission market power and retain the ability to unduly discriminate in the provision of transmission service and spot market energy services;
(3) lack of standardized wholesale electric market design allows undue discrimination within and across regions, can result in unjust and unreasonable pricing and allocation of transmission and permits the exercise of market power (and thus unjust and unreasonable rates) in power markets; and
(4) proper price signals are not being sent to the marketplace, with the result that market-based rates in many places are distorted, and reasonably accurate price signals necessary for infrastructure additions are not being sent.
106. To remedy remaining undue discrimination in the provision of interstate transmission services and in other industry practices, and to ensure just and reasonable rates for sales of electric energy within and among regional power markets, the Commission proposes to modify the Order No. 888
107. The Commission's goal in Order Nos. 888 and 2000 was to harness the benefits of competition for the nation's electricity customers by assuring adequate and reliable supplies of electricity at a just and reasonable price. As discussed above in the Need for Reform section (Section III), the current rules and regulations have prevented the full attainment of that objective. To address these problems in the current system, we are proposing a comprehensive package of reforms that are described more fully in this section.
108. Section III and Appendix C provide numerous examples of ways that an entity that owns both
109. To remedy this discrimination we propose to place all transmission customers under the same set of rules. We propose to place transmission service for bundled retail customers under the same terms and conditions of service as wholesale transmission service. To accomplish this we propose to revise the existing
110. Also, no later than September 30, 2004, or such date as the Commission may establish, we propose to eliminate the distinction between Point-to-Point and Network Integration Transmission Services by having one service, Network Access Service, that contains elements of both types of service—the flexibility of Network Integration Transmission Service and the tradability of Point-to-Point Transmission Service. We propose these time periods to provide sufficient time for the development of the necessary new software systems. Network Access Service is based on an open spot market for imbalance energy and a uniform congestion management methodology,
111. To provide the price signals needed to manage congestion, the Independent Transmission Provider will be required to operate a day-ahead and real-time market for energy. To provide customers with a mechanism for achieving price certainty under the new congestion management system, we also propose to require that customers be given Congestion Revenue Rights for their historical uses that protect against congestion costs when specific receipt and delivery points are used.
112. LMP and Congestion Revenue Rights will provide price signals to indicate where new investment is needed; however, the price signals alone may not guarantee sufficient investment. We also propose to require a regional transmission planning and expansion process to provide a backstop process for ensuring that needed transmission construction is undertaken. We propose that this process begin six months from the effective date of the Final Rule, even though much of the country will not have had the opportunity to respond to LMP and Congestion Revenue Rights for another few years.
113. At this stage of the industry's evolution, structural barriers to competitive markets remain, so to address this we are proposing market power mitigation measures for the spot markets that will be operated by the Independent Transmission Provider. These measures are designed to address the two significant structural problems in wholesale energy markets—the existence of localized market power that arises from transmission constraints, and the lack of price-responsive demand. The market power mitigation proposal is a framework that can be tailored to reflect the competitive conditions of the particular region. It is designed to be reexamined annually and adjusted as needed to reflect changes in the competitive structure of the region, including a phasing out of mitigation measures as resource adequacy and demand response develops. Because market power mitigation of spot market prices will tend to suppress the price signals for new entry, we are also proposing a non-price mechanism to assure that load meets a long-term resource adequacy requirement.
114. To avoid the market design flaws discussed in the Need for Reform section (Section III) and Appendix C and market manipulation in Appendix E, and to minimize the potential for seams issues, we propose a standardized tariff that incorporates the best practices and builds on the lessons from our experience with organized markets. In Appendix B, the proposed SMD Tariff standardizes many aspects of the basic market design. However, it also allows flexibility in a number of areas to customize the basic market design to meet regional requirements where such customization will not lead to further discrimination or inefficiencies.
115. We propose to permit small entities to seek waiver of the Standard Market Design Final Rule requirements. The regulations we propose include waiver provisions under which public utilities, and non-public utilities seeking exemption from the reciprocity condition, may file requests for waivers from all or part of the Commission's regulations.
116. Finally, while we have attempted to standardize the basic aspects of the market design policy, this proposed rule does not include detailed business practices and communication protocols that will be needed to administer Standard Market Design. We fully appreciate the benefits of business practice standardization and, as we did in the natural gas industry, we believe it is best if industry participants develop these types of highly detailed and technical standards. Thus, we are proposing a process, similar to that used in the natural gas industry, that could be used for standardization of business practices, data sets and communication protocols that includes representation of all affected market participants. Upon its formation, the Wholesale Electric Quadrant of the North American Energy Standards Board (NAESB), working closely with Independent Transmission Providers who would collectively serve in an advisory capacity to the board, would produce business practice and electronic communication standards. NAESB would notify the Commission when it has adopted standards, and the Commission would then use rulemaking proceedings to propose the incorporation of these standards by reference into the Commission's regulations. If the industry is unable to reach consensus on a particular standard, the Commission would be available to resolve the dispute, so that the industry process can continue, or the Commission could develop its own standards if necessary. Consistent with gas industry regulation, issues of policy that affect significant resources or that
117. Standard Market Design is intended to cure undue discrimination, in part, with respect to the use of the transmission grid. As we discussed in Section III.B.2, there are different rules for bundled retail transmission service and for wholesale and unbundled retail transmission services. These differences result in unduly discriminatory preferences for the vertically integrated transmission owner's bundled retail customers.
118. We propose that to eliminate this undue discrimination, the transmission component of bundled retail service must be taken under an open access transmission tariff. Under the current
119. In the interim, however, we propose to require that bundled retail load be placed under the existing
120. We propose that the public utilities file these revisions to their tariffs and execute service agreements to take Network Integration Transmission Service on behalf of their bundled retail load no later than July 31, 2003. We recognize, however, that some public utilities (
121. Since the implementation of the existing
122. In several orders, the Commission clarified three significant points: (1) A customer must submit a request to roll over its contract no later than sixty days prior to the date the current service agreement expires;
123. These revisions have a significant impact on the rights of current transmission customers and will continue to do so up until the time the SMD Tariff, including auctions of Congestion Revenue Rights, is in place.
124. Another form of undue discrimination is the lack of independence of the transmission provider in many regions of the country. As discussed in Section III.B.1, remaining corporate ties between generation and transmission within public utilities are problematic since they allow the vertically integrated utility to exercise market power to advantage its affiliated generation.
125. To remedy this undue discrimination, transmission service must be provided by an independent entity. Therefore, we propose to require all public utilities that own, control or operate facilities used for the transmission of electric energy in interstate commerce to: (1) Meet the definition of Independent Transmission Provider, (2) turn over the operation of its transmission facilities to an RTO that meets the definition of Independent Transmission Provider, or (3) contract with an entity that meets the definition of Independent Transmission Provider to operate its transmission facilities.
126. An Independent Transmission Provider is any public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce, that administers the day-ahead and real-time energy and ancillary services markets in connection with its provision of transmission services pursuant to the SMD Tariff, and that is independent (
127. We propose that affected public utilities must inform the Commission which Independent Transmission Provider will operate the public utility's transmission facilities no later than July 31, 2003. However, a public utility that is a member of an approved RTO or ISO or other entity that meets the definition of Independent Transmission Provider may file a request for a waiver of the filing requirements of this paragraph on the ground that it has already complied with the requirement.
128. Any entity meeting the definition of Independent Transmission Provider would file the SMD Tariff to provide transmission services, including ancillary services, and to administer the day-ahead and real-time energy and ancillary services markets. As discussed further below, an Independent Transmission Provider would also perform market monitoring and market power mitigation, long-term resource adequacy and transmission planning and expansion on a regional basis.
129. An Independent Transmission Provider would also file under section 205 any changes to transmission rates necessary to implement Standard Market Design, no later than 60 days prior to the date on which it proposes to implement Standard Market Design.
130. In addition, one or more public utilities may jointly file an application to meet the requirements of Standard Market Design. Also, an Independent Transmission Provider may make necessary filings on behalf of public utilities required to meet the requirements of this paragraph.
131. We seek comment on whether this remedy is adequate to remove the potential for unduly discriminatory behavior on the part of a vertically integrated transmission provider. Can the requirements of Standard Market Design be satisfied either by performing the function through an RTO or contracting with an independent entity to perform them? Given that most transmission providers have filed proposals to join an RTO, is a non-RTO compliance option necessary to cure undue discrimination and produce just and reasonable rates for transmission service and the sale of electric energy?
132. We have long recognized that the Independent Transmission Company (ITC) business model can bring significant benefits to the industry. Their for-profit nature with a focus on the transmission business is ideally suited to bring about: (1) Improved asset management including increased investment; (2) improved access to capital markets given a more focused business model than that of vertically integrated utilities; (3) development of innovative services; and (4) additional independence from market participants. We believe that these characteristics of ITCs can have significant benefits for the implementation of Standard Market Design, particularly in the areas of development of transmission infrastructure and structural independence from market participants.
133. The Commission recently approved a proposal by several transmission owners to form an ITC, TRANSLink Transmission Company, LLC (TRANSLink), to share responsibility with the Midwest ISO Regional Transmission Organization (the Midwest ISO)
Our rulings on the allocation of functions issues are based on our belief that for effective RTO operations, regional trading, and one-stop shopping, a single transmission provider must have overall authority and ultimate responsibility for transmission service in the region. We further believe that the security-constrained, economic dispatch needed for an efficient and reliable market is best operated by an independent regional transmission provider. However, we believe that it is acceptable for some functions with predominantly local characteristics to be delegated to an ITC so long as the RTO has oversight authority in the event that local actions have a regional impact. We find that this is critical to successful RTO development and especially important given the characteristics of the interstate transmission grid. It has become increasingly evident in recent years that even seemingly local issues, such as generator location or isolated transmission bottlenecks, can and do impact the larger grid, and that is why we believe that centralized RTO oversight is needed.
We also remain concerned that vesting control into sub-regional entities may create seams which could easily lead to re-balkanization. These difficult delegation decisions are made with our firm belief that ITCs can flourish under the RTO umbrella and that in performing certain delegated functions, ITCs will be able to effectively manage their assets, protect their value, and bring their expertise to increase efficiencies and enhance the value of their business. Nevertheless, these delegation decisions should not prevent ITCs from seeking additional authority, subject to Commission approval, at a later date after ITCs have gained experience under RTO operations.
134. We seek comment on the functions that an ITC should perform under Standard Market Design. Should the Commission retain the same delegation of functions that was approved in
135. We seek comment on whether an ITC that has no ties to a Market Participant, as defined in this proposal, is sufficiently independent to act as the Independent Transmission Provider. The ITC may hold grid assets such as transmission facilities and Congestion Revenue Rights and may be allowed a performance-based ratemaking program. Thus the Commission is concerned that the ITC may unduly discriminate in favor of its own transmission interests when carrying out operational and planning decisions in its role as Independent Transmission Provider. We seek comment on whether such ITC interests in transmission investment may cause the ITC to unduly discriminate in day ahead or real time markets operations or to discount generation, demand response, and other transmission owners' (
136. To address the discrimination described in Section III above and in Appendix C, we will require Independent Transmission Providers to provide a nondiscriminatory, standard transmission service to all customers.
137. To complement Network Access Service and implement the Standard Market Design, Independent Transmission Providers will manage congestion using LMP. Management of transmission grid congestion is difficult to do through bilateral transactions alone; thus a spot market is required to manage congestion efficiently. We believe that congestion management, balancing of load and generation in real time, and the provision of ancillary services can be accomplished most reliably and efficiently by a bid-based, security-constrained spot market.
138. In addition to administering a spot market to manage congestion, the Independent Transmission Provider will also use it to handle imbalances and the procurement of ancillary services. The Independent Transmission Provider would operate markets for energy, regulation, operating reserve—spinning and operating reserve—supplemental. These markets would be security-constrained, bid-based markets operated in two time frames: (1) A day ahead of real-time operations, and (2) in real time. Transmission services will be scheduled through the day-ahead and real-time markets. The Independent Transmission Provider would establish schedules for transmission service, and sales and purchases of energy, regulation, and both operating reserves, to ensure the most efficient use of the transmission grid. Although the Independent Transmission Provider will not be required to operate an organized market for either short- or long-term bilateral transactions, its scheduling process must accommodate such bilateral trades.
139. Network Access Service builds upon the existing Order No. 888 Network Integration Transmission Service and will be available to all eligible customers. As with Network Integration Transmission Service, Network Access Service offers flexible use of the transmission grid—it allows the load-serving entity to choose to serve its load with any available resource on the system (or access any interface to import power from a neighboring system), consistent with the Network Resource Interconnection Service discussed in the Generator Interconnection proposed rule.
140. Network Access Service is premised on dispatching of the regional transmission grid so that the customers that value transmission service the most will get it. All requested transactions must be physically feasible under a security-constrained dispatch. Where there are transmission constraints, the LMP system we propose will price out all transactions and redispatch available generation as needed to accommodate all requests for service.
141. Network Access Service gives the customer the right to transmit power between any number of combinations of receipt and delivery points. A receipt point is defined here as the location where a transaction originates, and a delivery point is defined as the location where a transaction terminates. Receipt and delivery points include both individual nodes as well as aggregated points,
142. Any customer using transmission service, whether a load-serving entity, generator, or marketer, would take Network Access Service. However, as explained more fully in Section IV.D.1, only those customers taking power off of the grid would pay the access charge. (All customers would pay congestion costs and losses associated with their particular transaction.) We expect that, in most instances, it would be a load-serving entity, rather than a generator or marketer, that would be the customer for transactions that result in power leaving the grid, and thus, the load-serving entity would be the entity paying the access charge.
143. Under the existing
144. With Network Access Service, all customers who want physically feasible service will be able to receive service; however, uncertainty can arise as to the rate paid to receive the service. In addition to the access charge (which recovers the embedded costs of the transmission system), the customer would be subject to the cost of congestion between its chosen receipt and delivery points. To achieve certainty with respect to price and avoid congestion costs, the customer would have to acquire the Congestion Revenue Rights associated with its specific receipt point-delivery point combination(s).
145. Accordingly, customers desiring service comparable to (but actually more dependable than) existing firm transmission service would need to acquire Congestion Revenue Rights for their receipt and delivery points and schedule service between those points in the day-ahead market. With the allocation process we propose in Section IV.H.2, customers under existing contracts will receive Congestion Revenue Rights that match their current use of the system, which will ease and simplify the conversion process. Customers using non-firm transmission service under the existing pro forma tariff could request service when needed in the day-ahead or real-time markets. To the extent the customer is willing to pay congestion costs and transmission losses, its requested transmission service would be available and provided.
146. The existing
147. The existing
148. To receive Network Access Service, a customer must meet the same requirements as those under the existing
149. As noted above, a customer would acquire Congestion Revenue Rights to assure price and delivery certainty for its transactions. Anyone can hold Congestion Revenue Rights. Congestion Revenue Rights can be acquired through a variety of means, including: (1) Direct allocation that is based on some measure of current or historical rights to the system; (2) periodic auctions; or (3) some combination of these methods. The initial process for acquiring these rights is discussed in Section IV.H.2.
150. Transmission service will be scheduled through the day-ahead market with deviations accounted for in the real-time market, as discussed in later sections. These scheduling opportunities are comparable to the existing
151. A Network Access Service customer would have to indicate the location of its receipt and delivery points when it schedules service in the day-ahead or real-time markets.
152. The existing
153. Thus, we believe that the requirement to designate network resources to receive transmission service may no longer be needed. Further, we note that under the existing
154. Under the existing
155. With Network Access Service, this process is no longer necessary. A Network Access Service customer can essentially access any point simply by requesting it through the day-ahead scheduling process or real-time transactions (and be willing to pay congestion costs and losses). To the extent the customer wanted to avoid the cost of congestion for the transaction, it could retain its existing Congestion Revenue Rights and acquire additional Congestion Revenue Rights for its new receipt and delivery points through an auction or secondary market.
156. Alternatively, the customer could request a “reconfiguration” of the Congestion Revenue Rights it holds,
157. Most service requests will be resolved through the day-ahead security-constrained dispatch. Nevertheless, the Independent Transmission Provider will need to conduct system impact and/or facilities studies for service involving the interconnection of a new load or generator. The Independent Transmission Provider will also routinely perform simultaneous feasibility studies to determine the configurations of Congestion Revenue Rights that can be accommodated. Thus, except for adding references to the simultaneous feasibility studies that will be performed in response to requests for Congestion Revenue Rights, sections of the existing pro forma tariff addressing various studies will remain largely unchanged. However, as discussed in Section IV.C.8, these studies are now required to be performed by an Independent Transmission Provider.
158. Under the existing
159. This is a major improvement over the current tariff, as it should eliminate most or all TLRs. To the extent practicable, when system conditions require curtailment (in real time) that cannot be resolved through the congestion management system, the Independent Transmission Provider should curtail the customers whose transactions contribute to the constraint on a
160. We propose that an Independent Transmission Provider can assess a penalty for failure to curtail if a transmission customer fails to curtail after reasonable notice. The proposed penalty is the locational marginal price plus $1000 per MWh. The Commission has approved a minimum notice period of ten minutes if the curtailment is for reliability purposes.
161. We also note that the Commission required transmission providers to incorporate procedures for addressing curtailment of parallel flows involving more than one transmission system (
162. Network Access Service adds the tradability that currently exists for “firm” Point-to-Point Transmission Service, but was not available under Network Integration Transmission Service. Customers may be able to acquire Congestion Revenue Rights from a particular receipt point to a particular delivery point directly from the Independent Transmission Provider, through a formal auction, or through secondary markets. Once a customer has these point-specific Congestion Revenue Rights, the customer may sell them at any time to another entity, whether or not that entity intends to transmit power. The sale could be for all or a portion of the amount or duration of the Congestion Revenue Rights. All resales of Congestion Revenue Rights must be reported on and conducted through the OASIS. As is currently the case in some ISOs, Congestion Revenue Rights will be traded at the price at which purchasers value the rights. The procedures for the auctions and resale of Congestion Revenue Rights are discussed in Section IV.E.3.
163. We seek comment as to whether all Congestion Revenue Rights must be sold through the OASIS, or whether some bilateral sales may be made and only reported through OASIS after the sale.
164. The ancillary services provided as part of the current
165. The Commission seeks to ensure transmission owners the opportunity to recover their revenue requirements for their transmission systems under Network Access Service. This charge could either be a license plate rate (charge depends on zone of delivery) or a postage stamp rate (same rate applies for all load within the Independent Transmission Provider's service area) and would be paid by all entities serving load within the Independent Transmission Provider's service area. Moreover, to facilitate trading across regions, we are proposing to change our policy on pricing of transactions that start and end in different transmission systems.
166. In addition, we are proposing to refine our policy on pricing of transmission expansions to provide incentives for market-driven solutions. To facilitate the addition of much needed transmission infrastructure, we
167. Under the existing
168. To recover the embedded costs of the transmission grid, the Commission has historically permitted transmission providers to assess an access charge, in the form of a load ratio share charge or a per kW per month charge, on all transactions taking place on the transmission provider's system.
169. While this method of pricing has been effective in recovering a transmission provider's revenue requirement, some changes are required to reflect the new Network Access Service and to address unintended consequences of the current rate design. First, we propose that transmission owners recover embedded costs through an access charge assessed mainly to load-serving entities, based on their respective shares of the system's peak load,
170. Second, we propose to eliminate all “rate pancaking,” which involves charging separate embedded cost charges for moving power over separate Independent Transmission Provider service areas. We propose to eliminate rate pancaking both within an Independent Transmission Provider's service area and between service areas. Rate pancaking impedes the ability of distant generators to compete with nearby generators by imposing charges to transmit energy from distant generators that are unrelated to actual variable transmission costs. Assessing the access charge primarily to load-serving entities based on their load ratio share rather than on the number of service areas over which energy is transmitted increases generation competition by allowing distant generators to compete more easily with nearby generators.
171. As discussed further below, we propose that customers paying access charges would receive Congestion Revenue Rights (or alternatively, revenues from the auction of Congestion Revenue Rights). Thus, in exchange for paying the fixed costs of the transmission system, those paying access charges would receive the financial benefits—the stream of congestion revenues—resulting from usage of the transmission system. In addition, we seek to minimize cost shifts that could result from our proposal, and we propose to maintain as much as possible the explicit and implicit transmission rights currently held by customers. Thus, customers currently receiving Network Integration Transmission Service and firm Point-to-Point Transmission Service under the existing
172. First, we seek comment on the treatment of existing customers taking long-term firm Point-to-Point Transmission Service that are not load-serving entities. Such customers currently pay an embedded cost charge in order to receive firm Point-to-Point Transmission Service under the Order No. 888
173. The second issue concerns the treatment of load-serving entities in retail open access states that attract loads away from their traditional utility suppliers. Under our proposal, a new load-serving entity that attracts load from other suppliers would be assigned a share of embedded costs—costs previously assigned to other suppliers. In areas where there is no Available Transfer Capability for additional Congestion Revenue Rights, we seek comment on how such new load-serving entities should receive an allocation of the customer's former load-serving entity's Congestion Revenue Rights. We propose that Congestion Revenue Rights “follow the load.” Thus, Congestion Revenue Rights previously allocated to other suppliers whose loads (and access charges) have been reduced would be reallocated to the new load-serving entities.
174. We propose to permit the use of license plate rates such as those that are currently in effect within ISOs. We seek comment, however, on whether we should retain license plate ratemaking only for a transitional period and at some later date, require that all regions have postage stamp rates. Should the Commission upon the recommendation of a Regional State Advisory Committee accept an embedded cost recovery mechanism for the region which may vary from neighboring regions?
175. To better illustrate the pricing proposals we have included Appendix F which identifies by customer types whether and under what circumstances they will pay the access charge and/or receive Congestion Revenue Rights under Network Access Service.
176. When a vertically integrated utility joins a regional organization such as an ISO or RTO, the Commission has required that the utility execute a service agreement under the regional transmission provider's transmission tariff. For instance, the Commission required the vertically integrated utilities in GridSouth to execute a service agreement under the GridSouth transmission tariff, thus ensuring that these utilities would take service for their bundled retail load under the same terms and conditions as all other users of the grid.
177. With respect to whether the GridSouth transmission charge should be applied to the bundled retail load, the Commission permitted the utilities to pay the transmission portion of the bundled retail rate, but required that the service agreement explicitly state the rate to be charged.
178. Now that the Commission is asserting jurisdiction over all transmission service in interstate commerce, including that for bundled retail service, the question arises as to whether different charges for transmission service for wholesale and bundled retail customers should be permitted. Allowing different rates for wholesale and bundled retail customers could lead to undue discrimination if the rate setting policies of the state and the Commission differ significantly. The Commission seeks comment on whether all customers should be charged the same transmission rate either upon implementation of Standard Market Design or after a reasonable transition period of four years.
179. Under current rate designs, a user that transmits power from one region to another would pay two transmission charges to recover the embedded costs of the transmission provider from which power was exported as well as the embedded costs of the transmission provider where power is delivered to load. As long as transmission owners have an opportunity to recover their embedded costs, to increase competition, we propose to prevent customers from being assessed multiple transmission charges.
180. We have concluded that rate treatment for inter- and intra-regional transactions should be consistent to avoid creating artificial incentives or disincentives for trade across regions. Thus, the design of rates for Network Access Service should eliminate the payment of multiple access charges, such that only one access charge is paid for power to reach load. Accordingly, an export and through-and-out transaction originating in an Independent Transmission Provider's system and terminating at a load in another Independent Transmission Provider's system would pay only the access charge for the transmission system where power is ultimately delivered to load.
181. It has become apparent that transmission pricing across RTO borders can have a significant impact both on power purchasing decisions and on RTO formation. A customer's choice as to whether to purchase power from a generator located within the same RTO or a neighboring RTO is directly affected by the fact that one generator faces an additional access charge to reach the RTO in which the load is located. This additional access charge may cause the sale to become uneconomic.
182. In addition, decisions on which RTO/ISO to join may be affected by inter-regional pricing. Choices driven by the economics of transmission owner's merchant function's trading patterns, rather than by the most rational and efficient aggregation of transmission assets for a particular region, could result in oddly configured RTOs.
183. Rate pancaking across the numerous transmission owning utilities that comprise the RTO has been eliminated by the implementation of license plate rates, while continuing to provide an opportunity for the transmission owners to recover their full revenue requirements. We propose that the same or a similar rate structure should be applied to inter-regional transfers. In a competitive market environment, reliability and the supplier's cost of generation, rather than sunk transmission costs, should be the primary drivers for a customer's choice of power suppliers. To the extent rate design facilitates that result, transmission owners would have a greater incentive to join an RTO based on where their transmission facilities most benefit customers and markets, not on where their generators have better opportunities to make off-system sales
184. However, absent other adjustment mechanisms, if customers going through and out of an RTO are no longer charged access fees by that RTO for transmission service, these costs would instead be borne by the load served by the RTO through the existing load ratio share methodology.
185. Therefore, we propose to create a mechanism that recognizes the import/export quantities in establishing the revenue requirement to be recovered through the access charge. We seek comment on two approaches that could be used.
186. One method would be to have the “source” Independent Transmission Provider allocate a portion of its revenue requirement to the “sink” Independent Transmission Provider's transmission customers. An Independent Transmission Provider's revenue requirement could be reduced by the amount of revenues associated with through-and-out service and that portion of the revenue requirement would then be included as uplift in the scheduling charge paid by all customers of the sink Independent Transmission Provider in whose service area the power sinks. Under this approach, costs would not be shifted from the beneficiaries of the inter-regional transaction to the load on the source side of the transaction. At the same time, embedded cost recovery would not interfere with short-run efficiency, since embedded costs would not be recovered in individual inter-regional transactions, but would instead be recovered through uplift from all customers in the zone of the sink Independent Transmission Provider. This method would require a projection of inter-regional transfers and a rate filing to accomplish the re-allocation of costs between Independent Transmission Providers. It would also require a decision as to how narrowly to focus the cost allocation (
187. Alternatively, under a revenue crediting approach, inter-regional transfers could be priced at the load ratio share charge (or a similar transmission charge)
188. We seek comment on whether there should be a uniform cost allocation of inter-regional costs among all zones within an Independent Transmission Provider's system. For instance, there will likely be opposition to a region-wide charge by customers who do not import power. To address this concern, the inter-regional transfers could instead be netted out between zones within neighboring Independent Transmission Providers. This way the costs would be assigned to all customers within the import zone and the revenues would be returned to the export zone. These transmission costs could be assigned to the zone where the power was imported as if the neighboring Independent Transmission Provider's facilities were part of that zone. Likewise, the zone where exports leave an Independent Transmission Provider would receive the transmission payments associated with the exports. It is possible that the revenue sharing plan used by ISOs with license plate rates to resolve intra-ISO, interzone transactions could be broadened to encompass inter-RTO transactions.
189. As noted above, the proposed rule advocates treating inter- and intra-regional transmission pricing the same. As explained elsewhere, customers within the region who pay the access charge will be entitled to Congestion Revenue Rights or the revenues from the auction of those rights. We propose a similar result for inter-regional transactions when customers in one region are paying a portion of the embedded costs of another region. We seek comment on how to assign Congestion Revenue Rights to the customers of the importing region. For example, if Midwest ISO is a net exporter to PJM, customers on PJM's system will be obligated to pay a portion of Midwest ISO's embedded costs. PJM's customers could receive a proportionate share of Midwest ISO's Congestion Revenue Rights.
190. To the extent the Commission adopts a true-up methodology for recovering the costs of through-and-out services, should a similar pricing methodology be applied to parallel path flows? Parallel path flows are comparable in that one region benefits by the use of a neighboring region's transmission facilities. Parallel path flows are currently resolved through cooperation. An alternative method would be to price all uses of the grid. We seek comment as to how cost impacts of parallel path flows across regional borders should be addressed.
191. The existing transmission grid has fallen far behind the demands that have been placed on it. Over the last ten years, we have seen a strong increase in the amount of new generation, which has been built largely in locations that make the most economic sense for the builder of the generation (i.e., where land is affordable and economic sources of fuel, water and labor are near). However, we have yet to see a parallel jump in construction of transmission infrastructure. The absence of needed new transmission facilities has led to more and more congestion, which hinders customers from seeking and depending on more distant and competitive supply choices.
192. The sluggishness of transmission construction is largely because: (1) Siting transmission is a long and contentious process; and (2) mismatches between those who benefit from the new facilities and those who pay for them, particularly when the two affected sets of customers are served by different transmission providers, are often more than enough to make sure the new facilities do not get built. The Department of Energy's 2002 National Transmission Study points to state-by-state siting approval, a lack of regional
193. The Commission's pricing policy for network upgrades, whether for reliability or economic reasons, has traditionally favored “rolled in” pricing, where all users pay an administratively determined share of new facilities. This policy was based on the rationale that the transmission grid is a single piece of equipment such that system expansions are used by and benefit all users due to the integrated nature of the grid. This method forms the basis of the pricing proposal in the Generation Interconnection proposed rule.
194. If the expansion is for region-wide reliability, there is little disagreement as to who should pay for the necessary facilities—all ratepayers. Likewise, interconnection facilities are non-controversial; there is general agreement that these facilities should be directly assigned to the interconnecting generator.
195. What we see, however, is that economic expansions that would remove congestion and allow customers to reach more distant power supplies are the most difficult to get sited. This is at least in part because state siting authorities have no interest in siting a line that benefits a particular generator or a distant load in another state because to do so would require the load on the constructing public utility's system to pay for the new facilities. The state authorities, at a minimum, need assurance that the costs of that expansion will be paid for by those who benefit from the expansion in order to have sufficient incentive to site the new facilities.
196. Our goal is to remove any cost recovery impediments to transmission expansion so that needed upgrades get built now. Traditional means of expansion pricing may not be the most effective way of encouraging new transmission infrastructure, in part perhaps because they do not take into account the wide regional benefits of higher voltage upgrades that can accrue beyond a single transmission owner's system.
197. We believe that a more precise matching of beneficiaries and cost recovery responsibility would encourage greater regional cooperation to get needed facilities sited and built. Our preference is to allow recovery of the costs of expansion through participant funding,
198. The Generator Interconnection proposed rule introduced the idea that participant funding may be an acceptable pricing policy where an independent entity determines: (1) The cost of and responsibility for needed upgrades; (2) congestion price signals to which the customer responds (along with Congestion Revenue Rights); and (3) the assumptions underlying the power flow analysis.
199. The Commission envisions that, under Standard Market Design, the Independent Transmission Provider will perform all of these functions, which will allow the Commission to consider the use of participant funding. However, full compliance with Standard Market Design will take some time. We are eager to see new infrastructure in place as soon as possible and believe that participant funding will be a useful tool to make that happen. Accordingly, we propose that, for proposed transmission facilities that are included in a regional planning process which is conducted by an entity, whether an RTO, ISO, or other independent entity, that is independent, we will consider participant funding for that project.
200. In the absence of independence, we would apply a default pricing policy that would recognize the regional benefits of transmission expansions. Under this default policy, we propose to roll-in on a region-wide basis all high voltage network upgrades of 138 kV and above. Since lower voltage, sub-regional transmission needs are less likely to benefit the whole region, the cost of network facilities below 138 kV could be more appropriately allocated to a sub-region (
201. Further, as we explain in Section IV.G.3, Regional Planning Process, we encourage the formation of Regional State Advisory Committees, which, in addition to facilitating the siting of regional expansions, can enable states to work together to identify beneficiaries of expansion projects and make recommendations on pricing proposals. To the extent there is agreement within the Regional State Advisory Committee, the Commission would look favorably on a pricing proposal by the Regional State Advisory Committee if it is consistent with the FPA. Such a proposal might take the form of roll-in, an assignment to beneficiaries, or some combination of the two.
202. We seek comment whether these pricing proposals are appropriate to meet our goal of expediting needed infrastructure investment or whether another method would be more effective.
203. Under Network Access Service, all transmission customers may request transmission service. The Independent Transmission Provider must honor all valid transmission requests where there is sufficient capability,
204. LMP is the method that is currently used for managing congestion in the regional markets run by both PJM and New York ISO. It is also proposed to be adopted as the congestion management system for ISO-New England in 2003 and for the California ISO in its proposed market redesign.
205. LMP is a market-based method for congestion management. Congestion is managed through energy prices and transmission usage charges (congestion and loss charges) determined in a bid-based market. When there is no congestion anywhere on the system (when there is enough transmission capacity to get power from the cheapest available generators to all potential buyers) there will be only one energy price in the transmission system, the price bid by the last, or marginal, generator that provides energy or load that offers to reduce its demand.
206. For example, assume there is congestion or a constraint on one transmission interface. Some low-cost generators may not be able to deliver energy to load on the other (import) side of the constraint. So, they will need to reduce their production because of the constraint. To signal these generators to reduce their production, the energy price that these generators would receive would be lowered. To replace the low-cost generation, more expensive generators on the other side of the constraint (export) must be dispatched. To signal to these higher cost generators that they should increase their production, the energy price they would receive would increase. As a result the energy price on each side of the transmission constraint would be different. The energy price would be lower on the side where more suppliers are trying to sell out of the region than can be accommodated by the transmission capacity. The energy price would be higher on the side where more expensive local generation must be used because of the transmission constraint. As discussed further in Section IV.F., for purchasers of energy in the Independent Transmission Provider-run spot markets, the LMP at the node closest to them is their delivered power cost (energy charge plus transmission charge). The generators are then paid the LMP at the nodes closest to them.
207. For customers buying energy through bilateral contracts rather than in spot markets, the transmission usage charge would reflect the marginal cost of transmission between a receipt point and a delivery point.
208. LMP uses a financial instrument called a Congestion Revenue Right to provide customers with price certainty for transmission service.
209. Any changes a customer wants to make to the transmission service it has scheduled in the day-ahead market must be accomplished in the real-time market at real-time prices, which may be different from the day-ahead prices. A customer wanting less transmission service than it requested and received in the day-ahead market would effectively sell back to the market the amount of unused service. Conversely, a customer needing an additional amount of transmission service could buy the additional amount of service in the real-time market. No congestion revenues are paid to Congestion Revenue Rights holders for transactions made in real-time market.
210. The LMP system for congestion management is better suited to manage congestion in a competitive market than the congestion management system under the Order No. 888
211. The proposed SMD Tariff lays out the general framework and the basic rules for LMP. It is based on the best practices we have seen. We recognize that in certain regions there may need to be additional rules or changes to accommodate specific regional requirements. We also recognize that over time there likely will be a need to update the tariff provisions to offer new service options or to further refine the market rules. The
212. One concern that has been expressed in the Standard Market Design conferences and in comments on the Working Paper is that while LMP may work well with systems that are dominated by thermal plants, it may not work in systems that primarily rely on hydroelectric resources. In particular, the Pacific Northwest is concerned that an hourly bid-based system with LMP may be in conflict with Northwest resource uses, practices and obligations, which are dominated by hydroelectric generation. Much of this is from “run-of-river”
213. Northwest parties note that while annual costs in a thermal system are minimized simply by minimizing the costs in every individual hour the same does not hold true in a hydropower system. A hydroelectric dam with stored water has a marginal running cost close to zero, however, this does not mean that it should be dispatched first every hour. Rather, the value of hydropower over time depends on when that stored energy system can best be released to minimize costs over a season, a year, or even a multi-year period. Thus, there is a concern that in a hydropower system, a congestion management and energy spot market designed to minimize hourly costs will not minimize costs over a longer period.
214. Moreover, commenters have noted that decisions about water use in the Northwest are based on more than electric power cost minimization. Decisions about use of hydropower facilities involve coordinated trade-offs among power needs, the needs of fish and wildlife, irrigation, flood control, recreation and other factors, which may be difficult to reflect in the bids of individual units. Some parties in the Northwest acknowledge that a bid-based LMP system could be adapted to meet the objections above but are concerned either that such a system may be imposed without adaptation or that the adaption will be done poorly. There is also concern that adaptation to a bid-based security-constrained system may reopen such issues as transmission priorities and preference power allocations that have been settled over many years of negotiation based on factors other than market efficiency. Finally, Northwest parties worry about obtaining sufficient Congestion Revenue Rights to protect against congestion charges.
215. We believe that the proposed Standard Market Design would work well in every region and for all types of fuel sources; we believe that the concerns expressed by participants in the Pacific Northwest can be accommodated within the LMP system we propose. First, use of the Independent Transmission Provider's bid-based spot energy markets would be
216. For hydropower generators that wish to participate in the Independent Transmission Provider's spot energy markets, the Standard Market Design that we propose can accommodate the special features of hydropower facilities. Suppliers would be allowed to reflect their opportunity costs in their bids; bids need not be limited to marginal running costs. Also, generators such as hydropower facilities would have the option (but not the requirement) of requesting the Independent Transmission Provider to schedule the generator's designated MWhs over the highest priced hours of the day, to economically optimize hydropower production over the day. LMP is a result of a least-cost dispatch of the resources available to the transmission system in a manner that recognizes both the operational limits of those resources and the operational limitations of the transmission system. As a result, customers' loads can be met at the lowest total cost (as reflected in the submitted bids) consistent with the reliable operation of the system, which should be the objective on any system regardless of the resource base of the transmission system.
217. In short, we see no reason why the proposed Standard Market Design would prevent hydropower generators from operating in a way that accommodates their special features. Indeed, we believe that the LMP system would aid hydropower generators in optimizing the economic value of their resources within their legitimate operational constraints, because the prices for energy and transmission would signal the economic costs of providing energy and transmission service at different locations and time periods.
218. Finally, our proposal here would not abrogate existing pre-Order No. 888 transmission contracts, so customers holding these rights could continue their existing services under the existing contractual provisions. In addition, this proposal would allocate Congestion Revenue Rights or auction revenues to parties based on their recent historical usage of transmission. Thus, customers receiving transmission service under the Order No. 888
219. We agree that the operational limits of both the resources and the transmission systems need to be fully considered in the design of the specific market rules. For example, there is likely a need to calculate opportunity costs for hydroelectric resources differently from thermal plants. These differences can affect market mitigation measures. However, we are concerned about whether different market designs can be in place in the Northwest and the rest of the West, and ask for comment on whether the entire West must have a common set of market rules to eliminate seams and prevent manipulation.
220. In the SMD Tariff we propose to include several different types of Congestion Revenue Rights to allow customers to protect against congestion costs. For example, one concern that we have heard from customers and suppliers in the Northwest is that a receipt point-to-delivery point Congestion Revenue Right may not work to effectively manage congestion on a system that utilizes several different hydroelectric facilities on a contingent basis to serve the same delivery points. A Congestion Revenue Right that recognized the contingent nature of the supply sources would be more valuable to customers in this instance. We believe that developing these types of Congestion Revenue Rights is possible and we propose to work with the regions to develop variations to meet regional needs. The congestion management system that we propose is flexible enough to accommodate these types of regional variations. Such variation and flexibility should not impinge on the development of a seamless electric grid.
221. To implement LMP, the Independent Transmission Provider must operate an energy market to determine the marginal cost of redispatch. We propose to require that the Independent Transmission Provider operate both a day-ahead and a real-time energy market to manage congestion.
222. The Commission proposes to use real-time markets for energy to resolve energy imbalances. Under the proposal, the transmission customer would be charged the real-time price of energy for any imbalance,
223. The Commission also proposes that the Independent Transmission Provider operate a security-constrained, financially binding day-ahead energy market that is operated together with a day-ahead scheduling process for transmission service.
224. The day-ahead energy market is a bid-based market. Sellers submit bids that indicate the quantities of power they will offer for sale in each hour of the next day and the price for that power at each location (node).
225. Under the Commission's proposal, buyers are not required to procure energy through the day-ahead energy market. A load-serving entity may procure all of its power through bilateral transactions, in the transmission provider's spot markets, or by generating its own power.
226. The Commission proposes to require Independent Transmission Providers to allow buyers and sellers to submit purely financial bids, a feature that currently exists in the day-ahead markets run by PJM and New York ISO. These financial bids to buy or sell power are not backed by actual generation resources nor are they backed by actual load. Rather, these transactions are used to bring the prices in the day-ahead market and in the real-time market closer together. For example, suppose that the day-ahead price is consistently lower than the corresponding real-time price. Entities may therefore want to submit financial bids to buy energy in the day-ahead market at the lower price, and submit a corresponding bid to sell in the real-time market at the higher price, thereby making a net profit on the two transactions. The additional buyer bids in the day-ahead market would tend to increase day-ahead prices, while the additional supply bids in the real-time market would tend to reduce the real-time prices. The result is that the price differences in the two markets would shrink, as would the profits of sale. This process benefits the market. It helps market participants make better decisions in advance—in the day-ahead time frame—that will affect how much electricity they will sell or buy, because the day-ahead price becomes a more accurate gauge of what the real-time price will be.
227. The day-ahead energy market is operated together with the congestion management system and the day-ahead scheduling process for transmission service. The Independent Transmission Provider will determine market clearing prices for each hour in the day-ahead energy market based on the sale and purchase bids that are submitted. The market clearing price is the bid of the last unit of supply needed to satisfy the demand,
228. We believe there are important differences between Standard Market Design and the market design that was in effect in the California ISO when it experienced problems in the energy markets in 2000 and 2001. First, Standard Market Design is premised on the use of bilateral contracts. While LSEs may purchase energy in the spot markets, these purchases should constitute a small percentage of their actual purchases. In contrast, the California market design required the LSEs to purchase the bulk of their energy needs through the spot markets. Second, Standard Market Design includes a forward-looking long-term resource adequacy requirement to avoid the types of supply shortages that adversely affected California. Third, as discussed in more detail in Appendix E, Standard Market Design includes trading rules, a congestion management system, market power mitigation measures, and market power monitoring to address the manipulation strategies encountered in the California markets.
229. In determining market clearing prices, the Independent Transmission Provider factors in the operational limitations of the transmission capacity, such as congestion and reactive power needs, to ensure that the units that set the market clearing prices are consistent with the transmission system operations (
230. The day-ahead market would be financially binding. This means that a seller that is selected in the day-ahead market is obligated to actually provide the power in real time or in real time it will be charged the cost of procuring the shortfall through the real-time market.
231. Years of experience with organized markets makes it clear that a day-ahead market is a best practice that must be included in the Standard Market Design. The development of a day-ahead schedule for energy and transmission service, including certain ancillary services, provides reliability benefits. It allows the Independent Transmission Provider to have advance warning to ensure that sufficient units are committed to serve the projected load. For example, if the Independent Transmission Provider believes that load has not scheduled sufficient transmission service or energy purchases in the day-ahead markets, it can commit additional units to be available in real time. Because of their operating characteristics, different types of generation units have differing levels of start-up costs as well as different lead times to be available in real time. The day-ahead market gives the Independent Transmission Provider information on unit availability, costs and system needs well before real time so the Independent Transmission Provider has more options available to ensure reliability and reduce costs in the real-time market.
232. Finally, the day-ahead market provides an important platform for market power mitigation. We propose several mitigation measures to ensure that there is a well-functioning spot market for wholesale power. These spot
233. The Independent Transmission Provider will also establish hourly prices for certain ancillary services, which may differ by location to the extent that ancillary service requirements differ by location. Since the same supply resources can often be used to provide either energy or ancillary services, energy and ancillary services should have compatible market designs. Otherwise, there would be an incentive to sell one type of product over another. Since both are needed, a compatible system allows the supplier to sell energy or ancillary services, whichever is the most efficient use of the supply resources. This yields the lowest total costs to customers.
234. As explained further below, the Independent Transmission Provider will need to manage congestion in two time frames: (1) During the day-ahead scheduling process, and (2) during real-time operations. The Independent Transmission Provider will conduct separate auctions to manage congestion in each time frame. In the day-ahead auction, for each hour of the following day the Independent Transmission Provider will take bids to buy and sell energy, to provide certain ancillary services, and to purchase transmission service between identified receipt and delivery points. The Independent Transmission Provider will consider the bids for energy, transmission service and ancillary services simultaneously. Based on those bids, the Independent Transmission Provider will develop a schedule that maximizes the economic value (as reflected in the bids) of the transactions over the entire day-ahead period, in light of the amount of Available Transfer Capability and any resulting transmission congestion and losses. The Independent Transmission Provider will also establish prices for transmission service, energy and ancillary services that clear the markets.
235. Under LMP, transmission usage prices will vary based on the price of relieving transmission congestion and losses. Rather than using a system of physical reservations, a system of financial rights called Congestion Revenue Rights will be used to give customers the ability to protect themselves against congestion costs.
236. The initial allocation process for Congestion Revenue Rights will be done through compliance filings that allow for different treatment within each region. Since this must occur before Standard Market Design is implemented, we have not addressed initial allocation in the SMD Tariff, but it is discussed in Section IV.E.3.e below. This section describes allocation processes that would be used after the initial allocation has been done.
237. We propose to require that Independent Transmission Providers offer Congestion Revenue Rights of several types (one that we will mandate now and others that should be offered upon customer request when technically feasible) that allow transmission customers to obtain protection against uncertain future congestion charges. We have added a new section to the SMD Tariff that describes the types of Congestion Revenue Rights that would be available, how one acquires Congestion Revenue Rights after the initial allocation and how Congestion Revenue Rights provide protection against congestion costs (Part II.D., Congestion Revenue Rights). The proposed provisions are discussed below.
238. The Independent Transmission Provider would be required to offer Congestion Revenue Rights for all of the transmission transfer capability on the grid, but it would not be allowed to sell more rights than can be accommodated. Congestion Revenue Rights would be available over a variety of terms, such as weekly, monthly, yearly and perhaps for longer terms. If an entity pays to construct new generation or transmission facilities that add transfer capability, and the costs of the upgrade are not rolled in, the entity would receive the Congestion Revenue Rights associated with the new transfer capability. In the past the Commission has allowed credits for upgrades; is there still a role for credits under Standard Market Design?
239. Customers that have not acquired Congestion Revenue Rights in advance could schedule transmission service in the day-ahead market, but they would not have the Congestion Revenue Rights protection against congestion costs.
240. We propose that Congestion Revenue Rights be made available first in the form of receipt point-to-delivery point
Currently, in PJM and New York ISO only receipt point-to-delivery point obligations are offered. However, there has been considerable interest expressed by market participants in other types of Congestion Revenue Rights. For example, the Midwest ISO is considering offering a package of Congestion Revenue Rights that are similar to what we are proposing. Also, PJM is considering offering receipt point-to-delivery point options. Offering several different types of Congestion Revenue Rights would make the system more flexible and better able to adapt to the needs of specific customers. Also, certain types of Congestion Revenue Rights may be more valued in different regions of the country based on the physical configuration of the transmission system and the types of resources connected to that system. Various technical papers over the last few years have examined offering these alternate rights simultaneously and concluded that it is feasible under the conditions now specified in the SMD Tariff.
241. The SMD Tariff describes the characteristics of each of the types of Congestion Revenue Rights. These descriptions are summarized below.
242. A receipt point-to-delivery point right is a right that is specified by a receipt point (which can be a generator node, an aggregation of generator nodes, an interface, a trading hub, or any other collection of nodes) and a delivery point (which can be a delivery node, an aggregation of delivery nodes, an interface, or a trading hub), and the power in MW that is transmitted from the receipt point to the delivery point for a period of time (
243. A receipt point-to-delivery point right entitles the holder to the day-ahead congestion revenues associated with transmission service from the receipt point to the delivery point.
244. A receipt point-to-delivery point right would provide the holder with the right to schedule transmission service of the specified amount of power (MW) in the day-ahead market from the receipt point to the delivery point without paying any net charges for congestion (although the holder would need to pay a charge for losses). The reason is that every customer would be entitled to inform the Independent Transmission Provider to schedule its transmission service regardless of the congestion charge. In that case, the customer would be charged for congestion (as well as for losses). But a self-scheduled customer holding a receipt point-to-delivery point right for at least the same amount of power between the same receipt and delivery points would receive congestion revenues that fully offset the congestion charge.
245. Receipt point-to-delivery point rights can take the form of obligations or options. The difference between obligations and options becomes important when congestion occurs in the opposite direction from the right, that is, when there is congestion from the delivery point to the receipt point. In this case, congestion revenues in the direction of the right are negative. Under a receipt point-to-delivery point obligation, the Congestion Revenue Rights holder in that case would be required to pay the negative congestion revenues to the Independent Transmission Provider. Under a receipt point-to-delivery point option, the Congestion Revenue Rights holder would not be required to pay the negative congestion revenues to the Independent Transmission Provider. Existing firm point-to-point transmission contracts under the Order No. 888
246. A flowgate is a particular transmission facility or group of facilities (
246a. Consider, for example, a very simplified transmission network that connects two points, A and B, with two different but interconnected transmission lines, a northern line and a southern line, as shown below:
246b. Unlike a receipt point-to-delivery point obligation, a flowgate right would never require the holder to make congestion payments. The congestion revenue associated with a flowgate in a specified direction would equal the additional net economic value to market participants that would result by incrementally increasing the flowgate's capacity in the specified direction. That additional net economic value may be either positive (
247. Receipt-point-to-delivery-point rights offer the transmission customer with long-term energy contracts the best way to protect itself against hourly congestion costs. However, many transmission customers may be meeting their loads' needs with a portfolio of generators scattered around a regional electricity market. Such customers may be seeking a more flexible type of right than the receipt-point-to-delivery point right (which is typically only reconfigured on a monthly basis and which can be traded on the secondary market most easily if another customer requires the same points as specified in the right). The major market advantage of the flowgate right is that since there are fewer congested flowgates than possible under receipt-point-to-delivery-point rights, transmission customers can focus their rights on the key congested flowgates. This allows for coverage of much of the congestion charges (in some estimates, between 80 percent to 90 percent). However, the flowgate rights may not provide a complete protection against congestion charges for a receipt point-to-delivery point energy transaction, since the congestion revenues may differ from the congestion charges.
248. At the start of Network Access Service, the Independent Transmission Provider would be required to offer receipt point-to-delivery point obligations. These rights are the easiest to implement because they are already in wide use. While we want the market to develop additional choices for customers, we are concerned about requiring implementation of numerous types of rights, including types of Congestion Revenue Rights that have not yet been tested by an ISO or RTO, when Standard Market Design is first implemented. Because there is no experience with the other types of rights, we propose not to require the Independent Transmission Provider to offer them initially. However, upon the request of market participants, the Independent Transmission Provider would be required to offer receipt point-to-delivery point options and flowgate rights as soon as technically feasible.
249. Additionally, Congestion Revenue Rights could be offered for various terms,
250. As explained above, holders of Congestion Revenue Rights would be entitled to receive congestion revenues associated with transmission congestion in each hour of the day-ahead market. The aggregate amount of Congestion Revenue Rights issued by the Independent Transmission Provider would be the amount simultaneously feasible based on Available Transfer Capability under normal operating conditions. As a result, during normal operating conditions, the Independent Transmission Provider would collect enough congestion charge revenue from users of transmission service in the day-ahead market to fully pay the day-ahead congestion revenues owed to holders of Congestion Revenue Rights. Indeed, the Independent Transmission Provider might collect a surplus of revenue in some hours during normal operating conditions. However, when a significant amount of transmission facilities are out of service, so that less transmission service can be provided, the Independent Transmission Provider may collect less congestion charge revenue from transmission users than the amounts owed to Congestion Revenue Rights holders.
251. There are two ways to handle this revenue shortfall. First, the amount of congestion revenues paid to the holders of Congestion Revenue Rights may have to be reduced. As a result, the customer may only be able to protect against a portion (
252. We believe it is important that there be an active secondary market for Congestion Revenue Rights. This will allow a market mechanism for customers that have Congestion Revenue Rights to acquire new ones or to sell Congestion Revenue Rights they no longer need. Additionally, this provides a way for market participants that do not have Congestion Revenue Rights to acquire them. Market participants would be allowed to resell any Congestion Revenue Rights that they have been awarded for the full term of the rights or for a part of the term. Resales could be transacted bilaterally between willing buyers and sellers. In addition, we propose to require that the Independent Transmission Provider conduct periodic auctions of Congestion Revenue Rights. The Independent Transmission Provider's auction would allow holders of rights to resell their Congestion Revenue Rights in an organized market. This would provide greater price transparency for these rights than if all sales were conducted through bilateral transactions. Moreover, the auctions would provide the ability to reconfigure Congestion Revenue Rights into different receipt and delivery points, or into different types of rights (
253. In the auctions, buyers and sellers would submit bids that specify the type of Congestion Revenue Rights desired to be bought or sold, the location, term and price. The Independent Transmission Provider would select the combination of bids that maximizes the economic value of the transactions for the participants. In so doing, the Independent Transmission Provider must reconfigure the Congestion Revenue Rights offered for sale in a way that maintains the simultaneous feasibility of the Congestion Revenue Rights. That is, the types and/or locations of the Congestion Revenue Rights offered for sale may differ from those that are purchased. The Independent Transmission Provider
254. The time period covered by the Congestion Revenue Rights sold in auctions would be a month or longer. We propose that an Independent Transmission Provider would be permitted, but not required, to conduct pre-day-ahead auctions for energy and ancillary services. Under such auctions, market participants could offer to buy and sell energy and ancillary services at specific locations on a forward basis for a specified time period, such as for a month or a year. Participation in these pre-day ahead markets, as in all markets, would be on a voluntary basis. Such purchases and sales of energy and ancillary service would require use of the transmission system, just as sales of Congestion Revenue Rights would. Thus, in conducting pre-day-ahead auctions, the Independent Transmission Provider would allocate transmission capacity among competing demands for Congestion Revenue Rights, forward energy and forward ancillary services so as to maximize the economic value of the winning bids. The Independent Transmission Provider would establish market-clearing prices for forward energy and ancillary services at each location, as well as market-clearing prices for Congestion Revenue Rights.
255. A potential benefit of pre-day-ahead auctions is that they could more easily maximize the economic benefits of transmission capability by considering a greater array of competing uses of the transmission grid. They could also provide a convenient, central market forum for buyers and sellers to arrange forward trades of energy and ancillary services. They could provide transparency and liquidity (and thus protection against manipulation) in long-term markets where liquidity has recently been reduced.
256. This section sets forth the bidding, scheduling, price determination, and settlement provisions necessary to implement LMP in the day-ahead and real-time markets for energy, regulation and both operating reserves. In this section, we lay out the basic elements that would be used for congestion management and operation of the spot markets.
257. We propose that the Independent Transmission Provider operate day-ahead and real-time markets for energy and certain ancillary services in conjunction with its scheduling of transmission service day ahead and in real time. These markets would allocate transmission and generation capacity among competing uses in different markets through LMP pricing. For example, the markets would determine how much transmission capacity would be allocated for transmission service to market participants completing bilateral energy transactions, for use by the Independent Transmission Provider in completing energy sales and purchases through its bid-based energy markets, and for providing ancillary services. The markets should be operated jointly to ensure that transmission and generation capacity is allocated where it is most valuable, and to ensure that the prices for the products and services are internally consistent.
258. Each day the Independent Transmission Provider would accept requests to schedule transmission service to support bilateral energy transactions or customer-owned generation for each hour of the following day. A customer desiring transmission service would be required to submit a scheduling request in a standardized form specified by the Independent Transmission Provider. For each requested transmission service, the scheduling request would indicate the receipt point and the delivery point of the bilateral energy transaction or customer-owned generation, the amount of power (MW) to be transmitted and the time period. To facilitate the ability of demand to respond to price signals, transmission customers will be given several ways of indicating their willingness to change their consumption based on congestion costs and marginal losses: (1) Customers (whether or not they hold Congestion Revenue Rights) would be allowed to specify in their scheduling requests the maximum transmission usage charge (reflecting the costs of congestion and marginal losses) at which the customer desires service;
259. Another way that transmission customers will be able to respond to price signals is by submitting multi-hour block bids, requesting transmission service for a block of consecutive hours and indicating the maximum price for the entire multi-hour period. For example, a multi-hour block bid might specify that the customer desires 10 MW of transmission service from receipt point A to delivery point B in each hour from 1 p.m. to 6 p.m. as long as the price per MW for the entire 5-hour period does not exceed $10. Such a bid would be accepted if the sum of the hourly transmission usage prices for each of the 5 hours did not exceed $10. Otherwise, the entire bid would be rejected. This option allows a customer, for example an industrial customer in a state with retail access, to indicate that it is willing to reduce its transmission usage if the prices for a multi-hour period are above a specified level. This feature has not been put in practice in any of the bid-based markets operated by ISOs. We seek comments on its merit and any implementation difficulties.
260. The Independent Transmission Provider would consider these transmission scheduling requests in conjunction with bids submitted in its day-ahead energy and ancillary service markets. Based on all of these, the Independent Transmission Provider would accept the set of energy bids and scheduling requests and develop a day-ahead schedule that maximizes the economic value for all market participants. The Independent Transmission Provider would also
261. The Independent Transmission Provider would schedule all requests for transmission service since these users have agreed to pay any applicable congestion charges. The Independent Transmission Provider would also schedule all requested transactions where the transmission usage charge was below the amount the customer indicated it was willing to pay.
262. Customers with Congestion Revenue Rights would receive congestion revenues that help offset any congestion charges paid as part of the transmission usage charge. The amount of the congestion revenues received (and the associated protection against congestion charges) would depend on the specific Congestion Revenue Rights held. A customer holding receipt point-to-delivery point Congestion Revenue Rights for a certain amount of power between a delivery and receipt point that matches its day-ahead transmission schedule would receive congestion revenues that exactly offset its congestion charges, so that its net bill would reflect no congestion charges (although it would be charged for losses).
263. The above process would be used for scheduling transmission service on a daily basis. Some customers, particularly those with Congestion Revenue Rights, may desire to schedule the same exact service over a longer period to save on administrative costs. The Commission seeks comments on whether a customer should be allowed to provide a schedule for multiple days or have a standing scheduling request that would remain in effect until changed by the customer. Any schedule request, once scheduled by the Independent Transmission Provider would become financially binding on the customer at the close of each day's day-ahead market.
264. Transmission service across the border of adjoining Independent Transmission Providers' service areas—from a point of receipt in one service area to a point of delivery in another—requires coordination between the affected Independent Transmission Providers. When transmission congestion exists between a point of receipt and a point of delivery in different service areas, managing the congestion becomes more difficult because more than one Independent Transmission Provider is involved.
265. There are at least two methods for arranging for transmission service across borders—physical reservations (
266. Recently we accepted a prescheduling option for service across borders that was proposed by the New York ISO.
267. When energy is transmitted from a point of receipt to a point of delivery, some of the energy is lost due to resistance on the wires. These transmission losses are a cost of transmission and commonly are recovered on an average cost basis from all transmission customers. As noted earlier, we are proposing that energy prices and the associated transmission usage charges be based on marginal costs, in order to promote economic efficiency. We seek comment on whether transmission losses should be recovered on the basis of the marginal cost of losses or if they should be recovered on the average cost of losses. There are advantages and disadvantages to each approach. Using marginal losses would promote a more efficient use of the transmission system. However, as discussed below, charging marginal losses will collect surplus revenues that must then be returned to transmission customers. On the other hand, the advantage of charging average losses is simplicity. If average losses are charged, the losses collected from customers would equal actual losses. There would be no need to create a mechanism to return surplus losses.
268. For customers purchasing transmission service to complete bilateral transactions, we see value in allowing transmission customers to pay for their assigned losses either in cash or in kind. To pay in cash, the customer would pay the market price for its assigned MWhs of losses, which would be included in the applicable transmission usage charge. Thus, the MWh of energy injected at the point of receipt would equal the MWh withdrawn at the point of delivery. The transmission provider would procure the energy used for losses from its energy market. To pay in kind, the customer would supply energy at the point of receipt in the amount of its assigned losses. Thus, the MWhs injected at the point of receipt would exceed the MWhs at the point of delivery by the amount of the assigned losses, and the customer would pay in cash only the congestion component of
269. We propose that the Independent Transmission Provider be required to run a voluntary, bid-based, security-constrained day-ahead energy market. “Voluntary” means that market participants do not have to buy or sell in the day-ahead energy market. The day-ahead market we are proposing provides customers with additional supply choices. It is not intended to substitute for other longer-term arrangements that customers may use to purchase supplies such as bilateral transactions or use of a customer's own generation. Thus, market participants would be able to schedule bilateral transactions and/or their own generation rather than bid into the day-ahead energy market. “Bid-based” means that participants may submit offers to buy or sell quantities of energy into the market and may specify the prices at which they are willing to transact. This provides an organized and transparent system for the Independent Transmission Provider to determine the marginal cost of relieving transmission congestion. “Security-constrained” means that the Independent Transmission Provider, in the energy auction process, takes account of all system constraints, such as contingency limits, needed for reliable system operations and develops a schedule that does not violate such constraints. This is necessary to ensure that the day-ahead schedule is physically feasible. Otherwise, the Independent Transmission Provider might be required to make additional payments in real time to relieve congestion, which could provide an incentive for market participants to create congestion in the day-ahead market to receive these payments in the real-time market.
270. Each day, the Independent Transmission Provider would accept bids to sell and buy energy for each hour of the following day. Participants desiring to sell or buy energy would submit a bid in a standardized form.
271. Each seller's bid would indicate the amount of power (MW) offered to be sold, the receipt point, and the time period. In addition, each seller would be allowed to submit multi-part bids that separately specify bid prices for start-up, no-load, and energy, as well as technical characteristics such as ramp rates, minimum run times and minimum down times. Allowing suppliers' bids to include these items yields more detailed information that can improve the ability of the grid operator to dispatch suppliers with the lowest total cost. For example, if the supplier were required to submit a one-part bid it would need to include start-up costs in its energy bid, resulting in a higher energy price bid. However, a supplier submitting a bid that separately specified the energy bid and the start-up costs would not have to make these estimates and the grid operator would use the bids to dispatch the supplier with the lowest total cost. Suppliers would also be allowed to submit bids that are self-schedules, that is, that would indicate an amount to be supplied at a location regardless of the applicable energy price. The supplier would receive the applicable market clearing price for its energy. This option may be useful for suppliers with very high start-up costs such as nuclear facilities. Intermittent resources would be able to participate in the day-ahead market on the same basis as other resources.
272. Similarly, each buyer's bid would indicate the desired amount of power (MW) to be bought, the delivery point, and the time period. In addition, each buyer would be allowed to specify bid prices that indicate the quantities it is willing to purchase at alternative prices. Buyers would also be allowed to submit multi-part bids that indicate the time and price constraints under which they are willing to purchase energy. These options would facilitate demand response programs because they allow the buyer to indicate the price at which it will voluntarily reduce its consumption. Buyers would also be allowed to schedule an amount to be purchased regardless of the applicable energy price.
273. Buyers and sellers would be able to submit different price bids for different hours of the day, and bids could vary from day to day. However, if market participants can exercise market power, limits may be imposed on bidding to mitigate market power, as discussed below in the section addressing market power monitoring and mitigation.
274. We propose a scheduling option to address the special conditions facing energy-limited resources such as hydroelectric and environmentally constrained thermal resources. These resources are limited in the amount of energy or the number of hours that they can produce energy over a period of time. As a result, production in one hour may reduce the amount of energy that the resource can produce (and the associated revenue) in other hours. Energy-limited suppliers could submit bids in the day-ahead market that specify the amount of energy, or the number of hours, available for production over the next day. The supplier could then request the Independent Transmission Provider to schedule its energy in those hours of the next day when the energy price is highest. Such a scheduling feature would promote efficient scheduling because it would allow the energy-limited resource to be scheduled where its energy would have the greatest value, with maximum profit to the resource owner.
275. We recognize that intermittent resources such as wind power may also benefit from scheduling rules that recognize their inability to precisely control output. We recently approved a special mechanism for intermittent resources selling into the energy market run by the California ISO.
276. Finally, in drafting the bidding and scheduling rules we have included several ways for demand to respond to prices. We recognize that several ISOs currently have demand response programs that operate differently. Under these demand response programs, the ISO pays end-users to reduce their demand if market clearing prices reach a certain level. We believe the direct approach of letting demand bid in the market will be less costly than a program where an end-user receives payments greater than the market clearing price to reduce its demand. We have not proposed to include these types of programs in the
277. Based on the accepted bids included in the day-ahead schedule, the Independent Transmission Provider would establish day-ahead locational energy prices for each hour. The hourly energy price at each location would reflect the marginal cost (as reflected in bids) of producing and delivering energy to that location in that hour. Energy prices would be consistent with the transmission usage charges, so the difference in energy prices between two locations in an hour would reflect the cost of transmitting energy from one location to the other.
278. The Independent Transmission Provider would establish a single market-clearing energy price for each hour for each node on its transmission system. We believe it is important that energy prices be calculated for each node to avoid socialization of congestion costs and to reduce the possibility of manipulating the congestion management system.
279. Upon request of market participants, the Independent Transmission Provider would establish trading hubs. A trading hub is a virtual location where financial transactions may be arranged, whose hub price is the weighted average of energy prices at a specified set of nodes on the transmission system. A trading hub facilitates financial trading and aggregation of supplies from multiple sources. Creation of trading hubs should not lead to socialization of congestion costs, because the price for service at the trading hub is the weighted average of prices at the various nodes that are included in the trading hub. Energy may not be injected or withdrawn from the grid at a trading hub, since a hub does not exist at a physical location. But a hub may be named as an intermediate point between physical points of injection and withdrawal where financial energy trades may occur.
280. Each buyer and seller would transact at the applicable clearing price for the hour and time period. A seller that submits separate bids for start-up and no-load costs and is dispatched by the Independent Transmission Provider for any period during the day, will be assured that it will recover the start-up and no-load costs that it bid. If a seller's total bid costs (including start-up and no-load costs, as well as energy running costs) over the entire day are not fully covered by its revenues from selling at the hourly clearing prices, it would receive an additional payment (
281. The results of the day-ahead market would be financially binding on buyers and sellers. That is, sellers would be paid the applicable locational day-ahead price for energy scheduled to be sold in the day-ahead market, and buyers would pay the applicable locational day-ahead price for energy scheduled to be bought in the day-ahead market. In addition, to the extent sellers and buyers fail to actually produce or take energy according to their respective schedules in real time, such imbalances would be settled at the applicable real-time energy price. Thus, a seller would pay the real-time LMP nodal price for any scheduled energy that it fails to deliver in real time to its bid delivery point. Similarly, a buyer would be paid the applicable LMP nodal real-time price for any scheduled energy that it does not take at its bid receipt point in real time.
282. The Independent Transmission Provider would post prices and other market information and settle the markets promptly to provide market participants with reliable information regarding their market transactions.
283. In certain instances, a generator may alleviate a voltage or stability constraint by producing real power and/or reactive power at its location. By alleviating the constraint, the transfer capability of the grid may be increased, thereby allowing a greater amount of lower-cost energy to be transmitted to an area with higher energy prices. For example, the transmission capability to import power into a load pocket may initially be limited to 1000 MW due to a voltage or stability constraint, even though the thermal limit is 1500 MW. However, production of an additional 100 MW of real power and/or an additional amount of reactive power within the load pocket could increase import capability into the load pocket by 50 MW, to 1050 MW. We seek comment on whether generators who provide such real or reactive power should receive additional compensation (in addition to the locational market price for energy and the applicable compensation for reactive power) for the additional transfer capability that they create, to provide incentives to produce energy that increases transfer capability. For example, should such generators be given the Congestion Revenue Rights with the additional transfer capability that they create? In certain circumstances, a generator must reduce its production of real power in order to increase its production of reactive power. In these circumstances, should the generator be compensated for the opportunity cost of its reduced profits from selling real power? Should the generator be paid the higher of its opportunity costs or the market congestion value of the additional transfer capability created? How should locational market power concerns be addressed in these circumstances?
284. Order No. 888 identified six ancillary services. Under this proposed rule, all six ancillary services must be provided by the Independent Transmission Provider, but the three listed below need not be obtained from the Independent Transmission Provider:
(1) Regulation and frequency response
(2) Operating reserve—spinning
(3) Operating reserve—supplemental
Transmission customers may meet their responsibility through self-supply, by procuring these ancillary services from a third party, or by acquiring them from the Independent Transmission Provider.
285. As discussed earlier, imbalance energy would be provided through the day-ahead and real-time energy markets. For the remaining three ancillary services (regulation and both operating reserves), we propose to require that the Independent Transmission Providers operate bid-based markets open to all potential suppliers so that Independent Transmission Providers can procure these ancillary services from the lowest cost suppliers. Different regional reliability authorities may establish different requirements for operating reserve—supplemental. For example, the four jurisdictional operating ISOs procure resources for the ancillary service operating reserve—supplemental (which are usually generation resources that are not synchronized with the grid or demand-side resources that can curtail use), with varying response times. Each ISO procures a portion of their necessary operating reserve—supplemental requirement with reserves that can respond within 10 minutes of a dispatch request, as well as slower-responding reserves at 30 minutes (New York ISO and ISO-New England) and 60 minutes (California). Since different regional reliability authorities have established different response times for operating reserve—supplemental, we do not propose a standard set of markets for operating reserve—supplemental. However, we propose to require that each Independent Transmission Provider operate separate markets for each type of operating reserve—supplemental that it procures.
286. Location-specific reserve targets may be required in some areas due to persistent and significant congestion. The Independent Transmission Provider would identify and establish these targets consistent with any reliability rules.
287. Each day, the Independent Transmission Provider would determine the total amount of each of the ancillary services that will be required for each hour of the following day. Customers that wish to meet their ancillary service requirement through self-supply or procurement through a third party would be required to provide the Independent Transmission Provider with the necessary information about the generation capacity or demand-side resource that would be providing the ancillary services (as is currently required under the existing
288. To procure the remaining amount of ancillary services, the Independent Transmission Provider would accept bids for regulation and the types of operating reserves for each hour of the following day. A participant desiring to sell regulation or operating reserves would submit a bid in a standardized form specified by the Independent Transmission Provider. Bids could be offered to provide ancillary services from generation capacity or any demand-side resource that meets the technical requirements of the ancillary service. Participants could offer the same capacity in more than one ancillary service market, as well as in the energy market.
289. Each bid would indicate the type of ancillary service, the amount of generating capacity (MW) offered for sale, the receipt point of the resource and the time period. The bid would also include an availability bid indicating the minimum price per MW (which could be either a positive amount or zero) required to provide the ancillary service. The availability bid would allow the bidder to ensure that it would not be selected to provide the ancillary service unless the ancillary service price is high enough to cover out-of-pocket costs, such as the costs of keeping a crew at its facility for the following day. The bid would also include the various components that would be submitted to
290. The Independent Transmission Provider would consider all bids to sell ancillary services, in conjunction with bids submitted in its day-ahead markets for energy and transmission service. As noted earlier, based on all submitted bids, the Independent Transmission Provider would maximize the economic value (as reflected in the bids) of the accepted bids,
291. Based on the accepted bids included in the day-ahead schedule, the Independent Transmission Provider would establish day-ahead prices for each of the ancillary services procured in the bid-based markets for each hour. In regions with separate locational ancillary service requirements, the Independent Transmission Provider would establish separate hourly locational ancillary services prices.
292. To promote an efficient market, the price for regulation and operating reserves services would equal the marginal cost of each service, which would equal the highest accepted total bid cost expressed in dollars per MW. The total bid cost of each generator is the sum of: (1) The generator's availability bid per MW and (2) the opportunity cost of forgoing sales in other markets operated by the Independent Transmission Provider, expressed on a per-MW basis.
293. A generator or demand-side resource could be eligible to bid into more than one market operated by the Independent Transmission Provider. The opportunity costs paid to the supplier would be the forgone profit from the most profitable other market. For example, a generator that is capable of providing ancillary services could also sell into the transmission provider's day-ahead energy market, although it would incur additional variable energy costs to do so. Thus, the forgone profit from selling into the energy market (as reflected in the generator's bid) would be the difference between the energy price and the generator's energy bid. The opportunity cost of selling ancillary services would include this forgone energy profit.
294. The hourly price for one of these ancillary services in a given location would thus equal the sum of the opportunity cost and the availability bid in dollars per MW of the most expensive unit accepted to provide that type of ancillary service in that hour to that location. As noted above, a generator providing any ancillary service is also technically capable of providing a slower response ancillary service. For example, a generator providing operating reserve—spinning could also provide operating reserve—supplemental. Thus the opportunity cost of providing operating reserves—spinning would be at least as high as the price of operating reserve—supplemental. As a result, the marginal cost (and thus, the price) of operating reserve—spinning would not be less than the price of operating reserve—supplemental in the same hour.
295. Although suppliers bid to provide these ancillary services in the day-ahead market, customers pay for them based on real-time load. Transmission customers would be assessed a
296. In Order No. 888, exports are not charged for these ancillary services. We ask for comments on whether they should be charged here.
297. Customers that want to self-provide or procure their own ancillary services would be required to notify the Independent Transmission Provider in the day-ahead scheduling process and identify the resources that would be used to provide these services. Customers would be given credit for the amount of ancillary services that they self-provide or procure from third parties. Customers that self-provide or procure from third parties more capacity than their requirements would be paid the applicable hourly ancillary service price for the excess if needed by the market.
298. The Independent Transmission Provider will use the day-ahead market to develop prices and a schedule for suppliers. The prices and schedules will be based on the bids submitted by buyers and sellers. However, the day-ahead schedule may be less than the forecasted load in real time and, if so, the Independent Transmission Provider would commit additional units to ensure that load can be met reliably in real time.
299. After the Independent Transmission Provider has established a day-ahead schedule and associated prices for energy, transmission service and ancillary services, it would make its own forecast of load within its market area for each hour of the following day. To the extent that its forecasted load exceeds the amount of energy scheduled to be delivered to load in the day-ahead schedule, the Independent Transmission Provider may need to procure additional reserves (called “replacement” reserves) from generators to make up the difference, but only to
300. To procure replacement reserves, the Independent Transmission Provider would accept bids from generators submitted for the day-ahead market. The Independent Transmission Provider would select generators to provide replacement reserves so as to minimize the costs of availability, start-up costs and no-load costs regardless of energy costs. This approach to procuring replacement reserves would provide an incentive for load to accurately bid its load in the day-ahead market since energy prices may be higher in the real-time market.
301. As discussed further in the next section, generators selected to provide replacement reserves would be included in the real-time energy bid stack along with other generators that submit bids into the real-time market to provide energy. Generators selected to provide replacement reserves would be paid the applicable real-time energy price for energy that they produce. If a generator's revenues received from selling real-time energy are less than its bids for availability, start-up, no-load and energy, the Independent Transmission Provider would pay the generator an additional payment (
302. We propose to add a new Section G.2 to the
303. A market participant that has not scheduled transmission service in the day-ahead market but desires transmission service in real time must inform the Independent Transmission Provider within specific time deadlines before real time. Market participants may change their day-ahead transmission service schedule by informing the Independent Transmission Provider consistent with the time deadlines.
304. Participants that have informed the Independent Transmission Provider of their desired changes within the Independent Transmission Provider's lead times, and adhere to the requested changes in real time, would settle the changes in transmission service at the applicable real-time transmission usage prices, described more fully below. Participants with new or increased transmission service would be charged the applicable real-time transmission usage price between the applicable receipt and delivery points for the new or increased transmission service in the applicable hour. Conversely, participants that reduce transmission service in real time (compared to the day-ahead schedule) would be paid the applicable hourly real-time transmission usage price for the applicable receipt and delivery points, to compensate them for the additional transmission capacity they have made available in real time.
305. Under Standard Market Design, the Independent Transmission Provider would be required to operate bid-based, security-constrained real-time markets for transmission service, energy, and certain ancillary services (
306. Under the Standard Market Design, the Independent Transmission Provider would accept bids to buy and sell energy in each hour in the real-time energy market. The bids would be in the standardized form specified by the Independent Transmission Provider. Real-time energy markets would be used to provide the energy imbalance service of Order No. 888
307. In general, bids would indicate an offer to depart in real time from the bidder's day-ahead schedule to purchase or sell energy (including a day-ahead schedule to purchase or sell 0 MWhs of energy). Real-time bids would be accepted from any market participant, including generators, load-serving entities, eligible retail buyers, marketers and other agents. Bids would indicate the increase or decrease (in MWhs) from the day-ahead schedule in the amount of energy to be sold or purchased in real time, and the location and the hour of the changed purchase or sale. Each participant bidding into the real-time energy market would be allowed to include multi-part price bids similar to those allowed in the day-ahead energy market (this is a departure from the Working Paper).
308. The transactions in real time vary from those reflected in the day-ahead schedule due to a variety of factors, including changes in weather conditions and unexpected equipment outages. The Independent Transmission Provider may be informed in advance of some of the scheduling departures under the procedures described above; other departures may occur without warning.
309. As occurs today, an Independent Transmission Provider will have to adjust energy production and/or load at various locations in order to balance generation with load and manage congestion. Under Standard Market Design, the Independent Transmission Provider would make these adjustments by calling upon participants that have submitted bids into the real-time energy market, as well as participants that have been selected to provide spinning, supplemental, and replacement reserves. The Independent Transmission Provider would issue dispatch instructions to bidders so as to balance generation and load, and efficiently manage congestion of demand and supply.
310. The Independent Transmission Provider would determine energy prices in the real-time energy market for each node for each 5-minute period or other subhourly period where a 5-minute determination is not technically achievable. Each price would reflect the marginal cost (as reflected in the real-time supply and demand bids) of producing energy and delivering it to the node in that period. The Independent Transmission Provider would post prices and other market information and settle the markets promptly to give market participants reliable information regarding their market transactions.
311. To promote efficient participant decisions regarding real-time transactions, we propose that all departures in real time from the day-ahead schedule be settled through the real-time market at the applicable price (as is done today in many markets). Nodal pricing would be used for both buyers and sellers in the real-time market.
312. There are several aspects of the design of the real-time energy market where we seek additional comments.
313. This Section discusses how to determine real-time energy prices. The options are to set the prices using near
314. Alternatively, an
315. We propose to adopt the
316. We seek comment on whether market participants should face additional charges for “uninstructed” deviations in real time from their schedules,
317. Strictly speaking, the marginal cost of meeting a small increment of load would be based on the bids of suppliers whose output can be increased, or buyers whose load can be decreased, from their scheduled level in the hour by as little as 1 MW. Thus, for example, the marginal cost of supplying load in an hour would not be based on the bid of any generator that is operating in the hour solely because of a minimum run constraint, because changes in load would not change the output of the generator.
318. However, we are concerned that by excluding generators whose output is adjustable in increments greater than 1 MW, on an hourly basis, from setting the energy price may not promote efficient results.
319. We seek comment on whether such lumpy generators should also be eligible to set the energy price in the day-ahead market. Although allowing these lumpy generators to set the energy price may have more direct benefit in the real-time market, we are concerned about potential negative ramifications from establishing different pricing rules for the day-ahead and real-time markets.
320. As discussed earlier, Order No. 888 requires transmission providers to offer to provide to transmission customers energy imbalance service, regulation and frequency response, operating reserve—spinning and operating reserve—supplemental. Under Standard Market Design, energy
321. We propose that the Independent Transmission Provider operate a real-time ancillary services market to accommodate adjustments in the supply of ancillary services from the day-ahead schedule. In real time, there may be entities that can provide ancillary services more efficiently than those that were scheduled in the day-ahead market. The real-time market would permit such efficient substitutions. Higher-cost suppliers scheduled in the day-ahead market would buy back their offer to provide ancillary services at the applicable real-time price, and other, lower-cost entities would be paid the real-time price to take over the supply of ancillary services. In addition, the Independent Transmission Provider may need an amount of ancillary services that differs from the amounts procured in the day-ahead market, for several reasons. For example, the requirements expected in the day-ahead market may differ from actual, real-time requirements, or participants scheduled to provide ancillary services may experience outages in real time. Under Standard Market Design, the Independent Transmission Provider would procure any additional ancillary services needed in real time through the real-time ancillary service markets that it operates.
322. In the real-time market, the Independent Transmission Provider would accept bids for each ancillary service. As in the day-ahead market, a participant could offer the same capacity in more than one ancillary service market. The real-time bids would contain the same types of information as those submitted into the day-ahead ancillary service markets, with one exception—we propose to exclude availability bids for spinning reserves and supplemental reserves in real time. The types of costs reflected in the availability bid to ensure that the supplier will be available to provide these reserves are incurred in the day-ahead time frame, not in real time.
323. The Independent Transmission Provider would consider all bids to sell ancillary services in real time and select those bids that minimize the overall cost of procuring additional ancillary services required in real time.
324. Based on the bids accepted in the real-time market, the Independent Transmission Provider would establish real-time ancillary service prices for each hour that reflect the marginal cost of each service. All participants supplying a given type of ancillary service in a given hour in real time (and to a given location, if there are locational ancillary service requirements) would be paid the applicable market clearing price.
325. Transmission customers that have not self-supplied or procured through third parties their full assigned ancillary service requirement would be assessed a
326. We believe the market rules discussed above in combination with the market mitigation measures and the resource adequacy requirement will result in an efficient system for matching supply and demand under most operating conditions. However, we recognize that when emergency situations do occur, changes may be needed to the market rules to comply with reliability requirements. In the event of a capacity shortage or emergency, local reliability rules and procedures (which typically combine NERC, regional reliability council and system operator guidelines) prescribe a series of actions that the system operator takes to maintain reliability. For example, procurement of reserves is reduced, typically in order of reserve quality (that is, supplemental reserve quantities are reduced before spinning reserve quantities). The system may be re-dispatched to adjust the location and responsiveness of remaining reserves. System operators have also traditionally called on emergency supplies from neighboring systems (in the past, these emergency purchases have taken place at pre-defined prices; increasingly, they are being made at market prices). Finally, steps are taken for voluntary and involuntary load-shedding. States typically approve in advance the retail curtailment plans of utilities.
327. In the markets proposed in the SMD Tariff, we envision that with more extensive demand-side participation, the potential for these types of capacity shortage or emergency situations will substantially diminish. However, system emergencies may occur. The existing
328. The existing
329. But more changes are needed to further the development of regional competitive wholesale electric markets and assure comparable and non-discriminatory treatment of all market participants. Accordingly, the following revisions must be made to the
330. Capacity Benefit Margin is the set-aside of transmission capability by a transmission provider to ensure the ability to import external resources to meet generation reliability requirements or in case of a generation capacity deficiency. During the Commission's outreach process, many commenters asserted that Capacity Benefit Margin ties up valuable transfer capability without a specific reservation and payment by the customers who receive the benefit of the set-aside. The subsidy occurs because, while part of the transfer capability is withheld from the market as Capacity Benefit Margin, the wholesale transmission customers using the system pay the entire transmission cost (including that of the Capacity Benefit Margin) through their transmission charges, thus subsidizing the Capacity Benefit Margin beneficiaries. The use of a Capacity Benefit Margin has also been regularly challenged on the grounds that the host transmission provider is withholding transfer capability under the guise of Capacity Benefit Margin in order to thwart competition.
331. We propose to standardize the treatment of Capacity Benefit Margin to ensure that (1) only customers benefitting from it pay for it, and (2) transfer capability needed to access resources on a neighboring system is treated consistent with all other portions of the transmission grid. Thus, an Independent Transmission Provider itself would not be permitted to set aside transfer capability for generation reliability reasons. Rather, a load-serving entity wanting access to resources on a neighboring transmission system to meet its resource adequacy requirement should instead acquire Congestion Revenue Rights from the interface to its load to ensure that access. This will free up transfer capability now unavailable to wholesale transmission customers and prevent cross-subsidization of transmission customers that serve load within the Independent Transmission Provider's service area by point-to-point transmission system users.
332. This prohibition of the generic set-aside of transfer capability by the Independent Transmission Provider for generation reliability reasons does not apply to an Independent Transmission Provider's responsibility to set aside transfer capability to ensure transmission reliability (
333. The Commission has found specific instances of abuse by transmission providers regarding the Available Transfer Capability calculation process and delays in the completion of transmission facilities studies.
334. More broadly, the SMD Tariff must recognize the regional nature of today's energy markets. Transmission capabilities must be calculated not for a single utility's service territory, but regionally to encompass existing trading patterns and power flows, particularly parallel path flows on neighboring systems. All transmission providers that are not part of a Commission-approved RTO must contract with an independent entity to perform transmission capability calculations on a regional basis. Likewise, we propose to require a common OASIS for the region.
335. Competitive and reliable regional power markets require adequate transmission infrastructure to allow geographically broad supply choices and minimize the complications created by loop flow. The recent DOE National Grid Study documented the problems resulting from recent under-investment in transmission infrastructure and identified a number of causes. Among the causes were the lack of regional planning and coordination of transmission needs and siting issues.
336. Transmission planning and expansion have generally been performed for a single control area rather than on a regional basis. This yields sub-optimal solutions, as individual transmission providers consider power flows across a limited area and do not adequately consider entire markets. Parallel path flows that occur on neighboring systems may make the construction of specific facilities less cost-effective than a regional solution. This effect can be properly considered by performing transmission planning and expansion on a regional basis. Moreover, facilities that, if constructed in one system would be the optimal solution for a neighboring system, might never be considered under a single control area-based planning model.
337. Implementation of Standard Market Design will only increase the importance of examining these issues on a regional basis. More open and transparent markets will enable customers to purchase from distant suppliers, increasing use of the grid. Locational marginal prices that result from the spot markets operated by an Independent Transmission Provider would signal to all market participants the value of additional supply and demand response at particular locations. Based on these prices over time, market participants will be able to decide whether additional investment—in transmission or generation facilities or demand response—is warranted. The ability of individual market participants to see the economics of possible solutions and make market-driven decisions concerning the addition of infrastructure is the fundamental mechanism that induces efficient investment under Standard Market Design. The policy relies primarily on a “ground-up” planning process that encourages construction by private companies yet also recognizes the need for a regional evaluation process for loop flow effects and cost-effectiveness. It is neutral with respect to the type of investment market participants may make in response to these price signals. However, due to loop flow, all system modifications would need to be coordinated through a regional process and would have to meet any criteria needed to maintain reliability and stability, and assure that existing customer rights are not impaired.
338. Given the need for transmission investment in much of the country and the time it will take to implement Standard Market Design and for
339. A critical piece of the transmission planning process is state-level siting decisions. We note a recent National Governors' Association report that recommends Multi-State Entities to facilitate regional transmission planning decisions.
340. Certain areas of the country and organizations already have proposals or processes to consider regional planning or development of regional markets. Building off of these existing efforts will help facilitate the development of a regional planning process in the near term. We emphasize that a planning area need not coincide with the geographic area of a Commission-approved RTO or Independent Transmission Provider required by this rule. Also, because of the interrelationships between Canadian and U.S. energy markets, we encourage participation by Canadian entities and provincial authorities in the regional planning process.
341. Current processes such as the Committee on Regional Electric Power Cooperation in the West provide for state and provincial advice in the planning across the entire Western grid. Therefore, we propose to use the area covered by Western Electricity Coordinating Council (WECC) that encompasses the geographic area covered by the Western Grid for regional planning purposes.
342. In the Eastern Interconnection there have been several efforts at developing regional wholesale electricity markets that we propose to build on for the regional planning process. PJM and MISO developed a Memorandum of Cooperation dated May 9, 2002 that commits to develop a joint and common wholesale electric market for PJM, MISO, and SPP. Consequently, we propose that the area covered by these organizations would also be a regional planning area.
343. Similarly, New York ISO and ISO-New England are currently pursuing discussions on the merger of these two organizations into a Northeast RTO. Both are also members of the Northeast Power Coordinating Council which has recently conducted studies of transmission needs in the region.
344. Finally, we recognize that there has been ongoing discussion development of regional markets in the Southeast. SETrans Regional Transmission Organization proposes to encompass a broad area in the Southeast. The Tennessee Valley Authority (TVA) has signed a Memorandum of Understanding with Southern Companies and Entergy, two sponsors of SETrans, to work together to develop coordination agreements. Additionally, the SETrans and GridSouth Transco, LLC parties signed a Memorandum of Understanding in January 2002 calling for similar regional coordination. Thus we propose to build on these efforts and propose a Southeast planning area composed of the Southeastern Electric Reliability Council and the Florida Reliability Coordinating Council.
345. We propose that all public utilities that own, control, or operate transmission facilities must participate in a regional planning process for the planning areas discussed above. We propose that this process start within six months after the effective date of the Final Rule and that the first regional transmission plan be completed within twelve months after the effective date of the Final Rule. Reliance on these existing regional efforts should facilitate the start-up of the regional planning process before Standard Market Design is implemented and all areas have Independent Transmission Providers operating transmission facilities.
346. After Standard Market Design is fully implemented, we believe the regional planning process will change as Independent Transmission Providers play a greater role in that process. There will still remain a significant need for a regional planning process to supplement private “ground up” investment decisions. The regional planning process is intended to supplement these private investment decisions, not supplant them. The regional planning process must provide a review of all proposed projects to assess whether the project would create loop flow issues that must be resolved on a regional basis. In addition, because of the externalities involved, there may be no private investment sponsor for some projects that would benefit the region. Private investment decisions in response to prices may not result in adequate expansions for two reasons. First, private parties may not be eligible to ask the state to exercise its eminent domain rights. Second, some needed and beneficial expansions may not create enough identifiable financial benefits to compensate private investors adequately, so those projects will not be built under a system that relies solely on private investment to expand the grid. A regional planning process can identify both the projects that would benefit the planning area and potential alternatives in a fair and unbiased manner. Additionally, a regional planning process, would evaluate the benefits of alternative proposals and provide an independent assessment of which projects are the most cost effective and/or have the least environmental impact.
347. To complement private investment initiatives, we propose that Independent Transmission Providers establish a mechanism for regional transmission planning and expansion guided by the following principles. First, the planning process should identify all expansion needs on the system, including both reliability and economic needs (
348. Second, an Independent Transmission Provider should have the responsibility to issue requests for proposals when the planning process determines that additional resources are needed to serve the regional market. Parties may respond with proposals to expand the grid, add generation (including distributed generation), or
349. Finally, the Independent Transmission Provider would act as a clearinghouse for proposed projects. It could identify separate projects that could be constructed at a lower cost if the projects were combined. Also, if there are alternative projects that have been proposed, the Independent Transmission Provider could evaluate the relative advantages of the alternative projects.
350. This approach to regional planning and expansion is fully consistent with Standard Market Design's goal of inducing efficient investment by relying primarily on price signals and independently administered Congestion Revenue Rights. At the same time, it recognizes that private investment decisions may not be fully adequate in all cases because of eminent domain and the possibility that private benefits of investment could be significantly less than social benefits. The planning process would have a regional scope, permit direct competition among all types of investment, include all market participants equally, and minimize the need to rely on eminent domain and the support of captive customers. Because existing transmission owners are the transmission builder of last resort, it also respects the reality that not all states allow non-traditional utilities to build in their state or to obtain eminent domain, thus creating a legal barrier to entry.
351. Software and data issues have become an important part of the market design and changes to market design. On many occasions over the past several years, market designs and improvements have been delayed or even abandoned due to software constraints or software development costs. Software and data systems inherited from the old structure are often idiosyncratic, making changes and seams issues more difficult than they should be. Market participants often find software to be impenetrable “black boxes.” Software development and modifications have become expensive and software “wheels” are being reinvented. Consequently, the software used to implement the Standard Market Design's real-time and day-ahead markets will be a critical element in the feasibility and success of Standard Market Design.
352. The Standard Market Design software should have the following characteristics: transparency (the ability to understand what the software does), testability (the ability to understand and compare performance) and modularity (the ability to change software modules without changing other software). Transparency, modularity and testability help break down entry barriers and allow for competition in software development. Modularity requires standard interfaces (well-defined data inputs and outputs and ease of access). Since we expect Standard Market Design to evolve over time and wholesale markets to grow, the underlying software must be able to accommodate change. Scalability, security and robustness are desirable design features.
353. All market and operations software approximates the actual operation of the system. However, computational and feasibility issues are not well understood. Issues include performance, AC vs. DC models and consistency if both are used. Unit commitment models use different heuristics that were not important in the old vertical structure, but can be very important for new demand and supply entrants in a decentralized market. To instill confidence in the software, testing, validation and evaluation should be a part of an open process.
354. We propose to require that the software meet the characteristics set forth above and that the input and output data systems and other Electronic Data Interchange be standardized in a common data model including a data dictionary (glossary and/or data definitions) and common network description. We seek comment on the following questions.
355. The Commission held a conference on July 18, 2002, to discuss the operational data and software needed to implement Standard Market Design and large regional wholesale markets, following an earlier conference on software issues. Among the topics discussed were market operational software capabilities, software standardization, ISO experiences with implementing software, cyber-security and the need to achieve some standardization within the electric market and grid operations software modules across vendors.
356. The conference established that for most applications, software does not appear to be a binding constraint on the size of RTOs or the implementation of Standard Market Design. Participants noted that the computational algorithms inside the models are continually improving, as is the speed of the processors used to solve the models, so it is reasonable to expect that software and associated hardware needs should keep pace with market span.
357. The Commission's goal is to assure that the best software is available for use in the nation's wholesale markets. This can best be attained by promoting competition among vendors, in a way that assures that no vendor comes to “own” a market niche or impose barriers to entry by new software companies with innovative analytical approaches.
358. Many vendors have particular areas of expertise and their software is often integrated with other software in complete software systems. We propose to encourage the development of “plug-and-play” software designs so that the best modules can be integrated into complete market operational systems for Independent Transmission Providers. To accomplish this we need to standardize data transfer between modules. Participants at the conference proposed two ways of accomplishing this—open systems and standardization. The open systems approach would leave it to each vendor to develop and publish the interface to the next module in the system. The standardization approach would define a set of minimum specific standard functions for each software module and specify the interfaces to be used between modules. We believe that the standardization approach is best suited to the close time frame needed for Standard Market Design implementation, and invite comment on the best process to develop these standards—should we use the evolving NAESB process or forums set up by the Electric Power Research Institute for this purpose, or use another approach?
359. The discussion of a suite of benchmark problems to test software illustrated the importance of benchmarking to facilitate testing and comparison of candidate software with respect to solution outcomes and processing time. We therefore encourage
360. As a follow-up to the July 18, 2002 Standard Market Design software conference, the Commission will hold another conference on these topics on October 3, 2002. This conference will focus particularly and in detail on what process or body should be used to set standards for data standardization for inputs and outputs to software modules; whether the standards already developed by the Ontario Independent Market Operator for this purpose might be applicable for United States markets;
361. In a variety of public forums, including RTO conferences and comments to RTO proceedings, much uncertainty has been expressed concerning two questions: which facilities belong under the control of the RTO; and which customer-owned transmission facilities that are turned over to RTO control are entitled to a credit?
362. Before Order No. 888, much of the industry consisted of vertically integrated investor-owned utilities (IOUs) that, for the most part, provided a single service—bundled requirements power—to retail and wholesale customers alike. The classification of delivery facilities between transmission and distribution came up only in a ratemaking context. Because wholesale requirements customers purchased bulk power, they often did not require service over distribution facilities. Often, only a stepdown substation or a feeder line was involved. For those few stand-alone transmission services that an IOU might provide, the cost allocation issue was the same. The Commission approached this allocation issue by defining an integrated transmission grid as those facilities that operate in a single cohesive fashion to deliver bulk power and allocating wholesale (and stand-alone transmission customers) a proportional share of the embedded costs of those facilities on a rolled-in basis with postage stamp pricing.
363. Infrequently, the Commission would consider rate treatments premised on the distinction between transmission and subtransmission (high and low voltage transmission). If there were delivery facilities (transmission or distribution) that were not part of the integrated grid, but were used by a specific wholesale customer (
364. These issues were discussed at length in Commission cases in the 1970s when IOUs attempted to bifurcate the pricing (effectively pancaking) and thereby increase their wholesale revenues. Customers, on the other hand, wanted to classify facilities as transmission and thereby decrease their delivered energy charges by only paying one charge for these facilities. While the issue was often framed as a transmission/distribution issue, it was mostly a battle over utilities trying to pancake rates (through charging a rolled-in rate plus a direct assignment charge) for transmission facilities or facilities that provided both transmission and distribution functions (dual-function facilities).
365. Order No. 888 did not require a change in traditional rate treatments. However, since the Commission issued its open access rules, a number of utilities have proposed subclassifications of transmission,
366. The issue of transmission/distribution classification in Order No. 888 was in the context of unbundled retail transmission service and the Federal Power Act's legal jurisdiction distinction between “transmission” facilities (subject to Commission jurisdiction) and “local distribution” facilities (subject to state or local jurisdiction). To determine what facilities would be under Commission jurisdiction for purposes of the Order No. 888 open access requirements and what facilities would remain subject to state jurisdiction for purposes of retail stranded cost adders or other retail regulatory purposes, the Commission developed a seven factor test to determine what facilities are transmission facilities and what facilities are local distribution facilities.
367. Order No. 888's seven factor test was designed to determine the local distribution component of an unbundled retail sale. The test did not exist prior to Order No. 888 and in fact was created to do something the Commission had never done before—identify local (retail) distribution facilities. Thus, the test identifies all facilities that are not local distribution facilities. We propose that this is the appropriate starting point for determining which facilities belong under the control of an Independent Transmission Provider. To the extent that a transmission owner or Independent Transmission Provider
368. This proposed test focuses on the presumption that, if a facility is transmission, it belongs under the control of the Independent Transmission Provider. Thus, once a determination is made with the seven factor test, there would be no need for an additional review under the Commission's previous integrated facilities test. In
Although we are accepting the state commissions' classification, we reiterate our finding in Order No. 888 that to the extent that any facilities, regardless of their original nominal classification, in fact, prove to be used by public utilities to provide transmission service in interstate commerce in order to deliver power and energy to wholesale purchasers, such facilities become subject to this Commission's jurisdiction and review.
Further, our deference in this proceeding does not affect the Commission's separate determination of what facilities must be under the operational control of RTOs, including ISOs and Transcos.
369. We request comment whether, either in addition to or in lieu of the seven factor test, the Commission should use a bright line voltage test (
370. This section discusses the transition process that will be used to move from the existing
371. Standard Market Design is intended to cure undue discrimination, more efficiently use the transmission grid and give customers additional options. To help ensure that the transition process satisfies these objectives, the proposed rule would allow certain regional flexibility in the implementation process to the SMD Tariff. In particular, the regions would have flexibility in converting the rights of existing customers to Congestion Revenue Rights or auction revenues under the new tariff. Also, the regions would have flexibility in establishing the rate design for the new Independent Transmission Providers. It is anticipated that the state representatives, through the Regional State Advisory Committees discussed in Section IV.K., will play an active role in these regional decisions.
372. When the Commission issued Order No. 888 it faced the issue of what to do with existing contracts. The Commission decided that it would not generically abrogate existing requirements and transmission contracts, but that under all post-Order No. 888 contracts were to conform to the Order No. 888
373. Similarly, we propose not to abrogate existing pre-Order No. 888 contracts. On a nationwide basis, these contracts should represent a relatively small portion of the total load and should be able to be accommodated within the Standard Market Design.
374. If pre-Order No. 888 contracts remain in effect, the contracting transmission owner would be required to take service from the Independent Transmission Provider in order to serve its existing wholesale power or
375. The Commission is concerned that pre-Order No. 888 contracts could permit the parties to extend a contract indefinitely through the use of roll-over or evergreen provisions in the contracts. The Commission seeks comment on whether it should limit the ability of the parties to extend these contracts past their initial term, or if that has passed the end of the next roll-over period and, if so, what limitations are appropriate.
376. The initial allocation of Congestion Revenue Rights is important to ensure that the implementation of Standard Market Design preserves the service rights of existing customers, provides access to all available capacity and minimizes cost shifts. We offer a process for this transition. First, the Independent Transmission Provider would compile a catalogue of all the existing long-term firm obligations for its transmission system that would still be in effect when Standard Market Design is implemented.
377. Next, the catalogue of firm obligations would be subject to a simultaneous feasibility test.
378. Either of two methods could ensure that current customers receive the value of their current contracts (actual or implicit)—direct assignment and an auction with a revenue assignment.
379. Alternatively, current firm customers could be given the auction revenues from the sale of Congestion Revenue Rights. Thus, the existing customers would receive the market value of those rights. Under this approach, all of the Congestion Revenue Rights available on the system would be sold through an auction. At a minimum, the Congestion Revenue Rights sold in the initial auction would have to include point-to-point obligations. If there is interest from market participants and it is technically feasible, the auction could also include point-to-point options and flowgate rights.
380. The terms of the Congestion Revenue Rights would vary. Initially, a set percentage would be auctioned on a monthly basis, another set percentage would be auctioned for six months and another for one year. This rulemaking proposes that the regions be given flexibility in setting the initial terms for the Congestion Revenue Rights sold in auctions. Since congestion patterns can change significantly after the implementation of LMP, there may be a benefit to delaying the auction of multi-year Congestion Revenue Rights until after a start-up period. On the other hand, customers may desire long-term Congestion Revenue Rights to correspond to the term of the long-term contracts used to satisfy the long-term resource adequacy requirement. We seek comment on whether we should require long-term Congestion Revenue Rights in such cases. The Congestion Revenue Rights that would be sold during the initial auction would be the set of Congestion Revenue Rights that maximizes the value of the awarded Congestion Revenue Rights based on buyers' bids that is simultaneously feasible. The revenues from the auction would be given to the customers that are paying for the embedded costs of the system through an access charge.
381. In the long-term, the auction methodology has a number of advantages over the allocation methodology in a competitive wholesale market. First, the auction methodology makes it easier for load-serving entities to change receipt points (and thus supply sources) and obtain protection against congestion costs because of the more frequent auctions for Congestion Revenue Rights. The same would also apply to sellers seeking to sell to different buyers. In contrast, if Congestion Revenue Rights are directly assigned, holders of the Congestion Revenue Rights on congested paths may be reluctant to offer these in the secondary market. This could limit the ability of new suppliers to enter the market. This could be problematic particularly with Congestion Revenue Rights held by vertically-integrated utilities. Second, experience to date has been that there is a more vibrant secondary market where Congestion Revenue Rights are auctioned rather than directly assigned.
382. This proposed rule establishes a preference for the auction of Congestion Revenue Rights. After a transition period, all Independent Transmission Providers would be required to auction their Congestion Revenue Rights. However, for an initial transition period of four years, this rulemaking proposes to allow regional flexibility on this issue. During a transition period, the Independent Transmission Provider after consultation with the Regional State Advisory Committee and stakeholders in a region, could decide to directly assign Congestion Revenue Rights. At the end of the transition period, the Independent Transmission Provider would be required to submit a filing to move to an auction for Congestion Revenue Rights with the auction revenues allocated to those that pay the access charge, or justify why a longer transition period is necessary. The customer that previously had been allocated the Congestion Revenue Rights would now receive the auction revenues. The customer could participate in the auction if it wished to retain the Congestion Revenue Rights. We seek comment on whether to allow a transition period before the start of Congestion Revenue Rights auction allocations and, if so, what the length of such a transition should be.
383. In Order No. 888, the Commission included a reciprocity provision in the
384. We propose to continue this approach to reciprocity. Further, we propose to grandfather all reciprocity tariffs that the Commission previously found met the comparability standards of Order No. 888. We request comment on this proposal.
385. In Order No. 888, the Commission recognized that the risk allocations regarding liability and indemnification “must be carefully drafted so that transmission providers and customers can accurately assess and account for their respective risks.”
386. Under the indemnification provision, the transmission customer indemnifies the transmission provider against third-party claims that arise from the performance of obligations under the tariff. The Commission explained that the purpose of the indemnification provision was to allocate the risks of a transaction, and costs of the risks, to the party on whose behalf the transaction was conducted.
387. Since Order No. 888, several entities have sought to revise their open access transmission tariffs to include liability provisions arguing, among other things, that no current federal forum exists for entities that are now subject to Commission jurisdiction only and can no longer seek relief at the state level.
388. We recognize that there may be a need to include liability provisions in the Commission's
389. We seek comment on the following issues: Is there a need to include liability provisions in the Commission's
390. In a structurally competitive market, one with many buyers and sellers who cannot influence price, the market can assure an overall efficient outcome where prices indicate the value of additional supplies and conservation. The development of structurally competitive markets is the Commission's long-term goal. However, at this stage of the industry's evolution, wholesale electric markets are not yet structurally competitive in all respects. The two significant structural flaws are the lack of price-responsive demand and generation concentration in transmission-constrained load pockets. Given these structural defects, the Commission cannot rely on the interaction of supply and demand in all instances to ensure that prices are competitive and thus just and reasonable.
391. Cost-of-service regulation is not effective for spot market pricing of commodities such as electricity. In the past, customers were served by a monopoly supplier under cost-of-service rates, in which the fixed and variable costs of a company's generation portfolio were allocated over the expected hours of service to determine a cost per kWh. But today, the power needs of load-serving entities are met through a mix of sources, including the companies' generation portfolios, and long-term and spot market purchases from a variety of sellers, including independent producers and marketers. These do not match the long-term arrangements needed for cost-of-service regulation. In this competitive context, cost-of-service regulation designed for long-term cost recovery is not well suited for determining appropriate spot market prices. When applied to spot markets, cost-of-service regulation blunts price signals and leads to inefficient investment and consumption decisions which over the long run increase costs for all customers.
392. When markets do not produce competitive outcomes, the Commission must use new regulatory tools to produce just and reasonable results. We propose new market power mitigation measures to deal with the consequences of major structural defects in wholesale electric markets, by approximating the outcomes that a competitive market would produce. These measures should function in markets that are not workably competitive, but not inhibit market operation in more competitive markets. Effective market monitoring and market power mitigation are critical elements of the Commission's plan to create and sustain competitive regional bulk power markets. Therefore, the Commission proposes rules for the spot markets to be operated by the Independent Transmission Provider to mitigate market power.
393. Market power is the ability to raise price above the competitive level.
394. The market power mitigation measures proposed here are designed to address the major structural defects in wholesale electric markets. The major structural defect on the demand side is the lack of price-responsive demand; when customers cannot respond to high prices by lowering their consumption, they cannot discipline price increases from suppliers. Absent demand response, market prices will reflect
395. On the supply-side, structural problems tend to be more location-specific and time-dependent. For example, binding and sometimes unpredictable transmission constraints may restrict competitive alternatives and create opportunities for some sellers to increase prices above a competitive level, at least for any seller that knows some of its output will be required to meet load reliably. This problem is often described as a load pocket problem. In some load pockets, a specific generator may be identified as needed for reliability, which gives it a local monopoly.
396. To be effective, market power mitigation measures must be applied before the fact, since remedies after the withholding has occurred are disruptive to the market and increase regulatory risk to its participants, which increases costs to customers.
397. In sum, the challenge in developing an effective market power mitigation plan is to design a plan that allows markets to function where they are competitive and, where they are not, uses market mechanisms to facilitate the transition to competitive markets. Market mechanisms can be used to approximate the outcomes that a competitive market would produce to provide the price signals for efficient investment and demand response. Because of the characteristics of electricity (it can be stored only in limited instances—pumped storage, compressed air, batteries) and the electric grid (flows follow the path of least resistance), even in regions where markets are generally competitive, transmission constraints may create non-competitive conditions during certain hours. In addition, when market power exists, the market power mitigation plan should be calibrated so that it does not inefficiently suppress prices, or mask scarcity prices, providing the wrong economic signals for efficient investment or demand response.
398. The Commission proposes a market power mitigation plan composed of three mandatory components that are specifically tailored to the structural flaws in the wholesale electric markets and a voluntary fourth measure that could apply in unusual market conditions to assure that the high prices are not the result of market power.
399. The first measure addresses the local market power problem and is similar in concept to the reliability must run agreements that exist in the ISOs today. The market monitor will identify certain conditions in which certain generators are in concentrated geographic markets created by transmission congestion or reliability needs of the grid. These would include units needed to run to support the reliable operation of the grid or a set of units owned by a small number of companies. At those times, those units will have localized market power so that when they are required to provide their energy or ancillary services to the grid their bids into the market should be capped.
400. The second component, a safety-net bid cap such as the $1000 per megawatt-hour cap currently used in Northeast markets and Texas, addresses the lack of price-responsive demand. Sellers could freely offer any amount of energy to the spot markets constrained only by the safety-net bid cap. The safety-net bid cap should allow markets to produce prices that reflect some (and perhaps a significant) amount of scarcity when shortages of reserves or power exist. But absent demand response, it sets an outer bound on suppliers' ability to exercise economic withholding.
401. The third component of the market power mitigation plan is the resource adequacy requirement discussed in Section J. The resource adequacy requirement does not directly prevent withholding, but by expanding the resource alternatives it diminishes the incentive and the ability of suppliers to practice and profit from either physical or economic withholding.
402. While it is clear that the first three measures must be part of the Standard Market Design market power mitigation plan, there may be market conditions in which a fourth measure is needed. The fourth mitigation measure would deal with situations when non-competitive conditions may exist, by examining and possibly limiting bids from individual suppliers into the day-ahead and real-time spot markets if those bids are high due to withholding rather than scarcity. Exercise of this mitigation could be triggered by predetermined conditions or triggers (such as a sustained period of prices significantly above competitive levels), or by significant infrastructure problems in the market (
403. The implementation of the market power mitigation plan summarized above and described in more detail below will rely on the results of an initial competitive market analysis by the Independent Transmission Provider's market monitor in each region. This will identify at the outset the persistent load pockets or other conditions that create local market power. This analysis will be filed with the Commission as part of the implementation process for Standard Market Design and subject to comment from all interested parties. After Commission review, it will form the basis for the mitigation measures that are applied by the Independent Transmission Provider. It then will be updated annually to review the continuing effectiveness of the market power mitigation.
404. The market power mitigation measures proposed rely principally on mitigating market power in spot markets. Mitigation would only apply to products traded in the spot markets operated by the Independent Transmission Provider, not to products traded under bilateral contracts outside the Independent Transmission Provider's spot markets. This is the least intrusive framework for market power mitigation but at the same time provides very effective protection against market power.
405. Although power and operating reserves purchased in the organized spot market are only a small percentage of total purchases, mitigating the organized spot market is an effective
406. Local market power principally arises either from the concentration of generator ownership within a load pocket, or the need for local units to operate to assure system reliability and stability within the load pocket. Local market power can arise from both persistent and foreseeable congestion, or from sporadic transmission congestion. Although local market power can arise from these different conditions, the mitigation method proposed here can be effective at mitigating the local market power regardless of how it arises.
407. In the existing ISOs in California and the Northeast, participating generator agreements are used to set out the operating terms, conditions and obligations concerning the dispatch of a generating unit, serving principally a reliability purpose. Under the Standard Market Design
408. The participating generator agreements, which would be filed with the Commission, would identify the non-competitive conditions when the generator with local market power would be required to offer its energy either by scheduling a bilateral transaction or by offering all available energy to the spot markets. This would be a must-offer requirement. The requirement would apply when the generator's power is needed to maintain the reliable operation of the grid, and also when there are insufficient competitive alternatives. The participating generator agreement would specify the conditions that would give rise to a generator's must-offer requirement, and would also specify bid caps that would apply when the generator was required to bid into the day-ahead and real-time markets. In non-competitive conditions, the generator's bids could not exceed the capped values. Although the participating generator agreement may restrict a generator's energy and operating reserves bids, the generator would still receive a market-clearing price and additional revenue to cover start-up and no-load costs.
409. In addition to the bid caps specified in the participating generator agreements, local market power also will be limited through bilateral contracts between load-serving entities and the generators. Under the resource adequacy requirement, load-serving entities must have enough resources to meet their demand to ensure the reliability of the grid. It can be expected that some of those resource requirements will need to be fulfilled with contracts with generators within their load pocket to ensure that the resource is deliverable during peak or congested periods. Bilateral contracts are an effective way for a buyer to mitigate the market power of a seller.
410. Under the participating generator agreements, when conditions are not competitive, that is, when there are insufficient alternatives available to meet load in that location, a generator must run to provide all its available capacity to the grid, either by scheduling a bilateral transaction or bidding into the spot market. The need for the generator to be producing could be identified either in the day-ahead market based on projected system conditions or in real time. In the day-ahead market, all available capacity would include all capacity not sold bilaterally and scheduled or on an outage. In the real-time market, all available capacity would include all non-producing capacity (not delivered to the market)
411. The Commission invites comment on how to structure the local market power mitigation, particularly on how to define the noncompetitive conditions which should trigger the mitigation, and on how bid caps should be structured for generators operating under a participating generator agreement.
412. There are some options for dealing with the risk of a forced outage inside a load pocket. One is for a portion of available day-ahead capacity to be exempt from the bid-in requirement to reflect forced outage risk in real time. Another possibility is to allow generators to provide all available capacity in real time at a capped bid in lieu of bidding in the day-ahead market to accommodate generators that have significant risk or opportunity costs. A third option would vary depending on whether the generator receives a reserve capacity payment. If the generator receives a capacity payment, that payment compensates for the outage risk so the generator should be obligated to deliver energy or to pay for substitute supply from some other source. If the generator does not receive a capacity payment, then it should not have to bear the risk for a legitimate outage. Units declaring a forced outage would be subject to audit by the market monitor. If the outage is found to be unjustified, then the generator should be subject to a penalty. The Commission requests comment on the penalty that would be appropriate to deter unjustified forced outages.
413. If bid-in capacity is generally insufficient to meet both operating reserve requirements and load, capacity rights associated with the resource adequacy requirement may be exercised by load-serving entities that have secured sufficient capacity so that they will not be interrupted. However, in this situation, lack of demand response can
Current markets in the Northeast and Texas rely on a $1000 per megawatt-hour bid cap, regardless of market conditions, as a safety-net that may be binding in this situation. The Commission proposes to adopt a safety-net bid cap as part of the market power mitigation plan here. Under this proposal, no bid to supply can exceed this level, regardless of cost or risk or location, even if the market is confronted with a genuine operating reserve shortage. However, if the monitor establishes that some units may provide power at a cost that exceeds the safety-net, a higher price for those units would be justified. In California, for example, imports are not allowed to set the market clearing price. However, in the market power mitigation framework proposed here imports would be allowed to set the market clearing price in order to get a proxy for a scarcity price, up to a capped value. If requirements cannot be satisfied with bid-in imports that would be subject to the safety-net bid cap, then load that has not met its resource adequacy requirement should be penalized as described in the Resource Adequacy section. A safety-net bid cap, such as the $1000 per megawatt-hour cap in the Northeast and Texas, can serve as a proxy scarcity price under Standard Market Design. The Commission requests comment whether the safety-net bid cap should be uniform across an interconnection, so that there would be one cap applicable in the East and another applicable in the West.
414. Comment is requested on how to determine an appropriate value for such a cap. It is important to examine the implicit trade-off between bilateral capacity payments, the safety-net bid cap and local market power mitigation. That is, a bid cap that constrains scarcity prices would be expected to translate into higher bilateral capacity payments under a contract to fulfill the long-term resource adequacy requirement. With a higher safety-net bid cap, perhaps one based on the value of lost load, smaller bilateral capacity payments would be required to maintain the same level of resource adequacy in the absence of price.
415. The Commission proposes a fourth voluntary market power mitigation measure which may be recommended by the market monitor during the Standard Market Design implementation process, or any time thereafter. This measure, if needed, would apply to unanticipated and sustained market conditions that would give the ability and the incentive to exercise market power. For example, extreme supply or demand conditions to which the market cannot quickly adapt, such as the loss of significant hydropower capacity because of drought, or force majeure events such as a major transmission line outage. These kinds of events, which are not transitory, can provide opportunities to exercise market power even in a market that is normally workably competitive. It may be appropriate for other conditions to trigger this mechanism. We seek comment on what these triggers should be. Although market-clearing prices would be expected to rise in these situations, and perhaps sharply and significantly, it may be important for the market to have the assurance that the price increases are attributable to the extreme circumstances and not to the exercise of market power. An AMP mechanism such as those approved by the Commission in New York ISO and California could provide this kind of assurance.
416. This kind of mechanism may not be necessary in every region. If a market monitor proposes such a mechanism, the proposal must include the specific triggers that would be used to initiate this form of market power mitigation along with the details of the mitigation method. Since this form of market power mitigation is for temporary market conditions, it will be equally important for the market monitor to indicate the criteria to determine when the market has returned to normal competitive conditions and this market power mitigation method will be suspended.
417. The details of this market power mitigation method, including the triggers, would be set out in the Independent Transmission Provider's tariff. If market conditions developed that satisfied the pre-determined triggers for the mechanism, it would be the market monitor's responsibility to give notice to the public and the Commission that the tariff mechanism had been triggered. The mechanism would then automatically take effect until the conditions developed that satisfied the pre-determined triggers for the suspension of this market power mitigation mechanism. If a market monitor proposes to use this form of market power mitigation, the details of the mechanism and the triggers would be subject to comment by all interested parties, and review by the Commission.
418. The mitigation for local market power, through the participating generator agreements, relies on must-offer obligations to mitigate physical withholding and bid caps to mitigate economic withholding. Mitigating economic withholding entails determining appropriate bid caps for all bid-in parameters.
419. The development of bid caps, especially for generators with significant opportunity costs such as hydropower and energy-limited units, is difficult and can be controversial. Nevertheless, this mitigation plan would require that each generator, including hydropower and energy-limited units, that may have local market power would need to have an agreement establishing bid caps for all bid-in parameters if its power is needed for the grid or local market power mitigation is necessary.
420. The Commission has approved several options for setting default energy bids that in some circumstances serve as energy bid caps. They include: (1) Default bids based on various averages of previously selected in-merit bids; (2) default bids based on various cost measures, usually a measure of operating cost adjusted for fuel costs;
421. For peaking units that are likely to set market clearing prices when they are dispatched, the must-offer requirement coupled with mitigation that sets bid caps at marginal cost could result in revenues that fail to recover fixed costs over a reasonable period of time. Although such units may recover additional revenue in capacity and reserves markets, bid caps for these units could also reflect a “scarcity” premium or adder to compensate for the lack of price-responsive demand that would otherwise set the price when these units were dispatched. The average cost of a new peaking unit at a given location operated over a given number of hours could form the basis for setting such a premium. This kind of adjustment to bid caps for peaking units could help support reliability until demand-side measures for responding to price were more fully incorporated in markets. The Commission requests comments on whether this approach or other adjustments to bid caps for peaking units might usefully substitute for demand response in the near term.
422. For hydropower and other energy-limited resources much of the difficulty in determining an appropriate energy bid cap for these units comes from the difficulty of assigning a value to their temporal opportunity costs. However, the times when it would be necessary for the transmission provider to call on power from these sources are likely to be times when prices are high and these units would want to be scheduled in any event. At all other times, hydropower units, in particular, should be offering all available capacity as operating reserves since their marginal operating costs are close to zero, but they may have high temporal opportunity costs. In other words, there appears to be no economic reason why such units should not always be fully committed either to the bilateral market or spot markets for operating reserves. Consequently, it appears unnecessary to cap energy bids from such resources below the safety-net bid cap as long as their bids to provide operating reserves were always in-merit. Alternatively, other energy-limited resources might be allowed to submit a bid that states a total megawatt-hour availability over the day and allow the market operator to schedule the power from the unit in the hours when the price is highest. Comment is requested on these and other approaches to establishing reasonable caps for energy bids.
423. Another alternative for hydropower, and other energy-limited resources, would be for the unit operator to submit a seasonal or monthly schedule for when the unit would not be expected to operate. This would enable, for example, hydropower units to specify the periods when they would expect to need to preserve water or flow water to satisfy environmental conditions. While these units have many legitimate competing needs for the water flow, it is still possible for a hydropower generator to engage in physical or economic withholding. In the existing ISOs, generators must submit a schedule for planned outages, which is coordinated by the ISO to ensure that outages occur when they are the least disruptive to the markets. The Independent Transmission Provider is expected to continue to perform this outage coordination function under Standard Market Design. Scheduling outages in advance, coupled with auditing by the market monitor, would provide a way to evaluate whether failures to run were from withholding or legitimate limitations. For hydropower units, for which the marginal costs are primarily opportunity costs, this method may be a sufficient check against withholding so that it might be unnecessary to have a bid cap for these units. The Commission requests comment on these alternatives.
424. Any parameters that a generator may include in its bid may require a cap or other restraint. For example, PJM caps regulation service at $100 per megawatt-hour, and New England uses energy prices to cap prices for spinning reserves. Standard Market Design would also allow availability bids for these products. The participating generator agreements should also contain bid caps for these operating reserves when they are needed for the operation of the transmission system and non-competitive conditions exist. However, the Commission requests comment on how to identify the options for determining competitive bid caps for regulation service and operating reserves, including availability bids, that should be established for day-ahead and real-time markets.
425. In the New York and PJM day-ahead markets, the unit-specific energy bid cap applies to the day-ahead market where separate bids for start-up and no-load costs are also available and would also be available under Standard Market Design. Market power mitigation should also establish caps for these bids and a variety of bid-in operating parameters, such as low and high operating levels and minimum run times, if non-competitive circumstances would permit sellers to manipulate these parameters to get unjustified higher up-lift payments. PJM, for example, does not mitigate the start-up and no-load bids or certain operating parameters, but it only allows units to change these values once every six months. New York permits greater flexibility and uses various screens to assess whether a seller is behaving non-competitively and should be mitigated.
426. Several approaches could be used for establishing bid caps for these particular parameters. One possibility would be to rely on engineering data, such as from the manufacturer about the specific type of unit, to establish caps for start-up and no-load bids and certain operating parameters, and give generators the flexibility to bid within those ranges without mitigation. These ranges would also be included in the generators' participating generator agreements. Just as with energy bids, a bid above the range
427. In the implementation filing, the market monitor would propose tariff language that sets forth the process for setting the bid caps for individual units or any formulas that might be used for this purpose. The market monitor would be responsible for collecting and verifying data from these units to establish appropriate caps for energy bid values consistent with the procedures in the Independent Transmission Provider's tariff. This could be controversial, especially for generators in load pockets that may effectively face “mitigation” in most situations. The Commission requests comment whether the Commission should establish a formula for determining the bid caps or whether the Commission should review the proposals developed in each region.
428. It is appropriate to exempt certain sellers from the market power mitigation. Specifically, sellers who control a small amount of capacity in the market, for example no more than fifty megawatts, would be exempt from mitigation. Sellers with little capacity would have little incentive to exercise market power since a non-competitive bid could eliminate their only unit from the dispatch. However, the Commission requests comment whether any other sellers should be exempt from the mitigation because they have insufficient incentives to withhold.
429. Market monitoring should be conducted on an on-going basis by a market monitoring unit that is autonomous of the Independent Transmission Provider's management and market participants. The market monitoring unit may be located within the offices of the Independent Transmission Provider, to permit easy access to the market data and operations personnel, or it may be physically located elsewhere.
430. The market monitor will be expected to report directly to the Commission, and the independent governing board of the Independent Transmission Provider. This will include reporting at regular intervals on the general performance of the markets in its region and reporting, on a timely basis, observed attempts at market manipulation or factors that impair the efficiency of the market. Although the market monitor will be accountable only to the Commission and the governing board, it should share its analyses and reports with the management of the Independent Transmission Provider and the Regional State Advisory Committee. This will enable the committee to carry out its advisory functions in an informed manner.
431. The market monitor must focus both on the functioning of the markets run by the Independent Transmission Provider as well as the conduct of individual market participants. The market monitor should focus on identifying factors that might contribute to economic inefficiency. Such factors include market design flaws, inefficient market rules, entry barriers to new generation, including distributed generation, barriers to demand-side resources, transmission constraints and market power. In monitoring for exercises of market power, the market monitor should focus principally on detecting economic and physical withholding (as distinct from the normal operation of supply, demand, and true scarcity). For entities that own both transmission and generation assets, withholding behavior could include both generator and transmission outages. For example, instead of directly withholding a generator's power, a market participant with transmission assets could effect the same end by derating a transmission line needed to deliver the generator's power to the market. Monitoring should be designed to detect this kind of behavior.
432. The Commission requests comment on whether the market monitor should also be responsible for monitoring the Independent Transmission Provider's operations, in addition to the markets and the market participants. Specifically, should the market monitor evaluate whether the Independent Transmission Provider treats market participants neutrally, without undue discrimination?
433. To meet its responsibilities, the market monitor must have the ability to collect and evaluate necessary data provided by the Independent Transmission Provider and market participants. The market monitor would have the responsibility to propose to the Commission, and the Independent Transmission Provider's board changes to market rules, if they provide inefficient incentives to market participants, and to promptly identify circumstances that may require additional market power mitigation so that remedies can be put in place prospectively.
434. The work and findings of the market monitor must be integrated into the regional planning process. The market monitor's analysis of the markets will identify load pockets and can help provide direction for needed investment in generation, including distributed generation, demand response capability, and transmission infrastructure to improve the competitive structure of the markets.
435. The Commission proposes here the basic elements of a market monitoring plan to be used by each market monitor. The Commission staff will convene a conference in the Fall to discuss and further develop the essential elements that should be required in a standard market monitoring plan. After getting additional public input at the conference, Staff may propose additional detail for the market monitoring plan, which the Commission may adopt, after an opportunity for public comment.
436. The Commission intends to require the use of a core set of questions and analytical techniques to be used by each market monitor to assess market structure, participant behavior, market design, and market power mitigation. This will facilitate inter-regional comparisons. Examining this core set of issues using techniques reflecting “best practices” would be an essential part of the monitor's responsibilities that allows inter-regional comparisons. However, specifying these core requirements here should not prohibit or discourage monitors from expanding their analyses where regional differences or unanticipated events warrant it. In fact, because markets and monitoring are in a formative stage, the Commission would need to continue to facilitate communication between market monitors to share insights and develop common approaches.
437. An important focus of market monitoring will be structural market
438. Some monitors have estimated whether average generator profitability would cover costs of a gas-fired peaking unit and provide sufficient inducement for entry.
439. The Commission proposes to require each monitor to perform a structural analysis of the region that would include: (1) Market concentration including by type of generation, (2) conditions for entry of new supply, (3) demand response, and (4) transmission constraints and load pockets that give sellers the ability and incentive to exercise market power. This analysis would be performed prior to the implementation of the Standard Market Design, in order to implement the market power mitigation. It also would be performed annually to reassess and adjust the market power mitigation, and to evaluate the conditions of the market.
440. In addition, the Commission proposes to require an annual assessment of the performance of the markets operated by the Independent Transmission Provider. This assessment would use a competitive benchmark to assess market performance as an additional means of assessing the effectiveness of the market power mitigation.
441. Comment is requested on how the monitor should address these and other topics, to develop useful measures that permit inter-regional comparisons. For example, concentration measures stratified by generator type might better identify competitive alternatives under various demand conditions. Estimates of generator profitability, such as PJM and ISO-New England have used in the past, might be a useful measure of incentives for generator entry. These estimate the degree to which a hypothetical unit operating in all profitable hours would have recovered its costs. Although it is not a definitive profit estimate for any particular generator, it may be a useful measure for comparing incentives for generator entry across market or regions.
442. A core set of questions and analytical techniques must also be developed for monitors to use to evaluate conduct of market participants in the transmission and spot markets operated by the Independent Transmission Provider. Analysis of generation and transmission outages is central because these can be forms of withholding. Because some owners of generation also own transmission, monitors must review any planned transmission outages, for example, to make sure that scheduling outages could not be used to enhance or create opportunities to exercise generator market power. Analysis of generator conduct might also include a review of bidding behavior in the spot markets operated by the Independent Transmission Provider to identify any auction design flaws that may give market participants an unanticipated incentive and ability to manipulate market-clearing prices or up-lift payments. The monitor should also evaluate the effectiveness of the participating generator agreements in mitigating market power where market structure is not sufficiently competitive.
443. Finally, the monitor must analyze the operation of the congestion management system and the market for the resale of Congestion Revenue Rights for evidence of market power or manipulation. The monitor must also assess whether those who collect congestion revenues are in a position to influence transmission expansion plans that can affect congestion revenues and report on the incentive structure of those arrangements.
444. Any flaws in the market rules that may be identified by the monitor and any market participant conduct that indicates the ability to exercise market power under the market rules in effect would be remedied prospectively after Commission authorization of changes to the market rules. However, if the conduct violates existing rules, the market monitor must have the necessary tools to investigate the conduct and to penalize it. These will be discussed in the sections below.
445. An important adjunct to the market power mitigation and monitoring plan will be a clear set of rules governing market participant conduct with the penalties for violations clearly spelled out. The Commission proposes to require the Independent Transmission Provider to include in its tariff certain minimum behavioral rules, which will be monitored by the market monitor. These will include, at a minimum, the following rules:
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446. These rules must be accompanied by predetermined penalties, as discussed below in the Enforcement section.
447. Data collection should be targeted to providing monitors with information necessary to answer the required questions covering critical issues regarding market structure, participant behavior, and market design. These data would be acquired from various public sources and in the normal course of operating the markets. They would include: (1) Market statistics and indices, such as market-clearing prices and system-wide congestion costs; (2) data on system conditions, such as transfer capability and planned and forced outages; (3) information on other prices, such as fuel prices and prices in adjacent markets; (4) information on load served from the spot market; (5) data relating to generator bidding patterns; and (6) information on Congestion Revenue Rights.
448. In addition, monitors must have the ability to obtain data on generator production and opportunity costs and information on the operating status of transmission and generation facilities that relate to claimed outages or deratings. Generator-specific data on all relevant costs and operating parameters—
449. As a condition for participating in the spot markets, and using the transmission grid, market participants must agree to provide the market monitor with any information requested. Since the ability of the market monitor to perform his or her monitoring role is dependent upon the ability to acquire the necessary information, the monitor must have the ability to require market participants to provide information. This is an important enforcement tool. The Independent Transmission Provider's tariff should specify the penalties that would apply to market participants who fail to comply with an information request from the market monitor. Market participant objections to market monitor information requests will be resolved by the Commission on an expedited basis because delays in providing information could result in continuing harm to the market. In any such dispute the Commission will give substantial deference to the market monitor's stated need for the information.
450. All information obtained by the monitor that is specific to a market participant would be treated confidentially. Any disputes concerning how the confidential information could be used would be resolved by the Commission, before the data are released to the public. Since the Commission has oversight responsibility for wholesale electric markets, any data collected by the market monitor would be available to the Commission and the confidentiality of the data would be protected by the Commission under its regulations.
451. At a minimum, the monitor would be required to submit an annual report to the Commission and the Independent Transmission Provider's governing board, and share that report with the Regional State Advisory Committee. The report would include: (1) A general description of the market operations, supply and demand, and market prices; (2) an analysis of market structure and participant behavior following guidelines described above; (3) an evaluation of the effectiveness of mitigation measures taken; (4) an overall assessment of market efficiency perhaps using a simulated competitive benchmark as some have developed; (5) an evaluation of barriers to entry for generating, demand-side, and transmission resources; and (6) any recommended changes to market design or market power mitigation measures to improve market performance. The report would also include a discussion and analysis of any region-specific issues that the monitor judges important to achieving a competitive outcome. This could also be particularly useful to the planning process in determining where expanded transmission capacity might reduce market power problems in load pockets. The annual report would be made public, with appropriate protections to maintain confidentiality, if necessary.
452. In addition, the market monitor will be required to report to the Commission, through the Office of Market Oversight and Investigation, any instances of conduct by market participants that appear to be inconsistent with the Independent Transmission Provider's tariff. Early reporting of questionable conduct will permit coordination between the market monitor and the Commission's investigative staff to determine the best methods for developing the facts and addressing conduct that could be harmful to the market.
453. The Commission requests comment whether additional reporting requirements are needed.
454. The market monitor must play an important role in the enforcement of the market rules contained in the Independent Transmission Provider's tariff. In this role the market monitor will need to coordinate closely with the Commission's investigative and enforcement staff. However, to ensure effective enforcement, the market monitor must have adequate authority to investigate market participant conduct and the Independent Transmission Provider must have a set of predetermined penalties to apply to conduct that is in violation of the rules of the Independent Transmission Provider's tariff.
455. As a condition of participating in the markets operated by the Independent Transmission Provider and using the transmission grid operated by the Independent Transmission Provider, the Commission proposes to require market participants and transmission customers to agree to predetermined penalties that would apply to violations
456. It may be appropriate to build into the tariff standards for mitigating the penalty. Some standards that could be used are: the impact on the operation of the grid, the financial impact on the violator, and any good faith efforts to maintain compliance. The Commission requests comment on the conditions that would justify mitigation of the penalty.
457. To operate the transmission system reliably, the transmission operator must be able to balance generation and load at all times. This requires adequate electric generating, transmission, and demand response infrastructure. Some lead time is needed to develop adequate infrastructure for the future through self supply or bilateral contracting.
458. Resource adequacy today must be assessed at the regional level. Because all customers in an interconnected region are interdependent, a shortage of resources for some customers in the region can lead to a shortage for the entire region, which threatens reliable grid operations and risks sustained shortages with attendant high prices for the region.
459. We propose a resource adequacy requirement to provide for sufficient supply and demand resources to avert such shortages. Under these procedures, we believe that involuntary curtailment will rarely if ever be employed. However, consistent with current policies, the proposal must include procedures for such emergency conditions.
460. The Commission proposes to adopt a resource adequacy requirement to help ensure development of the infrastructure needed for reliable transmission system operation. Because electricity cannot be generated and easily stored for future delivery, extra generating and demand response resources are needed to serve a function similar to storage in the natural gas industry; other commodity markets would call these a supply inventory. The cost of necessary reserves is analogous to the necessary cost of storage or inventory.
461. A requirement to assure adequate long-term resources is currently needed because spot market prices do not consistently signal the need for new infrastructure in the electric power industry. Most resources take years to develop and spot market prices alone may not signal the need to begin development of new resources in time to avert a shortage. Moreover, spot market prices that are subject to mitigation measures may not produce an adequate level of infrastructure investment even after a shortage occurs. Further, as long as regional resources are made available to all regional load-serving entities and their customers during a shortage, such entities have the incentive to lower their supply costs by depending on the resource development investments of others, a strategy that leads to systematic under-investment in infrastructure by all load-serving entities in the region.
462. The spot market price does not yet work well to produce long-term reliability investment, even without price mitigation, for several reasons. Extra resources need to be planned in advance for electricity because, when prices rise, demand is not reduced quickly and new generation cannot be added quickly. Both the demand for electricity and the supply of new generating capacity generally respond very slowly to price.
463. Regarding demand response, most retail customers buy power at a regulated fixed price. Even in states that have approved retail competition, customers are often shielded for years from price changes by a rate freeze. They are unaware of hourly changes in the cost of producing electricity. Electric meters are read monthly, and customers see only the imperfect price signal of a monthly bill rendered after electricity is used. Although larger commercial and industrial customers can be more price responsive, for many of them electricity is a small fraction of their cost of doing business and may receive little managerial attention. It takes time to develop the administrative rules and the technical capability to reduce consumption. As a result, most demand today is unable to respond to real-time prices because of insufficient price information, inflexible rate designs, and metering limitations.
464. The response of new generating capacity to price is slow because it takes time to plan, site and construct new electric power generating facilities. Development of a new power plant takes two to five years or more, depending on the type of plant and its location. It can take even longer to site the transmission lines needed to transmit the power to customers.
465. These factors together can lead to sustained periods of inadequate supplies, threatening the reliable operation of the bulk power system. Insufficient demand response to price and the slow supply response to price can combine to produce electricity shortages that not only threaten reliability but also can raise day-ahead and real-time market prices significantly.
466. Further, rushing to relieve inadequate regional supplies and reduce high regional spot prices may bias construction choices toward supply resources that can be constructed quickly, perhaps sacrificing long-term cost minimization, environmental concerns and fuel diversity goals. Most customers prefer spreading out resource capital costs over time to concentrating them into a peak period. A resource adequacy requirement accomplishes this.
467. Customers object strongly to inadequate supplies—and high prices when supplies are inadequate—because electricity is essential for many uses and customers cannot turn to substitutes to reduce electricity demand. Electric power drives modern life, and there is significant societal disruption from even short supply interruptions.
468. For these reasons, customers want protection from the exercise of market power that may occur when supplies are short, and some form of market power mitigation is needed under these circumstances, as discussed in the market power mitigation section. However, market power mitigation may tend to suppress the scarcity price that
469. In an interconnected region, the failure of some market participants to secure sufficient long-term electricity resources can contribute to a shortage that affects reliability and spot market prices for all participants in the wholesale power market.
470. Under retail competition, load-serving entities competing for customers may compete on the basis of cutting the cost of forward contracting for resources unless they all are held to the same resource adequacy requirement. Without such a uniform requirement, those suppliers that contract for reserves may lose market share, and those who do not may gain a market share—at least for a short period of time. For this reason, a load-serving entity has an incentive to minimize its own costs by procuring few or no reserves and relying on others to develop reserves. If the rules allow it, some load-serving entities will try to have the reliability benefit of adequate regional resources that other load-serving entities pay for or that uncontracted-for generation must offer pursuant to market power mitigation.
471. Severe power shortages lead to public insistence on government intervention. Both historical practice and recent events indicate that during a shortage those load-serving entities that have reserves are required by government to share them with those that do not have reserves. There are at times state regulatory and gubernatorial requirements to protect customers from blackouts or high prices, a U.S. Department of Energy requirement for utilities to share power reserves in an emergency, or a Commission requirement to bid all available power into an organized spot market.
472. Some market participants depend on government intervention during severe shortages as an alternative to paying their share of the cost of developing adequate regional resources. As long as regional reserves are made available to all, a load-serving entity can reduce its own reserve resource costs and rely on the resources of others. The result is that all load-serving entities will tend to follow this strategy, leading to a systematic underinvestment in resources needed for reliability.
If their provision were left to the marketplace, public goods would be underallocated. The reason is that individuals would have incentives to understate their own preferences in order to avoid paying and free-ride on the demands of others. Thus, public goods provide one of the strongest arguments for government intervention in the marketplace: not only does the market fail, but it can fail miserably.
473. These arguments persuade us to propose a long-term resource adequacy requirement in the Standard Market Design rule. A resource adequacy requirement provides for timely development of supply and demand response resources to assure regional resource adequacy. It helps smooths out the price swings of the electricity business cycle. A well-designed resource adequacy requirement supports competitive markets if it allows suppliers to compete to provide infrastructure and buyers to choose the infrastructure with the best combination of features such as cost, reliability, environmental effects, and service life.
474. We propose to require, as set out in the proposed regulations, that an Independent Transmission Provider must forecast the future demand for its area, facilitate determination of an adequate level of future regional resources by a Regional State Advisory Committee, and assign each load-serving entity in its area a share of the needed future resources based on the ratio of its load to the regional load.
475. The Independent Transmission Provider must assure that each load-serving entity in its area acts to meet its share of the future regional needs—through self-supply, contracts to purchase generation, biddable demand or other demand response program. The Independent Transmission Provider must apply standards, discussed below, to audit the adequacy of the plans of load-serving entities to meet the future resource needs of its area. Moreover, the Independent Transmission Provider must check that resources are not double-counted by different load-serving entities. In a region with more than one Independent Transmission Provider, each Independent Transmission Provider must coordinate this checking responsibility with all the Independent Transmission Providers in the region.
476. If a power shortage occurs during which the Independent Transmission Provider is unable to satisfy demand in the spot market and also meet its reliability requirement for a minimum level of operating reserves, the Independent Transmission Provider must add a per-megawatt-hour penalty during the shortage to the price of energy taken from the spot market by a load-serving entity that did not meet its share of the regional needs for that year.
477. Further, if the operating reserve level decreases to the point that the Independent Transmission Provider must curtail load, the Independent Transmission Provider must, to the extent possible, curtail the spot energy purchases of the load-serving entity that did not meet its resource adequacy requirement before curtailing the spot energy purchases of load-serving entities that did. The load-serving entity is subject to such first curtailment during a shortage only in the amount by which it falls short of meeting its share of the resource adequacy requirement for the year in which the shortage occurs.
478. If a shortage remains after all such first curtailments are completed and additional curtailment is necessary, the remaining loads of the first-curtailed load-serving entities and the loads of other load-serving entities that have satisfied their resource adequacy requirement would be curtailed under the same protocol. In this case the shortage may be attributable to certain load-serving entities of either type that, whether or not they may have met their resource adequacy requirement. We expect that those load-serving entities that are short of their own reserves would lose service ahead of those that are not short.
479. The approach to resource adequacy proposed here is intended to assure the development of both new supply and demand response resources.
480. This proposal is designed to complement, not replace, existing state resource adequacy programs. A vertically integrated utility satisfying a current state resource requirement that equals or exceeds its share of the resource adequacy requirement would not have to do anything more. For those states that have retail choice programs in which retail customers or their suppliers buy power from a multistate region, we intend this approach to provide for regional adequacy in a way that no one state alone may be able to accomplish.
481. The proposed approach is like the traditional reserve margin requirement imposed by states on monopoly utilities. It worked well during most of the last century to ensure adequate supplies, and is still in use in most states, especially states that have no retail choice program. However, because the traditional approach relies on individual utility plans and resources, it might not continue to work well in a region where utilities now rely on independent power producers in several states for new resources instead of their own new generation. The traditional reserve margin requirement may also not work well in a region where some states have traditional monopoly utilities and others have retail choice because a shortages in one state can affect all states in the region.
482. To continue to rely on the traditional reserve margin requirement, it has to be adapted to have a regional focus and to fit with competitive procurement. We propose a resource adequacy requirement of this type.
483. The resource adequacy requirement proposed here is unlike that of the three Northeast ISOs. ISO-New England, the New York ISO and PJM each impose an obligation on load-serving entities known as an Installed Capacity (ICAP) requirement. The three requirements differ, but share some basic characteristics. We are reluctant to impose a national ICAP requirement, in part because of our concern about the effectiveness of the existing ICAP programs and in part because they were based on former voluntary tight power pools. The three ISOs play a strong role in administering the program, a role that may not suit regions without a history of tightly coordinated reserve sharing.
484. The basic features of the proposed requirement are set out next, including discussion of the demand forecast, the level of resource adequacy, the role of the load-serving entity, the load-serving entity's share of the regional resource adequacy requirement, the types of resources that can satisfy the resource requirement, the standards that each type of resource must meet, the planning horizon, enforcement of the requirement, and regional flexibility.
485. An Independent Transmission Provider would be required to do an annual demand forecast for its area. The forecast would look ahead for the time period needed to add new supply and demand response resources. We will refer to this time period as the planning horizon, a topic discussed further below.
486. Demand forecasts have long been used in the utility industry to determine the need for future resources and to plan new infrastructure investments. The Independent Transmission Provider may undertake a “bottom up” method of demand forecasting by adding up the demand forecasts of its component areas where they can be relied on.
487. After the area's demand is forecast, the Independent Transmission Provider must assess whether the collective resource plans of load-serving entities in this area are adequate to meet the projected future peak need with allowance for adequate reserves. In today's more competitive environment, the effectiveness of single-utility supply forecasts may be reduced. Under open wholesale transmission access, regional patterns of energy flow can change quickly, making single-utility transmission planning difficult. Generators sited in a utility's service territory, if not under contract, may export power to another area or region. Single-utility forecasting is also more difficult today because power market information is considered very sensitive. Competitive suppliers are reluctant to share this information with a utility that is a potential competitor. A regional assessment of regional supply adequacy by one or more independent entities in the region would help overcome these difficulties.
488. Further, close coordination is needed between those planning generation and transmission because the location of planned generation affects the location of planned transmission and vice versa, and an Independent Transmission Provider (or a group of Independent Transmission Providers acting collectively in a region with more than one Independent Transmission Provider) is in the best position to coordinate these planning functions.
489. Once the future level of supply and demand resources is determined, the region must assess whether this level is adequate. This requires a regional determination of the appropriate level of resource reserves, for example, whether the reserve margin (if reserve margin is the region's measure of resource adequacy) should be 12, 15, 18 percent, or another level. We seek comment on and encourage regional discussion of appropriate planning targets in energy-limited areas, specifically on how to incorporate volatility of annual hydropower supply.
490. Each region should take its own characteristics into account when determining the appropriate level, subject to a minimum level of resource adequacy for all regions discussed below. This determination has been made by load-serving entities under the oversight of the states, and we want this state oversight to continue. We propose that the level should be set by a Regional State Advisory Committee.
491. We will require the Independent Transmission Provider (or the several
492. However, we ask for comment on what fallback provision should be employed if the Regional State Advisory Committee does not reach agreement on the appropriate level of resource adequacy. We believe that having different reserve levels in different states in the same region maintains the problem of some customers relying on the reserves of others.
493. We are concerned that the requirement be set so that the Independent Transmission Provider can operate the interstate transmission system reliably with real-time operational resource adequacy. We are also concerned that inadequate resources could lead to poor market liquidity and even shortages with sustained high wholesale power prices. For these reasons, we propose to adopt a 12 percent reserve margin
494. Each load-serving entity must satisfy a portion of the regional resource adequacy requirement. Load-serving entity here means any entity that uses transmission in interstate commerce to provide power to load, whether a traditional distribution utility or an energy service supplier that aggregates retail loads under a retail access program.
495. A large retail industrial or commercial customer that has retail access rights and buys power directly from suppliers is also considered a load-serving entity. If it does not buy power from another load-serving entity but uses the interstate grid to buy power directly from a supplier, it too would be required to meet its share of the resource adequacy requirement. As for other load-serving entities, their reserves may include the ability to reduce their own demand on the grid.
496. A load-serving entity may choose a higher level of reliability by developing more supply or demand response resources than required. Further, a load-serving entity may choose greater reliability and price assurance by procuring additional reserves for its own use. In particular, customers in a load pocket that is served by a few large generating units may need a higher reserve margin to have the same level of reliability as customers outside a load pocket.
497. Once the future regional requirement is determined, each load-serving entity's share of the regional requirement must be determined. Meeting a regional resource adequacy level does not assure that every part of the region has adequate resources if there are internal transmission constraints or if resources are counted that may be sold outside the region, retired before needed, or otherwise made unavailable. For these reasons, it is important that resources not be considered merely regional but be associated with and committed to particular load-serving entities.
498. We request comment on two methods for determining each load-serving entity's share of the regional requirement. One is to allocate the future resource adequacy needs to loads based on each load's forecasted future demand. For example, if the load forecast is for three years ahead and a particular load is growing faster than the regional average, its share of the adequacy requirement could be based on its forecast load ratio share for three years ahead, not on the present load ratio share. This method assigns more adequacy responsibility—and cost—to faster growing loads. However, if the Independent Transmission Provider's forecast is made through a “bottom up” method that adds up individual load forecasts, it must rely on each load to report its growth rate accurately. This approach creates an incentive for loads to understate their growth to lower their resource costs.
499. The other method is to allocate the future adequacy requirement to loads based on each load's most recently documented load ratio share. This method is less subject to manipulation. However, an area with a slow load growth located within a region of generally high load growth may subsidize the high reserve needs of its neighbors.
500. We ask for comment on which of these two methods the Commission should choose in the Final Rule. Alternatively, we ask whether this issue should be left to regional determination.
501. Once each load-serving entity's share of the regional adequacy requirement is determined, the Independent Transmission Provider must inform each load-serving entity of its share. It must require each load-serving entity to report and document how it plans to meet its adequacy requirement.
502. The time available to the load-serving entity from being informed of its resource share to having to report to the Independent Transmission Provider must be adequate to allow it to develop arrangements for meeting future resource needs. We ask for comment on how much time is needed for these purposes.
503. Each region's resource adequacy requirement could be satisfied by a combination of generation,
504. The supply requirement could be satisfied by self-owned generation, local distributed generation, or firm bilateral contracts for power that are backed by specific generating units (or a portfolio of designated generation units). The firm bilateral contract could be either a forward contract for the purchase of power or an option to purchase energy under specified shortage or price conditions, as long as the firm contract is backed by specified generating units.
505. In any of these cases, the generator must be committed to supply power to the load-serving entity, at least under certain conditions. Self-owned generation that is committed to another load-serving entity, unless it can be recalled during a shortage, would contribute to the other load-serving entity's requirement, not the requirement of the load-serving entity that owns it. Generation under contract must specify that the generator will be available to the load-serving entity—or at least to the market that the load-serving entity participates in—under conditions set out in the contract. These conditions, discussed further below under generation standards, must be adequate to meet the region's need for reserve resources.
506. The firm contract would be for a forward-looking period that would at least cover the planning horizon, which (as discussed further below) would be selected regionally and should be based on the time needed to develop new resources in the region. The load-serving entities must also demonstrate that future use of the designated resources is physically feasible and, in particular, that transmission is or will be available to deliver energy from a generator to the load-serving entity that claims it in its resource plan.
507. Allowing demand response infrastructure to satisfy the requirement removes bias toward exclusive reliance on new generation to meet regional needs. Better demand response to high prices when a shortage condition approaches will lower demand and reduce the use of high-cost power resources. Demand response will help ensure reliability, prevent a shortage that could produce a curtailment, act as a check against market power, and provide a yardstick for the value that buyers place on supply.
508. Biddable and interruptible load can satisfy the resource adequacy requirement as well as generation.
509. The Independent Transmission Provider must determine if each load-serving entity's planned resources meet certain standards. The resources must meet the standards to count toward satisfying the entity's share of the regional resource requirement. Both generation and interruptible or biddable load must meet standards to satisfy the requirement.
510. We propose here certain minimum standards for comment. We also are considering in the Final Rule to ask the North American Energy Standards Board (NAESB) to develop more detailed standards for determining whether resources satisfy the resource adequacy requirement, and we seek comments on this approach.
511. Generation must be owned by or under contract to the load-serving entity and committed to meet the resource needs of the load-serving entity at least during certain conditions such as an operating reserve shortage. The Independent Transmission Provider must be satisfied that the generation is physically feasible; that is, the generating units are capable of generating the power planned, and enough transmission is available to deliver the power from the generating station to the particular load. The generating units under contract must be real and specific generators. This is so that only real generation that can avert a supply shortage is counted and so that its transmission over the grid can be assured. For example, it does no good for a load on Long Island to claim a generator in western New York as a resource if the power cannot be delivered to Long Island during a Long Island shortage.
512. Because the purpose of this requirement is to encourage the development of new resources including new generation, generation under contract for development within the planning horizon should satisfy the requirement. Should the Commission specify the contract content needed to rely on generation under development? If so, should we refer this matter to NAESB to determine the content?
513. For these reasons also, a contract with a marketer to deliver power at a future time from unspecified sources cannot satisfy the requirement. The purpose here is not to transfer financial risk for nonperformance to a marketer but to ensure performance, that is, to ensure that enough actual, deliverable generating capacity is available or developed at satisfactory locations to avert a future shortage. However, a forward contract with a marketer that is linked to specific generation and demonstrates transmission adequacy would satisfy the requirement. We ask for comment on whether we should allow a liquidated damages contract for power from unspecified sources to be included in the resource adequacy plan, and also on whether we should allow a load-serving entity that initially fails to satisfy the resource adequacy contract, but later brings in new resources under a liquidated damages contract for the amount of its resource deficiency, to avoid the penalty price and first curtailment in the spot market during a shortage.
514. Generation must be deliverable to satisfy the requirement. A Congestion Revenue Right for the appropriate year is one way to satisfy this requirement. We propose to adopt a practice (used in PJM) that allows a resource owner to pay for the development of adequate transmission to deliver its energy to a load and then to sell its Congestion Revenue Rights while still satisfying the requirement that its generation be deliverable. Should a commitment by any load-serving entity to pay congestion costs no matter how high also satisfy the requirement? If so, how should the Independent Transmission Provider respond if the sum total of all such commitments exceeds the available capacity of a bottleneck interface?
515. A robust transmission system with few constraints may allow a load to rely on generation and demand
516. For transmission as well as for generation and demand response, the purpose of this requirement is to encourage the development of least-cost resources, which may include new transmission needed to access existing or new generation. We believe therefore that planned transmission with full siting approval and completion expected within the planning horizon should satisfy the adequacy requirement.
517. Demand response must also be verifiable to satisfy the adequacy requirement. The Independent Transmission Provider must have confidence that the demand response resource will be able to contribute when called on during a shortage. Demand response may be obtained through biddable demand reduction, interruptible load, or other dependable load management program. Distributed generation that is interconnected with a customer, a load-serving entity, or an energy services company, although it is technically generation and not demand response, can also be used by a local distributor to reduce the demand that the distribution system places on the grid. With biddable demand reduction, certain loads will be assured of dropping off the system at known price levels; the amount of load dropped should increase with the price.
518. With interruptible load, a customer pays a lower power price year round but will be interrupted under defined shortage conditions; the load is subject to a simple on-off criterion. An important feature of this proposal is that the load-serving entity plan that depends on interruptible load to meet its resource adequacy requirement must be capable of being implemented. The Independent Transmission Provider may require, for example, that the load-serving entity install equipment that gives it direct control over the loads of the customers that are subject to the interruption. We recognize, however, that installation of such equipment may be too costly or otherwise impractical in some situations. In that case, the load-serving entity must have a satisfactory arrangement for implementing its interruptible load program under the instructions of the Independent Transmission Provider.
519. If load in an area “buys” demand reduction from another area (in effect buying some of that other area's freed-up generation), the transmission needed to deliver the freed-up generation to the load that relies on it must be available.
520. The purpose of a forward-looking resource adequacy requirement is to create a demand for new resource entry in advance of a shortage so that enough supply construction and demand response infrastructure installation are begun in time to avert the shortage. The planning horizon for each region is the number of years ahead for which the Independent Transmission Provider must forecast annually its area's load, as well as the number of years ahead for which load-serving entities must show that they have adequate resources. For example, the Independent Transmission Provider could forecast its area's peak load three years from the present and require that each load-serving entity in its area have acceptable plans today to have enough resources three years from now to meet the forecast peak with a reserve margin of 12 percent. In this example, the planning horizon is three years and the reserve level is the minimum 12 percent.
521. The choice of the planning horizon affects the lead time for construction and the duration of forward contracts that can satisfy a resource adequacy requirement.
522. Because the planning horizon should be no less than the time frame for developing new resources and development times vary from region to region, the planning horizon can depend on that region's reliance on coal, gas, wind, hydropower or new demand-response technology for new supply. This argues for allowing each region to determine its own appropriate planning horizon.
523. We propose to make the planning horizon a matter for regional choice. Regions should consider several factors in selecting the planning horizon. Most important, the planning horizon chosen should not be so short that it fails to motivate and achieve construction of generation and demand response resources in time to avert a shortage. Greater fuel diversity may be achieved with a longer planning horizon. If the horizon is short, two years for example, load-serving entities may have an incentive to select resources that can be developed in two years or less, such as peaking units and some other gas-fired generators. A longer planning horizon allows time for development of other resources such as coal-fired generation, hydroelectric resources, and some advanced demand response programs. Load-serving entities in retail choice states would benefit from a shorter planning horizon because it would reduce their business risk associated with demand forecast error. Also, they may not want to enter into bilateral contracts for supplies for a time period that is longer than the duration of their contracts with their customers.
524. We propose to have the Regional State Advisory Committee determine the planning horizon for the region. The Independent Transmission Provider (including each Independent Transmission Provider in a region with more than one Independent Transmission Provider) must provide information and support to the Committee, as requested, to help it to determine the region's planning horizon. We request comment on how to resolve any lack of consensus within the Committee regarding the appropriate planning horizon. We also ask for comment on whether the Commission should establish limits on the region's choice of planning horizon, such as at least three years and no more than five years.
525. We also ask for comment on whether to have a resource adequacy requirement before the end of the first planning horizon period. For example, if the horizon is three years, should there be a requirement for resource adequacy in the first two years?
526. Here we explain in more detail our proposal to enforce the resource adequacy requirement, along with some alternative enforcement procedures, and ask for comment on the most effective enforcement method.
527. Unlike some ICAP requirements, the approach adopted here does not require a load-serving entity to pay a penalty in the near term for failure to
528. The first mechanism applies during a power shortage in which the Independent Transmission Provider is unable to satisfy demand in the spot market and also meet its reliability requirement for a minimum level of operating reserves.
529. Specifically, we propose that during such a shortage the Independent Transmission Provider must add a per-megawatt-hour penalty price to the price of energy taken from the spot market by a load-serving entity that did not meet its share of the regional needs for that year. This rate would apply only to spot energy purchases, not to power received from the load-serving entity's self-generation or bilaterally contracted energy. However, it would apply to spot market energy sales needed to correct for imbalances associated with energy from these sources. We would set the penalty price high enough that we do not suggest that failing to meet a resource adequacy requirement and paying a penalty rate is an acceptable alternative to developing new resources, which would be the case if the paying the penalty appears to be less costly over time.
530. The penalty price would increase in stages as the shortage becomes more severe. For example, the penalty price could be $500 (in addition to the spot market energy price) when operating reserves are just below the minimum level, $600 when operating reserves are more than below 1 percent below the minimum level, $700 when operating reserves are more than 2 percent below the minimum level, and so on. We ask for comment on having such a graduated penalty and the appropriate penalty rates.
531. This first enforcement mechanism provides a price-based mechanism to enforce a resource adequacy requirement and to restore the transmission system to a reliable condition. Most system operators—and their regulators—treat load curtailment (voltage reductions and blackouts) as a last resort measure, and operators may violate the reliability rule for minimum operating reserves rather than implement a load curtailment to satisfy the minimum operating reserve criterion.
532. The second enforcement mechanism is applied when the operating reserve level decreases to the point that some load must be curtailed.
533. In support of this second mechanism, we will require the Independent Transmission Provider to
534. If the Independent Transmission Provider does not have direct control of the circuit equipment needed to implement a curtailment and relies on the load-serving entity to follow its instructions to implement a curtailment, the load-serving entity would be subject to a severe penalty for the unauthorized taking of power from the spot energy market because this jeopardizes grid reliability. We propose to charge the applicable Locational Marginal Price plus $1000/MWh for all unauthorized energy taken following an instruction to implement curtailment.
535. We believe that load-serving entities, under these enforcement provisions and under the oversight of state regulatory authorities, will meet their resource adequacy requirement and not be subject to these curtailment penalty and first curtailment provisions at all. If most meet the requirement as we expect, shortages and first curtailment of any that do not should occur infrequently.
536. Having presented our enforcement proposal, we suggest variations of this proposal and ask for comments on these alternatives. As mentioned, under our proposal the penalty rate or load curtailment would occur at the end of the planning horizon, not the beginning. However, we ask for comment on this approach compared to an alternative approach that may provide a more immediate and effective incentive to a load-serving entity to take action to provide for future resources well in advance of facing a penalty or first curtailment. This is to impose a penalty on the load-serving entity immediately (that is, in year 2004 to continue the example in an earlier footnote) if it fails to submit a satisfactory plan to meet its 2007 resource adequacy requirement. We did not propose this option as our first choice because it has some of the unfavorable features of some ICAP programs that focus more on avoiding immediate penalties than on motivating long term resource development. However, we ask for comments on the merits of this alternative approach.
537. As presented, the Independent Transmission Provider audits the plan of each load-serving entity only at the beginning of the planning period (in 2004 in the example above). We are concerned that a load-serving entity may submit a satisfactory plan but fail to fully implement the plan. The proposal permits but does not require the Independent Transmission Provider to audit each year the progress of the load-serving entity in implementing its plan, and we ask whether we should explicitly require this. If the load-serving entity's progress is unsatisfactory, should the Independent Transmission Provider find that it fails to satisfy its resource adequacy requirement? If the load-serving entity implements its plan but some of its resources fail to perform when needed during a shortage, should that load-serving entity, in addition to having a greater need for spot market energy at a presumably higher spot market price, also be subject to either of the enforcement mechanisms set out above?
538. Another feature of our proposal is that it would not affect electric service from the self-generation and bilateral contracts of a load-serving entity that fails to meet its resource adequacy requirement (except that it would be subject to a penalty price during a shortage for balancing energy in the spot energy market). We ask for comment on whether this proposal unduly weakens the incentive to develop regional resources and whether, in the alternative, the Independent Transmission Provider should first curtail service to the load serving entities that failed to meet their share of the resource adequacy requirement, including transmission service from resources acquired outside the spot market, freeing up those resources for the use of those that planned adequately.
539. Finally, our proposed enforcement mechanisms are designed to create an incentive to avoid a future penalty or first curtailment. During the public outreach process for developing this proposed rule, some commenters recommended a stronger Independent Transmission Provider role in compliance with a mandatory resource adequacy requirement. One proposal is for the Commission to require the Independent Transmission Provider to procure resources on behalf of load-serving entities that fail to meet fully their requirement and charge them for the cost of the resources.
540. These approaches have advantages as well as disadvantages. Among the advantages are that they provide a greater assurance of achieving adequate resources and avoid the possible pitfalls of applying penalty rates or first curtailment. Among the disadvantages are that they take away one demand response option, namely curtailment, from the range of policy choices. Also, the latter approaches appear to require the Independent Transmission Provider to take a position in the capacity market, which places the Independent Transmission Provider in a role that may be incompatible with its independence.
541. What is the effect of these alternate enforcement mechanisms on the incentives and business risks of the
542. We propose to apply the requirement set out above to all regions, including regions that already have an ICAP requirement that has been previously approved by the Commission. This requirement would replace the current ICAP program.
543. Some regulators, customers, and market participants have expressed dissatisfaction with the ICAP models presently in place. Some customers view ICAP as an added cost with no tangible benefits; they assert that the commodity being traded has little value because customers are paying for installed capacity but not receiving any greater assurance that generation adequacy is maintained. Some commenters say that, in some ICAP programs, a generator can receive an ICAP payment and later be released from the ICAP obligation for a relatively small penalty to sell its capacity in another market with a high wholesale price.
544. Existing local generators are said to have preferential ability to participate in the ICAP market. The ICAP payment goes to the existing generators and does not necessarily lead others to enter the market to increase capacity. Depending on how the ICAP rules are designed, existing generators may be able to exercise market power, forcing up ICAP prices. In some markets, trading has been so thin at times that there is a question about whether there is a competitive market price.
545. In some such cases, the ISO has intervened to set the price administratively, and market participants are concerned that the price does not reflect the forward value of generating capacity. Some contend that prices in the spot markets and bilateral markets, including long-term forward contract markets, appear to be not well correlated with ICAP market prices.
546. The generators object to ICAP price controls. Some power generators see short-term ICAP payments as providing inadequate assurance of capital cost recovery to motivate new investment. They prefer longer-term contracts to ensure that their investment costs will be recovered.
547. Finally, many parties object that ICAP focuses on power generation, ignoring the potential of demand response.
548. Although we propose that every region must adopt our approach, this approach offers significant regional flexibility. Our approach allows each region to set its own level of resource adequacy, set its own planning horizon, and select from a combination of supply and demand response resources for meeting its needs.
549. Our proposal permits but does not require a region to have its Independent Transmission Provider establish a market for acquiring and trading adequate resources. We believe that the bilateral market and other means can be adequate for acquiring and trading resources. Nevertheless, we ask for comment on whether, under the approach to resource adequacy proposed here, we should require an Independent Transmission Provider to create a market to facilitate load-serving entities meeting their resource adequacy requirement efficiently.
550. Despite the flexibility of our proposed approach, regions with a historical reliance on a tight pool for sharing reserve may argue for a continuation of some form of ICAP program. We ask for comment on how existing Commission-approved ICAP mechanisms can be transitioned and modified so as to be made consistent with our resource adequacy proposal here without disrupting financial commitments made under existing rules. What are the disadvantages of particular elements of the ICAP approach that should be avoided in the approach proposed here? Do any of the enforcement proposals or alternatives discussed above re-introduce any such disadvantageous elements?
551. States have an important role in the process of creating and sustaining an efficient competitive wholesale market for electricity. The Commission has already established state-federal RTO panels as a forum for the Commission and state commissioners to discuss issues related to RTO development. However, there currently is not a formal process for state representatives to engage in a similar dialogue with the independent entity that will operate the electric grid under Standard Market Design. Therefore, the Commission is proposing to establish a formal role for state representatives to participate on an ongoing basis in the decision-making process of these organizations.
552. We envision that the Independent Transmission Provider that operates the grid would have a Regional State Advisory Committee. The Regional State Advisory Committee should be formed and should have direct contact with the governing board, in a manner which recognizes its public interest responsibilities, and be designed to provide the board as well as market participants and the Commission with a consensus view from states in the area. The specifics of how this advisory committee would be formed and operate would be decided on a regional basis. This coordinated oversight will ensure fulfillment of federal public interest responsibilities in a manner that includes the views of states throughout the region. In this regard, we also encourage the participation of Canadian provincial authorities in this process.
553. We take note of the recent report by the National Governors' Association entitled “Interstate Strategies for Transmission Planning,” which recommends establishing “Multi-State Entities” to facilitate state coordination on transmission planning, certification, and siting at a regional level.
554. The Regional State Advisory Committee may work with the regional transmission organization to seek regional solutions to issues that may fall under federal, state, or shared jurisdiction, which may include but are not limited to:
Further duties may evolve with the development and operation of the regional councils.
555. As discussed, the Commission is proposing to require that the independent entity that operates the
556. The Commission has previously recognized the importance of independent governance of regional organizations in both Order No. 888 and Order No. 2000. In Order No. 888, the Commission required that ISO governance be structured in a fair and non-discriminatory manner and that the ISO be independent of any individual market participant or any one class of participants. The Commission also required that the ISO's rules of governance should prevent control, and appearance of control, of decision-making by any class of participants. Order No. 2000 built upon and extended this independence requirement to RTOs. In Order No. 2000, we reaffirmed our commitment to independence as a bedrock principle for regional organizations, and in this rulemaking we find that our commitment to independence also is critical to the successful implementation of Standard Market Design. Compliance with the independence requirement of Order No. 2000 is based on the independence of the Board of Directors and all employees of the RTO. The governance requirements for the Board of Directors is critical to ensuring that the RTO is independent and that the RTO's interests are aligned with the interests of the market as a whole rather than with particular market participants of classes or market participants. While we did not mandate detailed governance requirements for RTO boards in Order No. 2000, we stated that we would review on a case-by-case basis the RTO governance proposals and judge them against the overarching standard that the RTO's decisionmaking process must be independent of individual market participants and classes of market participants. We also required an audit of the independence of an ISO's governance process two years after its approval as an RTO.
557. The Commission has considered on a case-by-case basis whether individual RTO proposals satisfy the Commission's requirements for independence.
558. As we have previously stated in both Order No. 888 and Order No. 2000, it is critical that the board be independent. The board's primary responsibility is to ensure that the markets operated by the Independent Transmission Provider are operated in a fair, efficient and non-discriminatory manner. The board's focus should be on the interests of the wholesale market, not the interests of particular market participants or classes of market participants. The board should not be regarded as a partner or a contractor of the market participants. Further, the board should be composed of members that are not part of the management of the Independent Transmission Provider. This Commission has the overall responsibility for the function of the wholesale electric market, including setting overall policy for the market. Independent Transmission Providers are public utilities subject to the Commission's jurisdiction under the Federal Power Act because they own, control or operate jurisdictional transmission facilities and will administer jurisdictional wholesale energy markets. In order to carry out the functions required by Standard Market Design, the board must be fully independent of any market participants. The board is responsible for overseeing the Independent Transmission Provider's administration of the tariff and market rules that have been approved by the Commission. It also must monitor the operation of the markets within its region to identify problems,
559. An important implication of these principles is that the board must not be a stakeholder board with industry segments given specific seats on the board. The interest of all board members should be a well-functioning market, not representation of a specific industry segment. Similarly, board members must have no financial interests in market participants so that there is no appearance of bias or benefit.
560. Stakeholders have an important role in advising the boards of Independent Transmission Providers. Most current regional organizations have established stakeholder committees that act either as advisors or in some cases vote on proposals that go
561. We are concerned that the current composition of these advisory committees may not adequately represent all segments of the industry. The current structure of many ISO stakeholder committees tends to replicate the functions of vertically integrated utilities. For example, PJM currently has five classes, Generation Owners, Transmission Owners, Other Suppliers, Electric Distributors, and End-Use Customers. Four of these classes represent interests that would benefit from higher levels of demand. Only one represents customers or end-users, and none represents demand-side technologies or alternative load control services such as demand resource management. This sector structure could discourage the introduction of changes that implement new demand management technologies and services, one of the biggest potential outgrowths of the move towards a competitive market. Financial entities, which are usually financial trading firms such as banks or other financial institutions that provide the needed capital to the industry, are also poorly represented, if at all. Therefore, we propose to require that an Independent Transmission Provider approved by the Commission must have at a minimum committees that reflect six stakeholder classes: (1) Generators and marketers, (2) transmission owners (this sector would include vertically integrated utilities), (3) transmission-dependent utilities,
562. The initial selection process for the Board of directors must be structured to ensure that board members are independent and have expertise in a variety of transmission and electric market areas. We propose that the following process be used.
563. First, the qualifications of the board members should be established. We believe it is important that the qualifications be more widely focused than just experience with electric transmission systems. Experience in additional areas such as risk management, generation planning and operation, or technology and innovation would provide the board with a wider background of knowledge in areas crucial to market development. We propose that board candidates be required to have experience in one or more of these fields: senior corporate leadership of a major publicly traded company; professional disciplines of finance, accounting, or law; electrical engineering; regulation of utilities; transmission system operation or planning; trading or risk management; information technology; and generation planning or operation. The candidate could have experience in the electric industry in either an Investor-Owned Utility or public power entity. The objective is to have a board that collectively possesses experience in many, if not all, of these areas.
564. Board members or their immediate families should not have current or recent ties (within the last two years) as a director, officer or employee of a market participant in the region or its affiliates. Board members or their immediate families should also not have direct business relationships with market participants or their affiliates. Finally, to the extent that the board member owns stocks or bonds of companies that are market participants, these must be divested within six months of being elected to the board. Prior to divestiture, the board member would not be able to participate in any decisions affecting that market participant or its affiliates. These requirements are necessary to ensure that the board member does not have any financial interest in a market participant that could influence the board member's decision. We propose that board members, their immediate families and senior management be required to fill out annual financial disclosure statements to ensure that there is no conflict of interest. The financial disclosure statements would be available for audit by the Commission.
565. Second, a nationally recognized search firm should be retained by the nominating committee to identify candidates that satisfy these criteria. The search firm should supply at least two names for each available board seat. The use of a nationally recognized search firm to develop the list of potential board members helps ensure the integrity of the process since the search firm would not have a financial interest in proposing candidates that represent specific market participants or classes of market participants. The search firm should not have a significant ongoing business relationship with the market participants in the region. The search firm must disclose to the nominating committee any ongoing business relationships it has with market participants in the region.
566. A nominating committee composed of two members from each of the stakeholder classes would be formed to review the list of candidates presented by the search firm. The nominating committee would vote for the individual board candidates as follows. Each nominating committee member would have the right to cast votes equal to the number of open board seats. A member shall not cast more than one vote for any one candidate and is not required to cast all of its votes.
567. Board seats are filled by a simple majority. Candidates with the highest vote totals are elected to open board seats. Ties for the last open board seats will have a runoff subject to the same rules as the initial selection process. The elected board members would vote to designate one of the members as Chairman of the Board. We seek comment on whether the Chief Executive Officer of the Independent Transmission Provider should be a non-voting member of the board.
568. We recognize that allowing a vote on candidates by stakeholders could be perceived as allowing a sector to dominate the board selection process or result in less than a fully independent board. While we recognize the concern, we believe that it is important that stakeholders have a voice in the selection process. We do not believe that it is the Commission's role to be the primary decision-maker in determining the candidates that are selected for the board. We seek comment on what protections should be built into the selection process to ensure that a class of market participants does not dominate the stakeholder voting process. Nevertheless, we solicit comment on whether to require the nominating committee to vote on an entire slate of candidates rather than on individual candidates.
569. The governance process also needs to include ongoing procedures for the selection of new board members. We believe that the process should seek to maintain a degree of continuity of board membership to ensure stability and consistency in decisionmaking, while at the same time ensuring that the board does change membership over time to allow the introduction of new viewpoints and encourage innovation.
570. To accomplish these two objectives, we propose that the board members have staggered terms. Approximately half of the first board should have initial terms of four years. The remaining board members should have initial terms of three years. All subsequent board members' terms will be for four years. The staggered terms will provide a degree of continuity to the board in its decision making process. We seek comment on whether the proposed staggered terms would lead to too rapid a turnover in the composition of the board. Board members would be permitted to serve no more than two consecutive terms. This limitation will ensure that there will be a change in board membership over time to allow for the introduction of board members with different experience.
571. The same process that was used to select the initial Board of Directors would be used in the selection process for subsequent board members in the case of resignation, death or removal for cause. Namely a nationally recognized search firm would be retained to identify board candidates. A nominating committee would be formed to review the list of candidates and propose new board members.
572. When the first set of board members terms start expiring a two stage process would be used for electing board members. First, existing board members whose terms are expiring would indicate whether they wished to remain on the board for a second term. The stakeholders would vote on whether these existing board members would remain on the Board of Directors. Second, if there were any remaining vacancies, then a search firm would be retained to provide candidates for the vacant seats on the Board of Directors. The same process that was used for filling the initial Board of Directors would be used for filling these vacancies.
573. We propose the following initial governance structure in the event of a merger of ISOs, RTOs or Independent Transmission Providers. Initially, the board members of the newly formed entity will be comprised of a number of board members from each of the respective organizations in addition to new members. We propose that there should be equal representation from each former organization plus an equal number of new board members.
574. A nominating committee will nominate all candidates (except the initial members that originate from the original boards of ISOs, RTOs or Independent Transmission Providers) for the initial election of new board members. The initial nominating committee will be composed of two board members from each of the respective merging organizations and the Chairs of two committees representing market operations, reliability and/or management.
575. System security is critical to the reliable operation of the interstate transmission grid. Wholesale electric grid operations are highly interdependent, and a failure of one part of the generation, transmission, or grid management system can compromise the reliable operation of a major portion of the regional grid. The wholesale electric market relies on the continuing reliable operation of not only physical grid resources, but also the operational infrastructure of monitoring, dispatch and market software and systems. Because of this mutual vulnerability and interdependence, it is necessary to safeguard the electric grid and market resources and systems by establishing minimum standards for public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce as well as entities that use these facilities.
576. NERC's Critical Infrastructure Protection Advisory Group has recently developed a set of recommended minimum requirements (standards) for securing information assets that support grid reliability and market operations and the physical environments in which these information assets operate. These standards are designed to ensure that the entity has a basic security program protecting the electric grid and market from the impact of acts, either accidental or malicious, that could cause wide-ranging harmful impacts on grid operations. These standards would be administered through an annual self-certification due January 31, 2004, and every January 31 thereafter. The proposed form for the self-certification is attached as Appendix G.
577. We propose to require that all public utilities that have tariffs on file with the Commission must file the self-certification by January 31, 2004, and every January 31 thereafter. Additionally, on and after February 1, 2004, as a condition of receiving
578. Finally, when the SMD Tariff is implemented, we propose to extend the requirement to cover the additional services being provided by the Independent Transmission Provider. At that time, any customer seeking to buy or sell through the markets operated by the Independent Transmission Provider or take transmission service under the Network Access Service would be required to demonstrate that it has a basic security program in place.
579. We expect that these standards will be revised and refined over time in light of changes in technology and operational experience with the standards. Therefore, the regulations will also identify the specific version number of the system security standards. When NERC revises the standards, the revisions will be filed with the Commission. The Commission will issue a Notice that it is considering revising the updated system security standards, and we will seek comments on the proposed changes. These security standards for electric market participants can be found in Appendix G, along with the proposed self-certification form, discussed above.
580. The Commission proposes to find in the Final Rule that rates, terms and conditions of transmission service and wholesale electric sales that do not comport with the regulations adopted by the Final Rule are unjust, unreasonable or unduly discriminatory. Many of the elements included in Standard Market Design will require computer software development and changes that public utilities may not be able to fully implement for a couple of years. The Commission's objective is to have Standard Market Design implemented on all jurisdictional transmission systems no later than September 30, 2004, or such time as the Commission may establish. The Commission does not believe it is in the public interest to delay implementation of the remedial action to cure undue discrimination or to develop necessary infrastructure until the time when all of the software changes necessary for standard market design are completed. Consequently, the Commission proposes a multi-step process that will be used to bring these rates, terms and conditions of service into conformity with the regulations.
581. The Commission will require all public utilities that own, control or operate interstate transmission facilities to begin discussions with stakeholders and state representatives within 30 days after the effective date of the Final Rule about how they will implement the transition process and comply with the requirements of the Final Rule. These discussions should address selection of an Independent Transmission Provider that will manage the transmission facilities, establishment of a regional state advisory committee, development of a regional transmission planning and expansion program, development of a long-term resource adequacy requirement and identification of areas such as load pockets where mitigation or appropriate infrastructure will be necessary.
582. The Commission recognizes that it has accepted many changes to the
583. Although a transmission tariff rate is already in effect for all public utilities that own, operate or control facilities used for the transmission of electric energy in interstate commerce, we acknowledge that changes to individual utility rates may be necessary as a result of the changes to non-rate terms and conditions that the Interim Tariff requires. Should a public utility determine that such rate changes are warranted by the new non-rate terms and conditions, it may file a new rate proposal pursuant to FPA section 205, no later than July 31, 2003. We will impose a blanket suspension on any such filings that we receive and make them effective, subject to refund, 61 days after they are filed.
584. We also propose a new tariff (SMD Tariff), attached as Appendix B, to supersede the Interim Tariff and implement Standard Market Design. The new SMD Tariff includes many areas in which the Independent Transmission Provider would propose provisions consistent with the policy framework set forth in the Final Rule, but designed to meet the specific circumstances of the region. We propose to give regions discretion in developing a transition program for existing contracts that is consistent with the guidelines set forth in the Final Rule.
585. The Commission recognizes that public utilities will need time to ensure that transmission facilities are operated by an Independent Transmission Provider, implement Network Access Service, establish day-ahead and real-time markets, adopt LMP for congestion management, incorporate market power mitigation measures customized for the region, develop a market monitoring program and develop a resource adequacy requirement for the region. Thus, for these requirements the Commission proposes a process for implementation that provides an opportunity for active participation by state representatives and market participants and that gives the Commission opportunities to review progress and require changes if sufficient progress is not being made.
586. To implement the requirements of Standard Market Design, we propose to require every public utility that owns, controls or operates facilities used for the transmission of electric energy in
587. The Commission will require all public utilities that own, operate or control interstate transmission facilities to file an Implementation Plan for compliance with the regulations no later than July 31, 2003. In the Implementation Plan, the public utility must identify the independent entity that will serve as the Independent Transmission Provider for the transmission facilities that the public utility owns, controls or operates. (A public utility that is already a member of an entity that satisfies the definition of Independent Transmission Provider may request a waiver from this requirement in its Implementation Plan filing.) Additionally, the Implementation Plan must include time lines and a proposal for compliance with the long-term resource adequacy requirements of the Final Rule. Further, the Implementation Plan must identify the software vendor(s) that the public utility will use for implementation of Standard Market Design and a time line that identifies implementation milestones and indicates the projected timing of their completion. The Commission wants to ensure that the cost of implementation of Standard Market Design is reasonable, and intends to closely monitor the expenditures incurred to implement the Final Rule. Therefore, we propose to require that all public utilities include in their Implementation Plan a detailed estimate of their projected cost of implementing the Final Rule. The estimate should include projected software costs as well as other costs that the public utility may incur. The public utility will also be required to file status reports on the Implementation Plan on a quarterly basis. The Commission will review the Implementation Plans and quarterly reports to ensure compliance with the regulations. Also, the Commission will establish appropriate procedures, if needed, for resolving concerns of state representatives and market participants.
588. The Commission recognizes that some public utilities will be able to implement Standard Market Design more quickly than others. The dates proposed in the Implementation Plan should reflect the level of changes that are required. The Commission intends to be flexible in setting compliance dates for Standard Market Design. The Commission expects that those public utilities that do not require significant changes could implement Standard Market Design much sooner than others. While the Commission's objective is to have Standard Market Design in place everywhere by September 30, 2004, it will consider requests to extend this date if the public utility can document that additional time is necessary.
589. Finally, the public utility must cooperate with others in its region to have a Regional State Advisory Committee in place by July 31, 2003.
590. The Commission proposes to require all public utilities that own, control or operate facilities used for the transmission of electric energy in interstate commerce to begin a regional transmission planning process within six months and produce a plan within one year of the effective date of the Final Rule. This will be an intermediate step in the process of satisfying the planning and expansion requirements contained in section 35.34(k)(7) of the Commission's regulations.
591. Pursuant to section 206 of the FPA, by December 1, 2003 all Independent Transmission Providers will be required to file the SMD Tariff, including language that explains the Independent Transmission Provider's proposals for market monitoring, market power mitigation, long-term resource adequacy, transmission planning and expansion, transmission pricing and any changes to the SMD Tariff necessary to accommodate regional needs. The filing must also indicate the date, which must be no later than September 30, 2004, or such date as the Commission may establish, when the Independent Transmission Provider will be able to fully implement Standard Market Design. The Commission must approve the tariff filing before the Independent Transmission Provider will be able to implement Standard Market Design. We anticipate acting on these filings on a timely basis so that the Independent Transmission Providers will know several months before the planned implementation date any changes that are required in these filings.
592. As a result of the changes required by the Final Rule, the Independent Transmission Provider or transmission owners may believe that other changes are needed in their transmission rates for jurisdictional service. Transmission owners and Independent Transmission Providers should file these types of changes under section 205 of the FPA at least 60 days prior to the date on which they propose to implement Standard Market Design. The Commission intends the implementation process to be a collaborative one. The Commission directs public utilities to meet with stakeholders and state commissions on a regular basis to discuss the changes that are necessary to comply with the Final Rule. Based on the filings that are received, the Commission may also establish technical conferences, mediation efforts or other procedures as necessary to ensure that all public utilities that own, control or operate interstate transmission facilities will be operating under Standard Market Design no later than September 30, 2004, or such time as the Commission may establish.
593. Further, the Commission intends this phased compliance process to encourage joint compliance filings. Public utilities may submit a single, joint application to meet the requirements of Standard Market Design, and Independent Transmission Providers may make necessary filings on behalf of their public utility members. Such joint filings may streamline the compliance process and reduce its costs.
594. The Commission proposes to require all public utilities to provide assurances to the Independent Transmission Provider with which they are affiliated that the public utilities comply with minimum security standards. We propose to require public utilities that have transmission tariffs on file with the Commission to file the self-certification of compliance with security standards that is attached as Appendix G. The self-certification must be submitted by January 31, 2004, and every January 31 thereafter. On and after February 1, 2004, any transmission customer (including a non-jurisdictional entity) that seeks to receive transmission service from a public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce must provide assurances to the transmission provider that it has a basic security system in
595. The Commission invites interested persons to submit comments, data, views and other information concerning matters set out in this proposed rule. To facilitate the Commission's review of the comments, the Commission requests commenters to provide an executive summary (not to exceed ten pages) of their positions. To the greatest degree possible, commenters should use the topic headings that the proposed rule uses and arrange their comments in the order of topics presented in this proposed rule, and cite the specific referenced paragraph numbers. Commenters should identify separately any additional issues that they may wish to address. Commenters should double-space their comments. Comments must refer to Docket No. RM01-12-000, and may be filed on paper or electronically via the Internet. The Commission must receive all comments no later than October 15, 2002. Comments should include an executive summary that should not exceed ten pages. Those filing electronically do not need to make a paper filing. Reply comments will not be entertained.
596. Those making paper filings should submit the original and 14 copies of their comments to the Office of the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426.
597. The Commission strongly encourages electronic filings. Commenters filing their comments via the Internet must prepare their comments in WordPerfect, MS Word, Portable Document Format, or ASCII format (
598. The Commission will place all comments in the Commission's public files and they will be available for inspection in the Commission's Public Reference Room at 888 First Street, NE., Washington, DC 20426, during regular business hours. Additionally, all comments may be viewed, printed, or downloaded remotely via the Internet through FERC's home page using the FERRIS link.
599. The Regulatory Flexibility Act
600. This rule applies to public utilities that own, control or operate interstate transmission facilities, not to electric utilities per se. The total number of public utilities that, absent waiver, would have to modify their current open access transmission tariffs by filing the Interim Tariff is 176.
601. With respect to the Interim Tariff, the Commission will specify precisely the terms and conditions that public utilities will have to incorporate into their existing tariffs, and this will considerably reduce the burden of modifying transmission tariffs. In order to implement the SMD Tariff, every public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce must (a) meet the definition of Independent Transmission Provider, (b) turn over the operation of its transmission facilities to a regional transmission organization that meets the definition of Independent Transmission Provider, or (c) contract with an entity that meets the definition of Independent Transmission Provider to operate its transmission facilities. We do not expect that any entity that must file an SMD Tariff would be a small entity as defined by the Regulatory Flexibility Act.
602. We do not, therefore, believe that the requirement of filing the Interim Tariff and SMD Tariff will impose a significant economic impact on small entities. Consequently, the Commission certifies that this proposed rule will not have a significant economic impact upon a substantial number of small entities.
603. In furtherance of the National Environmental Policy Act of 1969, the Commission will prepare an environmental assessment (EA) that will consider the environmental impacts of the proposed rule. A notice of intent to prepare the EA, including a request for comments on the scope of the EA and notice of a public scoping meeting was issued on July 26, 2002.
604. The Commission is submitting the following collections of information contained in this proposed rule to the Office of Management and Budget (OMB) for review under section 3507(d) of the Paperwork Reduction Act of 1995. The Commission identifies the information provided under Part 35 as FERC-516.
605. The Commission solicits comments on the Commission's need for this information, whether the information will have practical utility, the accuracy of the provided burden estimates, ways to enhance the quality, utility and clarity of the information that the Commission will collect, and any suggested methods for minimizing respondent's burden, including the use of automated information techniques.
606. Because of the regional differences and the various staffing levels that will be involved in preparing the documentation (legal, technical and support) the Commission is using an hourly rate of $50 to estimate the costs for filing and other administrative processes (reviewing instructions, adjusting existing ways to comply with previously applicable instructions or requirements, training personnel to be able to respond to the information collection, searching data sources, completing and transmitting the collection of information and conducting outreach sessions with all affected entities) associated with this proposed rule. The estimated cost is anticipated to be $10,755,200 (215,104 hours × $50) for this portion of the rule.
607. In addition, there is a separate component that must also be considered when implementing the requirements of this proposed rule, the costs for information technology (IT) needed to implement the SMD Tariff. The number of entities to be impacted at this phase of the rule's implementation will be fewer than at the Interim Tariff stage, but is still unknown at this time. Further, several entities are already developing or employing software that may be sufficient to implement the SMD Tariff, and the entities' software packages are at different stages of development. There are also regional differences to consider (as noted above) with respect to labor compensation. For these reasons, the Commission seeks comments on the anticipated costs for IT development associated with this proposed rule. When preparing their estimates, commenters should take into consideration design, procurement and operation costs for the following: (1) Data collection systems (including monitors, detection systems, control
The applicant shall not be penalized for failure to respond to this collection of information unless the collection of information displays a valid OMB control number.
608. The proposed SMD rules are intended to have a generally positive impact on these market participants. For example, the proposed SMD rules will facilitate direct dealings between market participants who want to secure long-term bilateral power supply arrangements. The proposed SMD rules will also facilitate short-term transactions that are made in the spot market to make up for imbalances (differences) between scheduled electricity supplies that were matched to projected load levels, and the load levels that actually develop. Through these proposed SMD rules, sellers will be able to more effectively sell into the market and buyers will be able to more efficiently buy from the market because they will not need to be directly matched up at the last minute on a real-time hourly and day-ahead basis. In addition, the proposed SMD rules will bolster the ability of many smaller customers, as well as larger customers, to profitably participate in programs designed to encourage reductions in loads to offset electricity supply shortages. Finally, the proposed SMD rules will foster the trading of transmission rights among transmission customers that will allow them to hedge against transmission congestion surcharges.
609. Up to 176 public utilities that own, operate or control transmission would be required to implement the Commission's SMD Rule. The revised open access transmission component of the SMD Rule would be incorporated as an interim amendment to the existing transmission tariffs of all jurisdictional transmission providers operating in interstate commerce. Independent Transmission Providers would also be required to file SMD Tariffs contained in the Final Rule to implement Network Access Service and Standard Market Design. To the extent an affected public utility participates in an RTO, or contracts with an Independent Transmission Provider, the RTO or Independent Transmission Provider would make the required filing on behalf of the affected public utility. Public utilities also will be permitted to file Implementation Plans jointly with other utilities. Further, the Commission proposes to entertain requests for waivers of the requirement to make compliance filings. These features of the proposed rule would lessen the incidence of SMD compliance filings. We have estimated for purposes of this analysis that RTOs and ITPs may number from 5 to 12 entities in the lower 48 states.
610. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE., Washington DC 20426 [Attention Michael Miller, Capital Planning and Policy Group, Phone: (202) 502-8415, fax: (202) 208-2425, e-mail:
611. Please send your comments concerning the collection of information(s) and the associated burden estimates to the contact listed above and to the Office of Management and Budget, Office of Information and Regulatory Affairs, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-7856, fax: (202) 395-7285].
612. In addition to publishing the full text of this document in the
613. From FERC's home page on the Internet, this information is available in the Federal Energy Regulatory Records Information System (FERRIS). The full text of this document is available on FERRIS in PDF and WordPerfect format for viewing, printing, and/or downloading. To access this document in FERRIS, type the docket number of this document, excluding the last three digits in the docket number field.User assistance is available for FERRIS and the FERC's Web site during normal business hours from our Help Line at (202) 208-2222 (e-mail to
Electric power rates, Electric utilities, Electricity, Reporting and recordkeeping requirements.
By direction of the Commission. Commissioner Breathitt concurred with a separate statement attached.
In consideration of the foregoing, the Commission proposes to amend Part 35, Chapter I, Title 18,
1. The authority citation for Part 35 continues to read as follows:
16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.
2. Part 35 is amended by adding a new Subpart G, Procedures and Requirements Regarding Non-Discriminatory Open Access Transmission Services and Standard Market Design, including new §§ 35.35, 35.36, 35.37 and 35.38 to read as follows:
(a) Applicability. This section applies to any public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce and to any Independent Transmission Provider.
(b) Definitions—
(1)
(2)
(i) Any entity that, either directly or through an affiliate, sells or brokers electric energy, or provides ancillary services to the Independent Transmission Provider, unless the Commission finds that the entity does not have economic or commercial interests that would be significantly affected by the Independent Transmission Provider's actions or decisions; and
(ii) Any other entity that the Commission finds has economic or commercial interests that would be significantly affected by the Independent Transmission Provider's actions or decisions.
(c) Non-discriminatory open access transmission services and standard market design.
(1) Every public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce, shall provide non-discriminatory open access services through the interim tariff contained in Order No. __, FERC Stats. & Regs. ¶ __(Final Rule on Electricity Market Design and Structure) no later than September 30, 2003. Such tariff shall remain on file with the Commission until it is superseded by the pro forma tariff contained in Order No. __, FERC Stats. & Regs. ¶ __ (Final Rule on Electricity Market Design and Structure).
(2) To implement the requirements of Non-Discriminatory Open Access Transmission Services and Standard Market Design, every public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce must meet the definition of Independent Transmission Provider, turn over the operation of its transmission facilities to a regional transmission organization, as defined in § 35.34(b)(1) of this title, that meets the definition of Independent Transmission Provider, or contract with an entity that meets the definition of Independent Transmission Provider to operate its transmission facilities.
(i) Every public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce as of [effective date of Standard Market Design Rule] must comply with this requirement by September 30, 2004, or such other date as determined by the Commission. Such public utility must inform the Commission which Independent Transmission Provider will operate the public utility's transmission facilities, and provide further information about its plans to implement Standard Market Design as specified in Order No. __, FERC Stats. & Regs. ¶ __, no later than July 31, 2003. Every public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce after the effective date of this rule must comply no later than 60 days prior to the time its facilities are used for transmission in interstate commerce.
(ii) A public utility that is a member of an approved regional transmission organization or an independent system operator or other entity that meets the definition of Independent Transmission Provider may file a request for a waiver of the filing requirements of this paragraph on the ground that it has already complied with the requirement. An application for a waiver must be filed no later than July 31, 2003, or no later than 60 days prior to the time the public utility's transmission facilities are used for transmission in interstate commerce.
(3) Pursuant to section 206 of the Federal Power Act, any entity that meets the definition of Independent Transmission Provider must file with the Commission a tariff of general applicability for the provision of transmission services, including ancillary services and the administration of the day-ahead and real-time energy and ancillary services markets. Such tariff must be the pro forma tariff contained in Order No. __, FERC Stats. & Regs. ¶__ (Final Rule on Electricity Market Design and Structure) or such other open access tariff as may be approved by the Commission consistent with Order No. __, FERC Stats. & Regs. ¶__ (Final Rule on Electricity Market Design and Structure). Such tariff must include proposed language that explains the Independent Transmission Provider's proposals for market monitoring, market power mitigation, long-term resource adequacy, transmission planning and expansion, transmission pricing, changes to the pro forma tariff necessary to accommodate regional needs, and further information as specified in the pro forma tariff contained in Order No. __, FERC Stats. & Regs. ¶__ (Final Rule on Electricity Market Design and Structure). The filing also shall specify the date on which the Independent Transmission Provider proposes to implement Standard Market Design.
(4) The Independent Transmission Provider shall file, pursuant to section
(5) One or more public utilities may jointly file an application to meet the requirements of this paragraph.
(6) An Independent Transmission Provider may make necessary filings on behalf of public utilities required to meet the requirements of this paragraph.
(7) The interim tariff and pro forma tariff contained in Order No. __, FERC Stats. & Regs. ¶__ (Final Rule on Electricity Market Design and Structure) will not apply to transmission of electric energy pursuant to contracts that were executed on or before July 9, 1996 and remain in effect as of [effective date of Standard Market Design Rule]. Customers under such contracts may elect to convert their contracts, consistent with their contract terms, to service under the pro forma tariff contained in Order No. __, FERC Stats. & Regs. ¶__ (Final Rule on Electricity Market Design and Structure) at any time after [effective date of Standard Market Design Rule].
(8) Waivers. A public utility subject to the requirements of this section may file a request for waiver of all or part of the requirements of this section, for good cause shown. An application for waiver must be filed no later than [effective date of Standard Market Design Rule], or no later than 60 days prior to the time the Independent Transmission Provider would otherwise have to comply with the requirement.
(d) Non-public utility procedures for tariff reciprocity compliance.
(1) A non-public utility may submit a transmission tariff and a request for declaratory order that its voluntary transmission tariff provides transmission service that is comparable to the service that the non-public utility provides itself.
(i) Any submittal and request for declaratory order submitted by a non-public utility will be provided an NJ (non-jurisdictional) docket designation.
(ii) If the submittal is found to be an acceptable transmission tariff, an applicant in a Federal Power Act (FPA) section 211 case against the non-public utility shall have the burden of proof to show why service under the open access tariff is not sufficient and why a section 211 order should be granted.
(2) A non-public utility may file a request for waiver of all or part of the reciprocity conditions contained in a public utility open access tariff, for good cause shown. An application for waiver may be filed at any time.
(3) If a non-public utility has on file with the Commission, as of [effective date of Standard Market Design Rule], a reciprocity tariff accepted by the Commission, the non-public utility is not required to make a filing under paragraph (d) of this section.
(a) The Independent Transmission Provider must have a market monitoring unit that is independent of the Independent Transmission Provider's management and that is accountable to the Commission. The market monitoring unit will provide information and recommendations to the Commission and the governing board of the Independent Transmission Provider.
(b) The market monitoring unit will monitor all markets run by the Independent Transmission Provider and the operation of the transmission grid for exercises of market power, flaws in the Independent Transmission Provider's tariff rules or operations that contribute to economic inefficiency, and market participants' compliance with the Independent Transmission Provider's tariff. The market monitoring unit also shall perform further duties as instructed by the Commission.
(c) The market monitoring unit will report at least annually on the structure and performance of the markets in the Independent Transmission Provider's region. The report must include, at a minimum: a description of market operations, supply and demand, and market prices; an structural analysis of the market, including an evaluation of barriers to entry; an assessment of market performance, including an assessment of market participant behavior; an evaluation of the effectiveness of the existing market power mitigation; and recommendations for improving the market design or market power mitigation measures to improve the efficiency of the market. The market monitoring unit also shall provide further reports as directed by the Commission.
(d) The Independent Transmission Provider must include in its tariff provisions requiring market participants, as a condition of participating in the markets operated by the Independent Transmission Provider and using the interstate transmission facilities operated by the Independent Transmission Provider.
(1) To agree to provide to the market monitoring unit all information and data requested by the market monitoring unit to perform its functions under these rules and the Independent Transmission Provider's tariff, and
(2) To agree to penalties specified in the Independent Transmission Provider's tariff for the violation of any tariff provisions.
(e) The market monitoring unit is responsible for administering the market power mitigation provisions of the Independent Transmission Provider's tariff.
(a) Each Independent Transmission Provider must ensure that the level of planned regional resources for a future year (the last year of the planning horizon) is adequate. Annually, each Independent Transmission Provider must:
(1) Perform an electric energy demand forecast for the last year of the planning horizon;
(2) Apportion the regional resource adequacy requirement for the last year of the planning horizon among the load serving entities in its area on the basis of the ratio of their loads;
(3) Require each load-serving entity in its area to submit to the Independent Transmission Provider a plan (including generation, transmission and demand-side options) to meet the load-serving entity's share of the regional resource adequacy requirement for the last year of the planning horizon; and
(4) Ensure that each load-serving entity's electric energy resource plan meets standards approved by the Commission and is feasible, including ensuring that resources are not double counted by different load serving entities.
(b) This requirement shall replace installed capacity requirements approved by the Commission prior to [effective date of Standard Market Design Rule].
(a) Each Independent Transmission Provider shall keep on file with the Commission a regional transmission expansion plan.
(b) Each Independent Transmission Provider's regional transmission expansion plan shall, at a minimum:
(1) permit all market participants to participate equally in a facilitated process to identify transmission projects that would best serve the needs of the region; and
(2) require the Independent Transmission Provider to issue requests for proposals to address transmission planning needs identified through such a process.
(c) Independent Transmission Providers shall satisfy the provisions of § 35.34(k)(7) of this title no later than the date on which service commences under Standard Market Design.
The following Appendices will not be published in the Code of Federal Regulations.
Among the revisions that the Commission proposes to require the Transmission Provider to file are revisions to Sections 1.19, 13.5, 13.6, 14.2, 22.1(a), 28.2, 28.3, 33.2, 33.3, 33.5, and 33.7 to recognize that the preferences contained in the tariff for native load customers and for the Transmission Provider's use of its system have been eliminated. The changes are set forth below:
(a) Service provided over Secondary Receipt and Delivery Points will be non-firm only, on an as-available basis and will not displace any firm or non-firm service reserved or scheduled by third-parties under the Tariff.
In addition, the Commission proposes to require Transmission Providers to make the following changes to section 2 of the pro forma tariff:
Access Charge: A charge designed to recover the embedded costs of the Transmission System.
Ancillary Services: Those services that are necessary to support the transmission of Energy from Resources to Loads while maintaining reliable operation of the Independent Transmission Provider's Transmission System in accordance with Good Utility Practice.
Automatic Generation Control (``AGC''): The automatic regulation of the power output of electric generating facilities within a prescribed range in response to a change in system frequency, or tie-line loading, to maintain system frequency or scheduled interchange with other areas within predetermined limits.
Availability Bid: Bid by a Resource that indicates the minimum price at which Regulation or Operating Reserves is offered to be supplied.
Available Transfer Capability (``ATC''): A measure of the Transfer Capability remaining in the physical transmission network for further commercial activity over and above already committed uses. ATC is defined as the Total Transfer Capability, less the sum of existing transmission commitments (including transmission which is used for reliability purposes).
Base Point Signal: Signals sent from the Independent Transmission Provider and ultimately received by Resources specifying the scheduled MW level for the Resource.
Bid: Offer to purchase and/or sell products or services in an Auction, including Energy, Demand Reductions, Transmission Service, Congestion Revenue Rights and/or Ancillary Services at a specified location, quantity, and time-period that is duly submitted to the Independent Transmission Provider pursuant to Independent Transmission Provider Procedures. The Bid should indicate either a specific price or the Bidder's desire to have the Bid accepted regardless of the market clearing price.
Bid Revenue Sufficiency Guarantee: A guarantee by the Independent Transmission Provider that ensures the minimum recovery of the Bid prices for Resources scheduled through the Day-Ahead Market, in subsequent post Day-Ahead Market commitments for reliability, and in the Real-Time Market.
Bilateral Transaction Schedule: Simultaneous schedules of Load and Generation of the same MW level by a Market Participant.
Boundary Interface: Point(s) used to indicate Point(s) of Receipt and Point(s) of Delivery outside of the Service Area.
Commission (``FERC''): The Federal Energy Regulatory Commission, or any successor agency.
Completed Application: An application for Transmission or Market Service that satisfies all of the information and other requirements of the Tariff, including any required deposit.
Congestion: The state of a Transmission System when a binding limit (constraint) on the system's Transfer Capability is reached that must be addressed.
Congestion Charges: Charges relating to the Marginal Congestion Component of Energy Purchases or Transmission Usage Charges. These charges reflect the increased cost that result from dispatching the Transmission System to respect Transmission System (or Flowgate) constraints.
Congestion Revenue Deficit: In the Day-Ahead Market, the absolute value of the difference between the Hourly Congestion Charge Collection and the Hourly Net Congestion Revenue Owed to Congestion Revenue Rights Holders when the difference is negative.
Congestion Revenue Right: A property right held by a Customer that entitles and/or obligates the holder of the right to receive specified Congestion revenues.
Congestion Revenue Surplus: In the Day-Ahead Market, the difference between the Hourly Congestion Charge Collection and the Hourly Net Congestion Revenue Owed to Congestion Revenue Rights Holders when the difference is positive.
Contingency: An actual or potential unexpected failure or outage of a system component, such as a Generator,
Control Center: The equipment, facilities and personnel used by the Independent Transmission Provider to coordinate and direct the operation of the Service Area and to administer the Day-Ahead and Real-Time Markets, including facilities and equipment used to communicate and coordinate with the Market Participants in connection with transactions in the Day-Ahead and Real-Time Markets or the operation of the Service Area.
Curtailment: Reduced transmission service or provision of electricity to a Customer in response to a transmission capability for reliability purposes.
Customer: An entity which has complied with the requirements contained in this Tariff, including having signed a Service Agreement, and is eligible to utilize the services provided by the Independent Transmission Provider under this Tariff; provided, however, that a party taking services under this Tariff pursuant to an unsigned Network Access Service Agreement filed with the Commission by the Independent Transmission Provider shall be deemed a Customer.
Day-Ahead: Nominally, the twenty-four hour period directly preceding the Operating Day, except when this period may be extended by the Independent Transmission Provider to accommodate holidays and weekends.
Day-Ahead Market: The market administered by the Independent Transmission Provider in which Energy, Ancillary Services, and Transmission Services are scheduled and sold Day-Ahead, consistent of the Day-Ahead scheduling process, price calculations, and settlements.
Decremental Energy Bid: A Bid Price curve provided by an entity engaged in a bilateral Import or Internal Transaction to indicate the LMP below which that entity is willing to reduce its Generator's output and purchase Energy in the LMP Markets.
Delivering Party: The entity supplying capacity and Energy to be transmitted at Point(s) of Receipt.
Delivery Point: The location where a transaction terminates. A Delivery Point can be a delivery Node, an aggregation of delivery Nodes, an Interface, or a Trading Hub. For purposes of this Tariff, the Delivery Point does not have to be a location where power is consumed.
Direct Assignment Facilities: Facilities or portions of facilities that are constructed for the sole use/benefit of a particular Customer requesting service under the Tariff. Direct Assignment Facilities shall be specified in the Service Agreement that governs service to the Customer and shall be subject to Commission approval.
Dispatch Hour: The sixty (60) minute period commencing at the beginning of each hour (0000 hour).
Dispatch Interval: Length of time between dispatch instructions from the Independent Transmission Provider.
Emergency: Any abnormal system condition that requires immediate automatic or manual action to prevent or limit loss of transmission facilities or Generators that could adversely affect the reliability of the electric system.
Energy: A quantity of electricity that is Bid, produced, purchased, consumed, sold or transmitted over a period of time and measured or calculated in megawatt-hours.
Energy Bid: For an Energy Supplier, a Bid curve that indicates an entity's willingness to supply Energy at certain prices to markets operated by the Independent Transmission Provider. For an Energy Purchaser, Bid curve that indicates an entity's willingness to purchase Energy at certain prices in markets operated by the Independent Transmission Provider.
Energy Limited Resource: Capacity Resources that, due to design considerations, environmental restrictions on operations, cyclical requirements, such as the need to recharge or refill, or other non-economic reasons, are unable to operate continuously on a daily basis.
Ex Ante Real-Time Energy LMP: The LMP that is produced by the Independent Transmission Provider's Security Constrained Dispatch and communicated to Resources under dispatch instructions in advance of real time. Under SMD, the LMP used for settlement is the Ex Post LMP.
Ex Post Real-Time Energy LMP: The LMP that is produced following the evaluation of actual dispatch relative to dispatch instructions. It is the LMP used for settlement purposes in the Real-Time Market.
Existing Transmission Contract: A contract for Transmission Service or wholesale requirements service currently in effect between two or more Transmission Owners, or between a Transmission Owner and another entity, that was executed on or before July 9, 1996, or earlier.
Export: Energy that is delivered from the Independent Transmission Provider Service Area Interconnection to another Service Area.
External Transaction: A Bilateral Transaction in which either the Receipt Point or the Delivery Point must be a point at the boundary of the Independent Transmission Provider Service Area. If the Receipt Point is a Boundary Interface, then the External Transaction is an Import. If the Delivery Point is a Boundary Interface, then the External Transaction is an Export.
Facilities Study: An engineering study conducted by the Independent Transmission Provider to determine the required modifications to the Independent Transmission Provider's Transmission System, including the cost and scheduled completion date for such modifications, that will be required to provide the requested transmission service.
Federal Power Act (“FPA”): The Federal Power Act, as may be amended from time-to-time (See 16 U.S.C. § 796 et seq.)
Fixed Block Resource: A unit that, due to operational characteristics, can only be in one of two states: either turned completely off, or turned on and run at a fixed capacity level.
Flowgate: A transmission facility (such as a transmission line or a transformer or some other component of the electrical network) or group of facilities (
Flowgate Right: A Congestion Revenue Right specified by a portion of the total MW capacity over a particular transmission Flowgate in a specified direction. Flowgate Rights entitle the holder to collect congestion revenues associated with the specified MW flow over the identified Flowgate in the specified direction.
Generation Capacity: The sustained maximum net output of a Generator, measured in megawatts, as demonstrated by the performance of a test or through actual operation as defined in the Independent Transmission Provider Procedures.
Generator: A facility capable of supplying Energy, capacity and/or Ancillary Services that is accessible to the Service Area.
Good Utility Practice: Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region.
Hourly Economic Maximum Level: The maximum MW level a Resource may operate under normal system conditions.
Hourly Economic Minimum Level: The minimum MW level a Resource may operate under normal system conditions.
Hourly Emergency Maximum Level: The maximum MW level a Resource may operate under Emergency system conditions.
Hourly Emergency Minimum Level: The maximum MW level a Resource may operate under Emergency system conditions.
Hub: A mathematical simplification of a set of buses to emulate a single bus for financial and trading purposes. A Hub is defined by a set of buses that are each associated with a fixed numerical weights such that the sum of weights equal one.
Hub Price: The weighted average of Energy LMP's at the buses that comprise the Hub.
Import: Energy that is delivered to an Independent Transmission Provider Service Area Interconnection from another Service Area.
Incremental Energy Bid: A Bid Price curve for Energy generated above the Hourly Minimum Economic Level.
Independent Transmission Provider: The entity that operates the facilities used for the transmission of Energy in interstate commerce and provides transmission service under the Tariff.
Independent Transmission Provider's Monthly Transmission System Peak: The maximum usage of the Independent Transmission Provider's Transmission System in a calendar month.
Interface: A defined set of transmission facilities (see also Boundary Interface).
Internal Transaction: Bilateral Transactions whose Receipt Point and Delivery Point are both within the Independent Transmission Provider's service territory.
Load: A term that refers to either a consumer of Energy or the amount of Energy (MWh) or demand (MW) consumed.
Load Forecast: Independent forecasts by the Independent Transmission Provider of Load within the Independent Transmission Provider's Service Area used in its scheduling decisions to ensure reliable operation of the system.
Load Ratio Share: The ratio of a Load-Serving Entity's Load to total Load within the Service Area during a specified time period.
Load-Serving Entity: An entity, including a municipal electric system and an electric cooperative, authorized by law, regulatory authorization or requirement, agreement, or contractual obligation to supply Energy, to retail Customers located within the Independent Transmission Provider's Service Area, including an entity that takes service directly from the Independent Transmission Provider to supply its own Load in the Independent Transmission Provider's Service Area.
Load Shedding: The systematic reduction of system demand by temporarily decreasing Load in response to Transmission System or area capacity shortages, system instability, or voltage control considerations.
Locational Marginal Pricing (“LMP”): A pricing methodology under which the price of Energy at each location in the Transmission System is equivalent to the cost to supply or the value to purchase the next increment of Load at that location taking into account the physical aspects of the Transmission System. The term LMP also refers to the price of Energy bought or sold at a specific location.
Lower Regulation Limit: The lowest operating point that the Independent Transmission Provider may dispatch a unit for Regulation under normal operating conditions.
Marginal Congestion Component (“MCC”): Component of Locational Marginal Price and Transmission Usage Charge reflecting the cost of dispatching the Resources available to the Independent Transmission Provider such that transmission constraints are respected.
Marginal Loss Charge Collection: The net amounts charged to purchasers associated with the Marginal Loss Component of the hourly LMPs at the purchasers' buses less the net amounts paid to sellers associated with the Marginal Loss Component of the hourly LMPs at the sellers' buses.
Marginal Losses: The Transmission System Real Power Losses associated with each additional MWh of consumption by Load, or each additional MWh transmitted under a Bilateral Transaction as measured at the Points of Withdrawal.
Marginal Losses Component (“MLC”): The component of LMP at a bus that accounts for the Marginal Losses, as measured between that bus and the Reference Bus.
Market Clearing Price: The price of a product or service determined by the Independent Transmission Provider at a given location and time at which the total amounts offered for sale and purchase are equal.
Market Monitor(ing Unit): Entity required to report directly to the Commission and to the independent governing board of the Independent Transmission Provider the results and recommendations derived from its study of the markets operated by the Independent Transmission Provider.
Market Services: Services provided by the Independent Transmission Provider under the Tariff related to the markets for Energy, capacity and Ancillary Services.
Maximum Curtailment Time: Maximum time (in hours) that a supplier of demand response Resources is willing to respond to Curtailment dispatch instructions.
Maximum Run Time: Maximum length of time (in hours) that a Generator can be reliably expected to operate.
Maximum Shut Down Limit: Maximum number of times a Generator is able to shut down in a 24 period.
Maximum Start-up Limit: Maximum number of times a Generator is able to start-up in a 24 period.
Minimum Curtailment Time: Minimum time (in hours) that a supplier of demand response Resources is willing to respond to Curtailment dispatch instructions.
Minimum Down Time: Minimum length of time (in hours) required for a Generator to begin operations following an outage due to operational constraints.
Minimum Generation Bid: The payment required by a Supplier to operate at the unit's Hourly Economic Minimum.
Minimum Generation Emergency: An Emergency declared by the Independent Transmission Provider in which the Independent Transmission Provider anticipates requesting one or more generating Resources to operate at or below Normal Minimum Generation, in order to manage, alleviate, or end the Emergency.
Minimum Run Time: Minimum length of time (in hours) required for a Generator to be in operation due to operational constraints.
Network Access Service: Transmission service offered by the Independent Transmission Provider under this Tariff. It offers use of the transmission grid by allowing Customers to: (1) Serve Load with any Resource on the system, (2) access any Interface to import power from a neighboring system, (3) integrate, economically dispatch and regulate its current and planned Resources to serve its Load; (4) transmit power through and out of the Independent Transmission Provider's system, and (5) aggregate Resources for resale and hub-to-hub transfer.
Network Operating Agreement: Agreement that contains the terms and conditions under which the Customer shall operate its facilities and the technical and operational matters associated with the implementation of the Tariff.
Network Operating Committee: Committee responsible for coordinating operating criteria to determine each Party's responsibilities under the Network Operating Agreement.
No-load Cost: Hourly costs associated with generating at a unit's Hourly Economic Minimum.
Node: A location where Energy can be injected and/or withdrawn from the grid.
Normal Response Rate: The expected response rate of an Energy supplying Resource measured in MW/min.
Obligation Right: A Congestion Revenue Right that requires the Customer to receive the Congestion revenues (either positive or negative).
Open Access Same-Time Information System (OASIS): The information system and standards of conduct contained in Part 37 of the Commission's regulations and all additional requirements implemented by subsequent Commission orders dealing with OASIS.
Operable Capacity: Capacity that is readily converted to Energy and is measured in MW.
Operating Day: The daily 24 hour period beginning at midnight for which transactions on the Energy Market are scheduled.
Operating Reserves: Generator Capacity that is available to supply Energy, or Load Resources that are available to Curtail Energy usage, in the event of Contingency conditions, which meet the requirements of the Independent Transmission Provider. Operating Reserves include Spinning Reserves and Supplemental Reserves.
Opportunity Cost: The cost of giving up the opportunity to sell (or consume) a product (or service) at a location and time in order to sell a related product (requiring the same inputs), at the same location and time or the same product at another location and time.
Optimal Power Flow (“OPF”): A Power Flow that maximizes the value (as expressed in the Bids) of the Congestion Revenue Rights, subject to the constraint that the selected set of Bids must be simultaneously feasible.
Option Right: A Congestion Revenue Right that allows the Customer to receive the positive Congestion revenues without the obligation to pay Congestion revenues when they are negative.
Planning Horizon: The number of years ahead in each region for which the Load-Serving Entities must demonstrate to the Independent Transmission Provider that they have procured adequate Energy Resources.
Power Flow: A simulation tool that provides an estimate of Energy flows on the Transmission System and adjacent transmission systems under a given set of assumed characteristics.
Primary Holder: The Owner of a Congestion Revenue Right recognized as such by the Independent Transmission Provider for settlement purposes.
Real Power Losses: The loss of Energy, resulting from transporting power over the Transmission System, between the Point of Injection and Point of Withdrawal of that Energy.
Real Time: Referring to the time period in which transmission and generation dispatch instructions are ultimately given.
Real-Time Market: The market administered by the Independent Transmission Provider for Energy, Ancillary Services, and Transmission Services in real time, consisting of the real time scheduling process, dispatch, price calculations, and settlements.
Receipt Point: The location where a Transaction originates. A Receipt Point can be a Generator Node, an aggregation of Generator Nodes, an Interface, or a Trading Hub. For purposes of this Tariff, a Receipt Point does not have to be a Generator.
Receipt Point-to-Delivery Point Congestion Revenue Right Obligation: Congestion Revenue Rights that confer: (i) The right to collect revenues equal to the applicable Marginal Congestion Component of the hourly Transmission Usage Charge from the Receipt Point to the Delivery Point when the Marginal Congestion Component is positive, and (ii) the obligation to pay an amount to the Independent Transmission Provider equal to the absolute value of the applicable Marginal Congestion Component of the hourly Transmission Usage Charge when the Marginal Congestion Component is negative.
Receipt Point-to-Delivery Point Congestion Revenue Right Option: Congestion Revenue Rights that confer to the holder the right to collect revenues equal to the applicable Congestion Charge component of the hourly Transmission Usage Charge from the Receipt Point to the Delivery Point when the Marginal Congestion Component is positive, but do not obligate the holder to pay the absolute value of the applicable Marginal Congestion Component of the hourly Transmission Usage Charge when the Marginal Congestion Component is negative.
Receiving Party: The entity receiving the capacity and Energy transmitted by the Independent Transmission Provider to Point(s) of Delivery.
Reference Bus: The location on the Transmission System relative to which all mathematical quantities, including Shift Factors and penalty factors relating to physical operation, will be calculated.
Regulation: The capability of a specific generating unit with appropriate telecommunications, control and response capability to increase or decrease its output in response to a regulating control signal, in accordance with the specifications in the Manuals. Regulation also encompasses regulation and frequency response service i.e. the continuous balancing of Resources (generation and interchange) with Load variations in order to maintain scheduled Interconnection frequency.
Regulation Capability: The maximum amount of Regulation Service in MW a Resource can operationally provide to the Independent Transmission Provider.
Regulation Requirement: Quantity of Regulation identified by the local reliability authority to be procured by the Independent Transmission Provider to ensure system reliability.
Reliability Rules: Those rules, standards, procedures and protocols, including Local Reliability Rules, developed in accordance with NERC, regional reliability councils, FERC, PSC and NRC standards, rules and regulations, and other criteria.
Reserve Location: Geographic area for which there is a specific Operating Reserve requirement applies.
Resource: Either a Generator or a Load that can reliably adjust its electricity usage by some specified range and rate at a specific Withdrawal Point in response to Day-Ahead or Real-Time prices or by instruction by the Independent Transmission Provider.
Resource Adequacy Requirement: The Resource reserve margin, stated as a ratio of the reserves to the forecast peak load during the final year of the Planning Horizon, expressed as a percentage.
Response Rate: The capability (in MW/minute) of a Resource to adjust its generation level in response to dispatch signals.
Scheduled Amount: Megawatt supply or demand obligation as indicated by the Independent Transmission Provider's Schedule.
Scheduled Resource: Resource incurring a supply or demand obligation as indicated by the Independent Transmission Provider's Schedule.
Security Constrained Dispatch: The determination of the dispatch that incorporates all transmission constraints necessary for reliability.
Security Constrained Unit Commitment: The allocation of Load to Generators by the Independent Transmission Provider through the operation of a computer algorithm which continuously calculates individual Generator loading at minimum Bid cost, balancing Load and scheduled interchange with generation while meeting all reliability rules and Generator performance constraints.
Self-Schedule: The Supplier's provision to the Independent Transmission Provider with its hourly Energy schedule in the Day-Ahead Market and Real-Time Market independent of market prices.
Self-Supply: The provision of certain Ancillary Services, or the provision of Energy to replace Marginal Losses, by a Customer using either the Customer's own Generators or generation obtained from an entity other than the Independent Transmission Provider.
Seller: Market Participant whose Bid to supply into either the Day-Ahead or Real-Time Market has been accepted and who has incurred the associated supply obligations.
Service Agreement: The initial agreement and any amendments or supplements thereto entered into by the Customer and the Independent Transmission Provider for service under the Tariff.
Service Area: The geographic region and transmission facilities therein that are under the operational control of the Independent Transmission Provider.
Service Commencement Date: The date the Independent Transmission Provider begins to provide service pursuant to the terms of an executed Service Agreement, or the date the Independent Transmission Provider begins to provide service in accordance with the Tariff.
Settlement: The process of determining the charges to be paid to or by a Customer in the markets operated by the Independent Transmission Provider under this Tariff.
Shift Factor: A ratio, calculated by the Independent Transmission Provider, that compares (1) the change in power flow through a transmission facility resulting from an incremental change in injection of power at a Receipt Point and withdrawal of power at the Delivery Point to (2) the incremental change in injection of power at the Receipt Point.
Shortage: A situation in which the markets for Energy, Regulation or Operating Reserves are not able to clear because of insufficient Bid-in capacity.
Spinning Reserves: Operating Reserves provided by synchronized Resources that can respond immediately to dispatch instructions.
Spinning Reserves Requirement: Quantity of Spinning Reserves identified by the local reliability authority to be procured by the Independent Transmission Provider to ensure system reliability.
Start Time: The number of hours required by a generating Resource to reach its Hourly Economic Minimum Level.
Start-up Cost: Payment needed by the Purchaser of Energy to cover the fixed costs associated with its Energy Bid or payment required by Generator to Start-up and reach its minimum operating level.
Supplemental Commitment: Scheduling of Resources by the Independent Transmission Provider following the posting of the Day-Ahead Schedule to meet the reliability needs.
Supplemental Reserves: Operating Reserves provided by Resources that can be started, synchronized and loaded within a specified time period.
Supplemental Reserves Requirement: Quantity of Supplemental Reserves identified by the local reliability authority to be procured by the Independent Transmission Provider to ensure system reliability.
Supplier: A Party that is supplying the Demand Reduction, Energy and/or associated Ancillary Services to be made available under the Tariff, including Generators and demand side Resources that satisfy all applicable Independent Transmission Provider requirements.
System Impact Study: An assessment by the Independent Transmission Provider of (i) the adequacy of the Transmission System to accommodate a request for Congestion Revenue Rights or (ii) whether any additional costs may be incurred in order to provide Congestion Revenue Rights.
System Marginal Price (SMP): The LMP of Energy at the Reference Bus.
Total Transfer Capability: The amount of electric power that can be transferred over the interconnected transmission network in a reliable manner.
Transaction: The purchase and/or sale of Energy, Congestion Revenue Rights, Ancillary Services, or Transmission Service.
Transfer Capability: The measure of the ability of interconnected electrical systems to reliably move or transfer power from a set of Receipt Points to a set of Delivery Points over all transmission facilities (or paths) between those areas under specified system conditions.
Transmission Owner: Entity with financial ownership of the transmission assets used in the provision of Transmission Service by the Independent Transmission Provider.
Transmission Owner's Monthly Transmission System Peak: The maximum hourly firm usage as measured in megawatts (MW) of the Transmission Owner's transmission system in a calendar month.
Transmission Planned Outage: Any transmission outage scheduled in advance for a pre-determined duration and which meets the notification requirements for such outages specified by the Independent Transmission Provider.
Transmission Service: Services needed to move Energy from a Receipt Point to a Delivery Point provided to Customers by the Independent Transmission Provider in accordance with this Tariff.
Transmission System: The facilities controlled and operated by the Independent
Transmission Usage Charge: A per unit charge for Transmission Service to support a Bilateral Transaction. The Transmission Usage Charge is equal to the difference of the LMP at the Delivery Point and the LMP at the Receipt Point (in $/MWh).
Unit-Specific Opportunity Cost: The Opportunity Cost calculation for specific Resources that are selected to provide Regulation or Operating Reserves in either the Day-Ahead or the Real-Time Markets.
Upper Regulation Limit: The highest operating point that the Independent Transmission Provider will dispatch a unit for Regulation under normal operating conditions.
Virtual Demand Bid: A Demand Bid in the Day-Ahead Market without a physical Resource capable of withdrawing Energy in the Real-Time Market.
Virtual Energy: Energy purchased or sold in the Day-Ahead Energy Market that is not backed by physical Resources.
Virtual Supply Bid: A Supply Bid in the Day-Ahead Market without a physical Resource capable of injecting Energy in the Real-Time Market.
Voltage Support Service: The provision of reactive power support necessary to maintain transmission voltage.
Wheel Through: Transmission Service through the Service Area of the Independent Transmission Provider that originates and terminates outside the Service Area of the Independent Transmission Provider.
Zonal-LMP: Load weighted average of Energy LMPs over a set of buses and weights defined by a zone.
Zone: A set of buses in a geographic area.
Zone Price: Load weighted average price over the defined set of buses in a zone.
Terms and conditions regarding Open Access Same-Time Information System and standards of conduct are set forth in 18 CFR § 37 of the Commission's regulations (Open Access Same-Time Information System and Standards of Conduct for Public Utilities).
3.1 Transmission Owners That Own Facilities Financed by Local Furnishing Bonds: This provision is applicable only to Transmission Owners that have financed facilities for the local furnishing of Energy with tax-exempt bonds, as described in section 142(f) of the Internal Revenue Code of 1986, as amended, or corresponding provisions of predecessor statutes (“local furnishing bonds''). Notwithstanding any other provision of this Tariff, the Independent Transmission Provider shall not be required to provide transmission service to any Customer pursuant to this Tariff if the provision of such transmission service would jeopardize the tax-exempt status of any local furnishing bond(s) used, in whole or in part, to finance the Transmission Owner's facilities, regardless of whether such facilities financed with these bonds are transmission, distribution, or generation facilities.
3.2 Alternative Procedures for Requesting Transmission Service:
(i) If the Independent Transmission Provider determines that the provision of transmission service requested by a Customer would jeopardize the tax-exempt status of any outstanding local furnishing bond(s) used, in whole or part, to finance any of the Transmission Owner's facilities, regardless of whether such facilities financed with these bonds are transmission, distribution, or generation facilities, or would jeopardize the Transmission Owner's entitlement to income tax deductions for interest expense in connection with such tax-exempt bonds, it shall advise the Customer within thirty (30) days of receipt of the Completed Application of (a) such determination and (b) the reasonably expected amount of any costs resulting from such loss of tax-exempt status and/or income tax deductions (or from the prevention of any such loss). For purposes of this section, the costs resulting from such loss of tax exempt status and/or income tax deductions (or from the prevention of any such loss) due to the provision of such transmission service shall include, without limitation, any reasonable transactions costs (including any redemption premium) of defeasing and/or redeeming any outstanding local furnishing bonds and/or from any such refinancing with taxable debt and/or from any disallowance or loss of a deduction for tax purposes of the interest in respect of such bonds.
(ii) If the Customer thereafter renews its request for the same transmission service referred to in (i) by tendering an application under Section 211 of the Federal Power Act, the Independent Transmission Provider, within ten (10) days of receiving a copy of the Section 211 application, will waive its rights to a request for service under Section 213(a) of the Federal Power Act and to the issuance of a proposed order under Section 212(c) of the Federal Power Act. The Commission, upon receipt of the Independent Transmission Provider's waiver of its rights to a request for service under Section 213(a) of the Federal Power Act and to the issuance of a proposed order under Section 212(c) of the Federal Power Act, shall issue an order under Section 211 of the Federal Power Act specifying that such service is provided subject to the Customer's payment of all costs deemed by the Commission to be eligible for recovery under Section 212(a) of the Federal Power Act. Upon issuance of the order under Section 211 of the Federal Power Act, the Independent Transmission Provider shall be required to provide the requested transmission service in accordance with the terms and conditions of this Tariff and such order. Transmission service shall not commence until after the Customer complies with the creditworthiness provisions of Section 8 of this Tariff.
A Customer receiving transmission service under this Tariff agrees to provide comparable transmission service that it is capable of providing on similar terms and conditions over facilities used for the transmission of Energy owned, controlled or operated by the Customer and over facilities used for the transmission of Energy owned, controlled or operated by the Customer's corporate affiliates. A Customer that is a member of a power pool or Regional Transmission Group also agrees to provide comparable transmission service to the members of such power pool and Regional Transmission Group on similar terms and conditions over facilities used for the transmission of Energy owned, controlled or operated by the Customer and over facilities used for the transmission of Energy owned, controlled or operated by the Customer's corporate affiliates.
This reciprocity requirement applies not only to the Customer that obtains transmission service under the Tariff, but also to all parties to a transaction that involves the use of transmission service under the Tariff, including the power seller, buyer and any intermediary, such as a power marketer. This reciprocity requirement also applies to any Customer that owns, controls or operates transmission facilities that uses an intermediary, such as a power marketer, to request transmission service under the Tariff. If the Customer does not own, control or operate transmission facilities, it must include in its Application a sworn statement of one of its duly authorized officers or other representatives that the purpose of its Application is not to assist a Customer to avoid the requirements of this provision.
5.1 Billing Procedure: Within a reasonable time after the first day of each month, the Independent Transmission Provider shall submit an invoice to the Customer for the charges for all services furnished under the Tariff during the preceding month. The invoice shall be paid by the Customer within twenty (20) days of receipt. All payments shall be made in immediately available funds payable to the Independent Transmission Provider, or by wire transfer to a bank named by the Independent Transmission Provider.
5.2 Interest on Unpaid Balances: Interest on any unpaid amounts (including amounts placed in escrow) shall be calculated in accordance with the methodology specified for interest on refunds in the Commission's regulations at 18 CFR § 35.19a(a)(2)(iii). Interest on delinquent amounts shall be calculated from the due date of the bill to the date of payment. When payments are made by mail, bills shall be considered as having been paid on the date of receipt by the Independent Transmission Provider.
5.3 Customer Default: In the event the Customer fails, for any reason other than a billing dispute as described below, to make payment to the Independent Transmission Provider on or before the due date as described above, and such failure of payment is not corrected within thirty (30) calendar days after the Independent Transmission Provider notifies the Customer to cure such failure, a default by the Customer shall be deemed to exist. Upon the occurrence of a default, the Independent Transmission Provider may initiate a proceeding with the Commission to terminate service but shall not terminate service until the Commission so approves any such request. In the event of a billing dispute between the Independent Transmission Provider and the Customer, the Independent Transmission Provider will
Nothing contained in the Tariff or any Service Agreement shall be construed as affecting in any way the right of the jurisdictional Independent Transmission Provider to unilaterally make application to the Commission for a change in rates, terms and conditions, charges, classification of service, Service Agreement, rule or regulation under Section 205 of the Federal Power Act and pursuant to the Commission's rules and regulations promulgated thereunder.
Nothing contained in the Tariff or any Service Agreement shall be construed as affecting in any way the ability of any Party receiving service under the Tariff to exercise its rights under the Federal Power Act and pursuant to the Commission's rules and regulations promulgated thereunder.
7.1 Force Majeure: An event of Force Majeure means any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, any Curtailment, order, regulation or restriction imposed by governmental military or lawfully established civilian authorities, or any other cause beyond a Party's control. A Force Majeure event does not include an act of negligence or intentional wrongdoing. Neither the Independent Transmission Provider nor the Customer will be considered in default as to any obligation under this Tariff if prevented from fulfilling the obligation due to an event of Force Majeure. However, a Party whose performance under this Tariff is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations under this Tariff.
7.2 Indemnification: The Customer shall at all times indemnify, defend, and save the Independent Transmission Provider harmless from, any and all damages, losses, claims, including claims and actions relating to injury to or death of any person or damage to property, demands, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting from the Independent Transmission Provider's performance of its obligations under this Tariff on behalf of the Customer, except in cases of negligence or intentional wrongdoing by the Independent Transmission Provider.
For the purpose of determining the ability of the Customer to meet its obligations related to service hereunder, the Independent Transmission Provider may require reasonable credit review procedures. This review shall be made in accordance with standard commercial practices. In addition, the Independent Transmission Provider may require the Customer to provide and maintain in effect during the term of the Service Agreement, an unconditional and irrevocable letter of credit as security to meet its responsibilities and obligations under the Tariff, or an alternative form of security proposed by the Customer and acceptable to the Independent Transmission Provider and consistent with commercial practices established by the Uniform Commercial Code that protects the Independent Transmission Provider against the risk of non-payment.
In order to purchase Network Access Service, purchase or supply Energy, or to supply Ancillary Services in the Independent Transmission Provider Administered Markets, Customers must satisfy the requirements of this Article.
9.1 Requirements for Network Access Service: A Customer eligible for Network Access Service is: (i) any electric utility (including the Load-Serving Entity or any power marketer), Federal power marketing agency, or any person generating Energy for sale is eligible to be a Customer for Network Access Service under the Tariff. Energy sold or produced by such entity may be Energy produced in the United States, Canada or Mexico. However, with respect to transmission service that the Commission is prohibited from ordering by Section 212(h) of the Federal Power Act, such entity is eligible only if the service is provided pursuant to a state requirement that the Independent Transmission Provider offer the unbundled transmission service, or pursuant to a voluntary offer of such service by the Independent Transmission Provider. (ii) Any retail Customer taking unbundled transmission service pursuant to a state requirement that the Independent Transmission Provider offer the transmission service, or pursuant to a voluntary offer of such service by the Independent Transmission Provider, is eligible to be a Customer under the Tariff.
9.2 Requirements for Market Services: The Independent Transmission Provider and each market participant shall execute a Service Agreement for Market Services which sets forth the terms and conditions under which a market participant shall either supply or purchase market services, consistent with the Form of Service Agreement for Market Services in Part VII.
9.3 Participating Generator Agreements: The Independent Transmission Provider and the owners of each Generator shall enter into a Participating Generator Agreement which shall be filed with the Commission. Each Participating Generator Agreement shall set forth the operating terms, conditions, and obligations concerning the dispatch of a generating unit.
9.4 Requirements Common to All Customers: Completed Application and Minimum Technical Requirements
A Customer shall submit a Completed Application and shall receive Independent Transmission Provider approval prior to obtaining any services under the Independent Transmission Provider's Tariff. A Customer also shall demonstrate to the Independent Transmission Provider's reasonable satisfaction that it is capable of performing all functions required by the Independent Transmission Provider's Tariff including operational, financial and settlement requirements.
9.4.1 Application: Each Customer requesting to schedule, take or provide any services under the Tariff must apply to the Independent Transmission Provider in writing at least sixty (60) days in advance of the month in which service is to commence. The Independent Transmission Provider will consider requests for such services on shorter notice when feasible. Service commencement will depend on the Independent Transmission Provider's ability to accommodate the request. To apply, the Customer shall complete and deliver a Service Agreement (in the form of Part VII) and an Application to the Independent Transmission Provider.
9.4.2 Completed Application: A Completed Application shall provide all of the information reasonably required by the Independent Transmission Provider to permit the Independent Transmission Provider to perform its responsibilities under the Independent Transmission Provider's Tariff. A Customer taking or providing service under the Tariff shall provide the Independent Transmission Provider, upon application for service, with a list identifying its parent company as well as any affiliate. The Customer shall notify the Independent Transmission Provider within 30 days of the effective date of any change to the original list. Any Customer shall notify the Independent Transmission Provider within 30 days of the effective date of any change to the original list. Any Customer shall respond within 10 days to a request by the Independent Transmission Provider to update the list of affiliates and/or parent company. The Independent Transmission Provider shall treat the information provided in the Application as Confidential Information except to the extent that disclosure of the information is required by the Independent Transmission Provider's Tariff, by regulatory or judicial order or for reliability purposes pursuant to Good Utility Practice.
9.4.3 Approval of Application and/or Notice of Deficient Application:
The Independent Transmission Provider will promptly review the Application and may request additional information to determine whether the applicant meets the Independent Transmission Provider's minimum financial and technical requirements. The Independent Transmission Provider will notify the applicant within thirty (30) days of receipt of a Completed Application.
If the Independent Transmission Provider rejects an Application, the Independent Transmission Provider shall provide a written explanation within fourteen (14) days of the rejection. The Independent Transmission Provider will attempt to remedy minor deficiencies in the Application through informal communications with the
10.1 Internal Dispute Resolution Procedures: Any dispute between a Customer and the Independent Transmission Provider involving transmission or Market Services under the Tariff (excluding applications for rate changes or other changes to the Tariff, or to any Service Agreement entered into under the Tariff, which shall be presented directly to the Commission for resolution) shall be referred to a designated senior representative of the Independent Transmission Provider and a senior representative of the Customer for resolution on an informal basis as promptly as practicable. In the event the designated representatives are unable to resolve the dispute within thirty (30) days [or such other period as the Parties may agree upon] by mutual agreement, such dispute may be submitted to arbitration and resolved in accordance with the arbitration procedures set forth below.
10.2 External Arbitration Procedures: Any arbitration initiated under the Tariff shall be conducted before a single neutral arbitrator appointed by the Parties. If the Parties fail to agree upon a single arbitrator within ten (10) days of the referral of the dispute to arbitration, each Party shall choose one arbitrator who shall sit on a three-member arbitration panel. The two arbitrators so chosen shall within twenty (20) days select a third arbitrator to chair the arbitration panel. In either case, the arbitrators shall be knowledgeable in electric utility matters, including electric transmission and bulk power issues, and shall not have any current or past substantial business or financial relationships with any party to the arbitration (except prior arbitration). The arbitrator(s) shall provide each of the Parties an opportunity to be heard and, except as otherwise provided herein, shall generally conduct the arbitration in accordance with the Commercial Arbitration Rules of the American Arbitration Association and any applicable Commission regulations or Regional Transmission Group rules.
10.3 Arbitration Decisions: Unless otherwise agreed, the arbitrator(s) shall render a decision within ninety (90) days of appointment and shall notify the Parties in writing of such decision and the reasons therefor. The arbitrator(s) shall be authorized only to interpret and apply the provisions of the Tariff and any Service Agreement entered into under the Tariff and shall have no power to modify or change any of the above in any manner. The decision of the arbitrator(s) shall be final and binding upon the Parties, and judgment on the award may be entered in any court having jurisdiction. The decision of the arbitrator(s) may be appealed solely on the grounds that the conduct of the arbitrator(s), or the decision itself, violated the standards set forth in the Federal Arbitration Act and/or the Administrative Dispute Resolution Act. The final decision of the arbitrator must also be filed with the Commission if it affects jurisdictional rates, terms and conditions of service or facilities.
10.4 Costs: Each Party shall be responsible for its own costs incurred during the arbitration process and for the following costs, if applicable:
(A) the cost of the arbitrator chosen by the Party to sit on the three member panel and one half of the cost of the third arbitrator chosen; or
(B) one half the cost of the single arbitrator jointly chosen by the Parties.
10.5 Rights Under the Federal Power Act: Nothing in this section shall restrict the rights of any party to file a Complaint with the Commission under relevant provisions of the Federal Power Act.
11.1 Customer Requirements: The Independent Transmission Provider shall establish metering specifications and standards for all metering that is used as a data source by the Independent Transmission Provider. Customers shall install and maintain such metering at their own expense and deliver data to the Independent Transmission Provider without charge. A Customer taking service under the Independent Transmission Provider's Tariff will make available to the Independent Transmission Provider metered data that meets Independent Transmission Provider requirements by one of the following means: (i) Direct transmission to the Independent Transmission Provider; (ii) direct transmission to the Independent Transmission Provider through Transmission Owner communications equipment, or (iii) indirectly through metering provided by the Transmission Owner within whose area its Load is located. The Customer also shall provide its metered data to the Transmission Owner within whose area its Load is located, to the extent that the Transmission Owner determines that the metered data provided to the Independent Transmission Provider is required for its system operation and planning functions, for the billing of services it provides to the Customer, or to perform calculations required by the Independent Transmission Provider.
11.2 Load-Serving Entities: Any Load that is not directly metered, as described above, will have its Load determined by the Transmission Owner within whose area its Load is located in accordance with the Transmission Owner's Retail Access plan on file with the (state commission) or otherwise authorized.
11.3 Ancillary Service Suppliers: Suppliers shall ensure that adequate metering data is made available to the Independent Transmission Provider as described above.
11.4 Third Party Metering Services: Customers whose metering services are provided by third parties qualified under rules, regulations and procedures of applicable state regulatory authorities shall be responsible to ensure that all data described in this Section are satisfactorily made available to the Independent Transmission Provider and applicable Transmission Owner(s) by those third parties.
11.5 Estimation of Metering: In the event of a meter malfunction or inadequate metering data, the Independent Transmission Provider may use estimates to determine Customer's rights and responsibilities under the Independent Transmission Provider's Tariff.
12.1 Access to Complete and Accurate Data: Customers under the Tariff shall provide to the Independent Transmission Provider such information and data as the Independent Transmission Provider reasonably deems necessary in order to perform its functions and fulfill its responsibilities under the Tariff and in accordance with the Independent Transmission Provider Market Monitoring Program. Such information will be provided on a timely basis and in the formats prescribed in the Independent Transmission Provider Procedures.
12.2 Independent Transmission Provider Procedures: The Independent Transmission Provider shall develop, and modify as appropriate, procedures for the efficient and non-discriminatory operation of the Independent Transmission Provider Administered Markets and for the safe and reliable operation of the Independent Transmission Provider's Service Area in accordance with the terms and conditions of the Tariff. All such procedures must be consistent with Good Utility Practice. Whenever requested by the Independent Transmission Provider, each Load-Serving Entity shall provide the Independent Transmission Provider with a forecast of the Loads for which it is responsible for the particular time period designated by the Independent Transmission Provider. Customers shall inform the Independent Transmission Provider of the Availability of Generators within the Independent Transmission Provider Service Area subject to a Customer's control by Energy contract, ownership or otherwise. Additionally, the Transmission Owners will provide megawatt, megavar, voltage readings, Transmission System data (facility ratings and impedance data), and maintenance schedules for all Transmission Facilities under the Independent Transmission Provider's Operational Control. For Transmission Facilities Requiring Independent Transmission Provider Notification, the Transmission Owners shall inform the Independent Transmission Provider of all changes in the status of the designated transmission facilities. Suppliers will provide data on Generator status and output including maintenance schedules, Generator scheduled return dates (inclusive of return to service from maintenance, forced outages or partial unit outages that resulted in a significant reduction in a generating unit's ability to produce Energy in any hour), and Generator machine data. These data shall also include Generator Incremental/Decremental Bids, operating limits, response rates, megawatt, megavar, and voltage readings.
12.3 Access to Confidential Information: The Independent Transmission Provider may request, and the Customer shall provide, Confidential Information consistent with the disclosure requirements set forth in the Independent Transmission Provider's Tariff. The Independent Transmission Provider
12.4 Use of Confidential Information: The Independent Transmission Provider shall use Confidential Information for the exclusive purpose of performing its obligations hereunder and under any Service Agreement.
12.5 Disclosure of Bid Information: Pursuant to Commission requirements, the Independent Transmission Provider shall make public Bid information from the Energy, Ancillary Services, and Transmission markets (but not the names of the Bidders making these Bids) three months after the Bids are submitted. The Independent Transmission Provider shall post the data in a way that permits third parties to track each individual Bidder's Bids over time. Prior to such disclosure, Bid information submitted to the Independent Transmission Provider by Market Participants shall be considered Confidential Information.
12.6 Survival: This section 12 will survive the termination of the Independent Transmission Provider's Tariff and any associated Service Agreement.
The Independent Transmission Provider will provide Network Access Service pursuant to the applicable terms and conditions contained in the Tariff and Service Agreement. Network Access Service allows all Customers to access all points (
1.1 Scope of Service: Network Access Service allows all Customers to access all points (
1.2 Independent Transmission Provider Responsibilities: The Independent Transmission Provider shall plan, construct, operate and maintain its Transmission System in accordance with Good Utility Practice in order to provide all Customers with Network Access Service over the Independent Transmission Provider's Transmission System. The Independent Transmission Provider shall endeavor to have constructed and placed into service sufficient transmission capability to deliver all Network Access Service Customers' Resources to serve Load. The Independent Transmission Provider will offer a mechanism for participants to identify long-term planning and expansion needs and to propose solutions (transmission, generation, or demand-side).
1.3 Service at Points without Concurrent Congestion Revenue Rights: Once a Customer agrees to pay the applicable Access Charge, it may use the Independent Transmission Provider's Transmission System to deliver Energy to its Network Loads from Resources when the Customer does not have Congestion Revenue Rights between the requested Receipt and Delivery Points. Such Energy shall be transmitted subject to the Customer paying the applicable Transmission Usage Charge. A Customer may revise or add Receipt Points or Delivery Points without an additional Access Charge.
2.1 Condition Precedent for Receiving Service: A request for Network Access Service may be performed under an umbrella Service Agreement pursuant to Part VII of the Tariff. A request for Network Access Service must contain a written Application to: [the Independent Transmission Provider Name and Address], submitted at least sixty (60) days in advance of the calendar month in which service is to commence. The Independent Transmission Provider will consider requests for such service on shorter notice when feasible. Requests for Network Access Service for periods of less than one year shall be subject to expedited procedures that shall be negotiated between the Parties within the time constraints provided in Section B.2.8.
2.2 Application Procedures: A Customer requesting Network Access Service must submit an Application, with a deposit approximating the charge for one month of service, to the Independent Transmission Provider as far as possible in advance of the month in which service is to commence. Applications should be submitted by entering the information listed below on the Independent Transmission Provider's OASIS, which will provide a time-stamped record for the Application.
2.2.1 Applications That Do Not Require the Integration of Resources and Load: A Completed Application shall provide all of the information included in 18 CFR 2.20 including, but not limited to, the following:
(i) The identity, address, telephone number and facsimile number of the party requesting service;
(ii) A statement that the party requesting service meets, or will be upon commencement of service, will meet the eligibility requirement under Part I of this Tariff;
(iii) The location of the specific Receipt Points and Delivery Points and the identities of the Delivering Parties and the Receiving Parties;
(iv) The location of the generating facility(ies) supplying the capacity and Energy and the location of the Load ultimately served by the capacity and Energy transmitted. The Independent Transmission Provider shall treat this information as confidential except to the extent that disclosure of this information is required by this Tariff, by regulatory or judicial order, for reliability purposes pursuant to Good Utility Practice or pursuant to transmission information sharing agreements. The Independent Transmission Provider shall treat this information consistent with the standards of conduct contained in Part 37 of the Commission's regulations;
(v) A description of the supply characteristics of the capacity and Energy to be delivered; an estimate of the capacity and Energy expected to be delivered to the Receiving Party; and the transmission transfer capability requested for each Receipt Point and Delivery Point on the Independent Transmission Provider's Transmission System; Customers may combine their requests for service in order to satisfy the minimum transmission capability requirement; and
(vi) Service Commencement Date and the term of the requested Network Access Service: The minimum term for Network Access Service is one hour.
2.2.2 Applications That Require the Integration of Resources and Load: A Completed Application shall provide all of the information included in 18 CFR 2.20 including, but not limited to, the following:
(i) The identity, address, telephone number and facsimile number of the party requesting service;
(ii) A statement that the party requesting service meets, or upon commencement of service will meet, the eligibility requirement under Part I of this Tariff;
(iii) A description of the Load at each Delivery Point. This description must separately identify and provide the Customer's best estimate of the total Loads to be served at each transmission voltage level, and the Loads to be served from each Independent Transmission Provider substation at the same transmission voltage level. The description must include a ten (10) year forecast of service for summer and winter Load and Resource requirements beginning with the first year after the service is scheduled to commence and extending for the duration of the service request;
(iv) The amount and location of any demand responsive Loads included in the Network Load. This shall include the summer and winter capacity requirements for each demand responsive Load, that portion of the Load subject to demand response, the conditions under which a response can be implemented and any limitations on the amount and frequency of demand response. Customer should identify the amount of demand responsive Load (if any) included in the ten (10) year Load forecast provided in response to (iii) above.
(v) A description of Network Resources (current and term of request projection), which shall include, for each Network Resource:
(vi) A description of Customer's Transmission System, if applicable:
(vii) Service Commencement Date and the term of the requested Network Access Service: The minimum term for Network Access Service is one hour.
The Independent Transmission Provider shall acknowledge the Completed Application within ten (10) days of receipt. The acknowledgment must include a date by which a response, including a Service Agreement, will be sent to the Customer. If an Application fails to meet the requirements of this section, the Independent Transmission Provider shall notify the Customer filing the Application requesting service or Congestion Revenue Rights within fifteen (15) days of receipt and specify the reasons for such failure. Wherever possible, the Independent Transmission Provider shall attempt to remedy deficiencies in the Application through informal communications with the Customer. If such efforts are unsuccessful, the Independent Transmission Provider shall return the Application without prejudice to the Customer filing a new or revised Application that fully complies with the requirements of this section. The Customer will be assigned a new priority consistent with the date of the new or revised Application. The Independent Transmission Provider shall treat this information consistent with the standards of conduct contained in Part 37 of the Commission's regulations.
2.3 Technical Arrangements to be Completed Prior to Commencement of Service: Network Access Service shall not commence until the Independent Transmission Provider and the Customer, or a third party, have completed installation of all equipment specified under the Network Operating Agreement consistent with Good Utility Practice and any additional requirements reasonably and consistently imposed to ensure the reliable operation of the Transmission System. The Independent Transmission Provider shall exercise reasonable efforts, in coordination with the Customer, to complete such arrangements as soon as practicable taking into consideration the Service Commencement Date.
2.4 Customer Facilities: To the extent Customer owns transmission facilities, the provision of Network Access Service shall be conditioned upon the Customer's constructing, maintaining and operating the facilities on its side of each Delivery Point or interconnection necessary to reliably deliver capacity and Energy from the Independent Transmission Provider's Transmission System to the Customer. The Customer shall be solely responsible for constructing or installing all facilities on the Customer's side of each such Delivery Point or interconnection.
2.5 Filing of Service Agreement: The Independent Transmission Provider must file Service Agreements or related agreements with the Commission to the extent required by applicable Commission regulations.
2.6 Notice of Deficient Application: If an Application fails to meet the requirements of the Tariff, the Independent Transmission Provider shall notify the entity requesting service within fifteen (15) days of receipt of the reasons for such failure. The Independent Transmission Provider shall attempt to remedy minor deficiencies in the Application through informal communications with the Customer. If such efforts are unsuccessful, the Independent Transmission Provider shall return the Application, along with any deposit, with interest. Upon receipt of a new or revised Application that fully complies with the requirements of the Tariff, the Customer shall be assigned a new priority consistent with the date of the new or revised Application.
2.7 Response to a Completed Application: Following receipt of a Completed Application for Network Access Service, the Independent Transmission Provider shall make a determination of physical feasibility as required in Section B.5.2. The Independent Transmission Provider shall notify the Customer as soon as practicable, but not later than thirty (30) days after the date of receipt of a Completed Application, either (i) if it will be able to offer Network Access Service without performing a System Impact Study or (ii) if such a study is needed to evaluate the impact of the Application pursuant to Section B.5.3. Responses by the Independent Transmission Provider must be made as soon as practicable to all Completed Applications and the timing of such responses must be made on a non-discriminatory basis.
2.8 Execution of Service Agreement: Whenever the Independent Transmission Provider determines that a System Impact Study is not required and that the service can be provided, it shall notify the Customer as soon as practicable but no later than thirty (30) days after receipt of the Completed Application. Where a System Impact Study is required, the provisions of Section B.2.5 will govern the execution of a Service Agreement. Failure of a Customer to execute and return the Service Agreement or request the filing of an unexecuted Service Agreement pursuant to Section B.2.9 within fifteen (15) days after it is tendered by the Independent Transmission Provider will be deemed a withdrawal and termination of the Application and any deposit submitted shall be refunded with interest. Nothing herein limits the right of a Customer to file another Application after such withdrawal and termination.
2.9 Initiating Service in the Absence of an Executed Service Agreement: If the Independent Transmission Provider and the Customer requesting Network Access Service
2.10 Scheduling of Network Access Service: Under Network Access Service, a Customer can schedule transmission service or procure Energy through the Day-Ahead and Real-Time Markets. The scheduling procedures for both options are contained in Part III of this Tariff.
To the extent a Customer desires the Independent Transmission Provider to integrate, economically dispatch, and regulate the Customer's Resources to serve the Customer's Load, the Customer must designate Resources as described below. All other Customers will identify Receipt Points and Delivery Points through the Day-Ahead and Real-Time Markets pursuant to Part III of this Tariff.
3.1 Designation of Network Resources: All Customers desiring the Independent Transmission Provider to integrate, economically dispatch, and regulate its Resources to serve its load must designate sufficient Network Resources to meets its Load on a non-interruptible basis. Network Resources shall include all generation owned, purchased or leased by the Customer designated to serve Network Load under the Tariff. Network Resources may not include Resources, or any portion thereof, that are committed for sale to non-designated third-party Load or otherwise cannot be called upon to meet the Customer's Network Load on a non-interruptible basis. Any owned or purchased Resources that were serving the Customer's Loads under firm agreements entered into on or before the Service Commencement Date shall initially be designated as Network Resources until the Customer terminates the designation of such Resources.
3.2 Designation of New Network Resources: The Customer may designate a new Resource by providing the Independent Transmission Provider with as much advance notice as practicable. A designation of a new Network Resource must be made by a request for modification of service pursuant to an Application under Section B.2.
3.3 Designation of Alternate Resources: The Customer has the right to obtain alternate Resources, whether through a bilateral contract or through the Independent Transmission Provider-Administered Markets. Alternate Resources enable the Customer to substitute one Resource for another, generally on a short-term basis. An alternate Resource does not have to be committed to the Customer on a firm basis as does a Network Resource.
3.4 Substitution of Resources and Congestion Revenue Rights: The Customer may replace one designated Resource with another. The Customer may request a reconfiguration of the Congestion Revenue Rights it holds for the current Resource and request Congestion Revenue Rights for the new Resource pursuant to B.6 of the Tariff.
3.5 Termination of Network Resources: The Customer may terminate the designation of all or part of a generating Resource as a Network Resource at any time, but must provide notification to the Independent Transmission Provider as soon as reasonably practicable.
3.6 Customer Dispatch Obligation: As a condition to receiving Network Access Service, the Customer agrees to dispatch its Network Resources as requested by the Independent Transmission Provider, consistent with Part II of this Tariff. To the extent practicable, the redispatch of Resources pursuant to this section shall be on a least cost, non-discriminatory basis between all Customers.
3.7 Transmission Arrangements for Network Resources Not Physically Interconnected with the Independent Transmission Provider: The Customer shall be responsible for any arrangements necessary to deliver capacity and Energy from a Network Resource not physically interconnected with the Independent Transmission Provider's Transmission System. The Independent Transmission Provider will undertake reasonable efforts to assist the Customer in obtaining such arrangements, including without limitation, providing any information or data required by such other entity pursuant to Good Utility Practice.
3.8 Limitation on Designation of Network Resources: The Customer must demonstrate that it owns or has committed to purchase generation pursuant to an executed contract in order to designate a generating Resource as a Network Resource. Alternatively, the Customer may establish that execution of a contract is contingent upon the availability of transmission service under the Tariff.
3.9 Customer Owned Transmission Facilities: The Customer that owns existing facilities that are determined by the Order No. 888 seven factor test to be Transmission Facilities may be eligible to receive consideration either through a billing credit or some other mechanism.
To the extent a Customer desires the Independent Transmission Provider to integrate, economically dispatch, and regulate the Customer's Resources to serve the Customer's Load, the Customer must designate Loads as described below.
4.1 Network Load: The Customer must designate the individual Network Loads on whose behalf the Independent Transmission Provider will provide Network Access Service. The Network Loads shall be specified in the Service Agreement and shall include actual deliveries at Interfaces.
4.2 New Network Loads Connected with the Independent Transmission Provider: The Customer shall provide the Independent Transmission Provider with as much advance notice as reasonably practicable of the designation of new Network Load that will be added to its Transmission System. A designation of new Network Load must be made through a modification of service pursuant to a new Application. The Independent Transmission Provider will use due diligence to install any transmission facilities required to interconnect a new Network Load designated by the Customer. The costs of new facilities required to interconnect a new Network Load shall be determined in accordance with the procedures provided in Section B.5.12 and shall be charged to the Customer in accordance with Part VIII of this Tariff.
4.3 New Interconnection Points: To the extent the Customer desires to add a new Delivery Point or interconnection point between the Independent Transmission Provider's Transmission System and a Network Load, the Customer shall provide the Independent Transmission Provider with as much advance notice as reasonably practicable.
4.4 Changes in Service Requests: Under no circumstances shall the Customer's decision to cancel or delay a requested change in Network Access Service (
4.5 Annual Load and Resource Information Updates: The Customer shall provide the Independent Transmission Provider with annual updates of Network Load and Network Resource forecasts consistent with those included in its Application for Network Access Service under the Tariff. The Customer also shall provide the Independent Transmission Provider with timely written notice of material changes in any other information provided in its Application relating to the Customer's Network Load, Network Resources, Transmission System or other aspects of its facilities or operations affecting the Independent Transmission Provider's ability to provide reliable service.
5.1 General Conditions: The Independent Transmission Provider shall provide Network Access Service over, on or across its Transmission System to any Customer that has met the requirements of Section A.9.
5.2 Determination of Available Transfer Capability: A description of the Independent Transmission Provider's specific methodology for assessing Available Transfer Capability posted on the Independent Transmission Provider's OASIS is contained in Attachment A of the Tariff. In the event
5.3 Notice of Need for System Impact Study: After receiving a request for Congestion Revenue Rights or for the reconfiguration of Congestion Revenue Rights, the Independent Transmission Provider shall conduct, to the extent necessary, a System Impact Study. A description of the Independent Transmission Provider's methodology for completing a System Impact Study is provided in Attachment B. The Independent Transmission Provider shall within thirty (30) days of receipt of a Completed Application, tender a System Impact Study Agreement pursuant to which the Customer shall agree to reimburse the Independent Transmission Provider for performing the required System Impact Study. For a service request to remain a Completed Application, the Customer shall execute the System Impact Study Agreement and return it to the Independent Transmission Provider within fifteen (15) days. If the Customer elects not to execute the System Impact Study Agreement, its Application shall be deemed withdrawn and its deposit shall be returned with interest.
(i) The System Impact Study Agreement must clearly specify the Independent Transmission Provider's estimate of the actual cost and time for completion of the System Impact Study. The charge shall not exceed the actual cost of the study. In performing the System Impact Study, the Independent Transmission Provider shall rely, to the extent reasonably practicable, on existing transmission planning studies. The Customer will not be assessed a charge for such existing studies; however, the Customer will be responsible for charges associated with any modifications to existing planning studies that are reasonably necessary to evaluate the impact of the Customer's request for service on the Transmission System.
(ii) If in response to multiple Customers requesting service in relation to the same competitive solicitation, a single System Impact Study is sufficient for the Independent Transmission Provider to accommodate the service requests, the costs of that study shall be prorated among the Customers.
5.5 System Impact Study Procedures: Upon receipt of an executed System Impact Study, the Independent Transmission Provider shall use due diligence to complete the required System Impact Study within sixty (60) days. The System Impact Study shall identify any system constraints and dispatch options, additional Direct Assignment Facilities or Network Upgrades required to provide the requested service. In the event that the Independent Transmission Provider is unable to complete the required System Impact Study within such time period, it shall so notify the Customer and provide an estimated completion date along with an explanation of the reasons why additional time is required to complete the required studies. A copy of the completed System Impact Study and related work papers shall be made available to the Customer. The Independent Transmission Provider shall notify the Customer immediately upon completion of the System Impact Study if the Transmission System will be adequate to accommodate all or part of a request for service, all or part of a request for Congestion Revenue Rights reconfiguration, or if no costs are likely to be incurred for new transmission facilities or upgrades. In order for a request to remain a Completed Application, within fifteen (15) days of completion of the System Impact Study the Customer must execute a Service Agreement or request the filing of an unexecuted Service Agreement, or the Application shall be deemed terminated and withdrawn.
5.6 Facilities Study Procedures: If a System Impact Study indicates that additions or upgrades to the Transmission System are needed to supply the Customer's service request, Congestion Revenue Rights Request, or Congestion Revenue Rights Reconfiguration request, the Independent Transmission Provider, within thirty (30) days of the completion of the System Impact Study, shall tender to the Customer a Facilities Study Agreement pursuant to which the Customer shall agree to reimburse the Independent Transmission Provider for performing the required Facilities Study. For a service request to remain a Completed Application, the Customer shall execute the Facilities Study Agreement and return it to the Independent Transmission Provider within fifteen (15) days. If the Customer elects not to execute the Facilities Study Agreement, its Application shall be deemed withdrawn and its deposit shall be returned with interest. Upon receipt of an executed Facilities Study Agreement, the Independent Transmission Provider will use due diligence to complete the required Facilities Study within sixty (60) days. If the Independent Transmission Provider is unable to complete the Facilities Study in the allotted time period, the Independent Transmission Provider shall notify the Customer and provide an estimate of the time needed to reach a final determination along with an explanation of the reasons that additional time is required to complete the study. When completed, the Facilities Study shall include a good faith estimate of (i) the cost of Direct Assignment Facilities to be charged to the Customer, (ii) the Customer's appropriate share of the cost of any required Network Upgrades, and (iii) the time required to complete such construction and initiate the requested service. The Customer shall provide the Independent Transmission Provider with a letter of credit or other reasonable form of security acceptable to the Independent Transmission Provider equivalent to the costs of new facilities or upgrades consistent with commercial practices as established by the Uniform Commercial Code. The Customer shall have thirty (30) days to execute a Service Agreement or request the filing of an unexecuted Service Agreement and provide the required letter of credit or other form of security or the request no longer will be a Completed Application and shall be deemed terminated and withdrawn.
5.7 Facilities Study Modifications: Any change in design arising from an inability to site or construct facilities as proposed will require development of a revised good faith estimate. New good faith estimates also will be required in the event of new statutory or regulatory requirements that are effective before the completion of construction or other circumstances beyond the control of the Independent Transmission Provider that significantly affect the final cost of new facilities or upgrades to be charged to the Customer pursuant to the provisions of Part II of the Tariff.
5.8 Due Diligence in Completing New Facilities: The Independent Transmission Provider shall use due diligence to add necessary facilities or upgrade its Transmission System within a reasonable time. The Independent Transmission Provider will not upgrade its existing or planned Transmission System in order to provide the requested Transmission Service or Congestion Revenue Rights if doing so would impair system reliability or otherwise impair or degrade existing service or Congestion Revenue Rights.
5.9 Obligation to Provide Transmission Service that Requires Expansion or Modification of the Transmission System: If the Independent Transmission Provider determines that it cannot accommodate a request for service or Congestion Revenue Rights because of insufficient transmission capability on its Transmission System, the Independent Transmission Provider must use due diligence to expand or modify its Transmission System to provide the requested transmission service, provided the Customer agrees to compensate the Independent Transmission Provider for such costs pursuant to the terms of Section B.5.12. The Independent Transmission Provider will conform to Good Utility Practice in determining the need for new facilities and in the design and construction of such facilities. The obligation applies only to those facilities that the Independent Transmission Provider along with the Transmission Owner has the right to expand or modify.
5.10 Partial Interim Service: If the Independent Transmission Provider determines that it will not have adequate transmission capability to satisfy the full amount of a Completed Application for service, the Independent Transmission Provider nonetheless shall be obligated to offer and provide the portion of the requested Network Access Service that can be accommodated without addition of any facilities and through redispatch. Partial service could be of an amount (MW) or duration. However, the Independent Transmission Provider shall not be obligated to provide the incremental amount of requested Transmission Service (or Congestion Revenue Rights) that requires the addition of facilities or upgrades to the Transmission System until such facilities or upgrades have been placed in service. To the extent the Customer disagrees with the Independent Transmission Provider's determination of insufficient Available Transfer Capability (or redispatch capability),
5.11 Expedited Procedures for New Facilities: In lieu of the procedures set forth above, the Customer shall have the option to expedite the process by requesting the Independent Transmission Provider to tender at one time, together with the results of required studies, an “Expedited Service Agreement” pursuant to which the Customer would agree to compensate the Independent Transmission Provider for all costs incurred pursuant to the terms of the Tariff. In order to exercise this option, the Customer shall request in writing an expedited Service Agreement covering all of the above-specified items within thirty (30) days of receiving the results of the System Impact Study identifying needed facility additions or upgrades or costs incurred in providing the requested service. While the Independent Transmission Provider agrees to provide the Customer with its best estimate of the new facility costs and other charges that may be incurred, such estimate shall not be binding and the Customer must agree in writing to compensate the Independent Transmission Provider for all costs incurred pursuant to the provisions of the Tariff. The Customer shall execute and return such an Expedited Service Agreement within fifteen (15) days of its receipt or the Customer's request for service will cease to be a Completed Application and will be deemed terminated and withdrawn.
5.12 Compensation for New Facilities: Whenever a System Impact Study performed by the Independent Transmission Provider in connection with the provision of Network Access Service identifies the need for new facilities, the Customer shall be responsible for such costs to the extent consistent with Commission policy.
6.1 Delays in Construction of New Facilities: If any event occurs that will materially affect the time for completion of new facilities, or the ability to complete them, the Independent Transmission Provider shall promptly notify the Customer. In such circumstances, the Independent Transmission Provider shall within thirty (30) days of notifying the Customer of such delays, convene a technical meeting with the Customer to evaluate the alternatives available to the Customer. The Independent Transmission Provider also shall make available to the Customer studies and work papers related to the delay, including all information that is in the possession of the Independent Transmission Provider that is reasonably needed by the Customer to evaluate any alternatives.
6.2 Alternatives to the Original Facility Additions: When the review process of Section B.5.5 determines that one or more alternatives exist to the originally planned construction project, the Independent Transmission Provider shall present such alternatives for consideration by the Customer. If, upon review of any alternatives, the Customer desires to maintain its Completed Application subject to construction of the alternative facilities, it may request the Independent Transmission Provider to submit a revised Service Agreement for Network Access Service and a request for associated Congestion Revenue Rights. If the alternative approach solely involves Network Access Service and the Customer is willing to pay any applicable Congestion Charges, the Independent Transmission Provider shall promptly tender a Service Agreement for Network Access Service providing for the service. In the event the Independent Transmission Provider concludes that no reasonable alternative exists and the Customer disagrees, the Customer may seek relief under the dispute resolution procedures pursuant to Section A.10 or it may refer the dispute to the Commission for resolution.
6.3 Refund Obligation for Unfinished Facility Additions: If the Independent Transmission Provider and the Customer mutually agree that no other reasonable alternatives exist and the requested service cannot be provided out of existing capability under the conditions of Part II of the Tariff, the obligation to provide the requested Transmission Service shall terminate and any deposit made by the Customer shall be returned with interest pursuant to Commission regulations 35.19a(a)(2)(iii). However, the Customer shall be responsible for all prudently incurred costs by the Independent Transmission Provider through the time construction was suspended.
Part VI of this Tariff details Transmission Planning and Expansion.
8.1 Conditions Required of Customers: Network Access Service shall be provided by the Independent Transmission Provider only if the following conditions are satisfied by the Customer:
(i) The Customer has pending a Completed Application for service;
(ii) The Customer has met the creditworthiness and eligibility criteria set forth in Sections A.8 and A.9;
(iii) The Customer will have arrangements in place for any other transmission service necessary to effect the delivery from the generating source to the Independent Transmission Provider prior to the time service under Part II of the Tariff commences;
(iv) The Customer has agreed to pay for any facilities constructed and chargeable to such Customer under Part II of the Tariff, whether or not the Customer takes service for the full term of its reservation; and
(v) The Customer has executed a Network Access Service Agreement or has agreed to receive service pursuant to Section B.2.9.
8.2 Customer Responsibility for Third-Party Arrangements: Any scheduling arrangements that may be required by other electric systems shall be the responsibility of the Customer requesting service. The Customer shall provide, unless waived by the Independent Transmission Provider, notification to the Independent Transmission Provider identifying such systems and authorizing them to schedule the capacity and Energy to be transmitted by the Independent Transmission Provider pursuant to Part II of the Tariff on behalf of the Receiving Party at the Point of Delivery or the Delivering Party at the Point of Receipt. However, the Independent Transmission Provider will undertake reasonable efforts to assist the Customer in making such arrangements, including without limitation, providing any information or data required by such other electric system pursuant to Good Utility Practice.
9.1 Procedures: Prior to the Service Commencement Date, the Independent Transmission Provider and the Customer shall establish Load Shedding and Curtailment procedures in accordance with this Tariff with the objective of responding to contingencies on the Transmission System. The Parties shall implement such programs during any period when the Independent Transmission Provider determines that a system contingency exists and such procedures are necessary to alleviate such contingency. [The Independent Transmission Provider shall notify all affected Customers and other market participants (
9.2 Transmission Constraints: During any period when the Independent Transmission Provider determines that a transmission constraint exists on the Transmission System that cannot be handled through the LMP Congestion Management System, and such constraint may impair the reliability of the Independent Transmission Provider's system, the Independent Transmission Provider shall take whatever actions, consistent with Good Utility Practice, that are reasonably necessary to maintain the reliability of the Independent Transmission Provider's system. To the extent the Independent Transmission Provider determines that the reliability of the Transmission System can be maintained by redispatching resources, the Independent Transmission Provider shall initiate procedures to redispatch resources on the Independent Transmission Provider's Transmission System on a least-cost basis without regard to the ownership of such resources.
9.3 Curtailments of Scheduled Deliveries: If a transmission constraint on the Independent Transmission Provider's Transmission System cannot be relieved through the implementation of least-cost redispatch procedures and the Independent Transmission Provider determines that it is necessary to Curtail scheduled deliveries, the Independent Transmission Provider shall, on a non-discriminatory basis, Curtail the transaction(s) that effectively relieve the constraint. To the extent operationally feasible, the Independent Transmission Provider shall curtail transactions in the following order. Parties who do not have Congestion Revenue Rights in adequate amounts for their Receipt Point-Delivery Point combinations, shall be curtailed first. All other transactions that have a material impact on the transmission constraint will be curtailed on a pro rata basis. [The
9.4 Load Shedding: To the extent that a system Contingency exists on the Independent Transmission Provider's Transmission System and the Independent Transmission Provider determines that it is necessary for the Independent Transmission Provider and the Customer to shed Load, the Customers shall be directed by the Independent Transmission Provider to shed Load on a non-discriminatory basis to alleviate the Emergency/reliability contingencies.
(i) The Independent Transmission Provider will act first, whenever feasible, to direct Customers who have not met their assigned share of Resource Adequacy Requirements, pursuant to Section I of this Tariff, to shed load, before requiring other Customers to shed load, up to the amount of the lesser of: (1) The Resource deficiency; or (2) the Customers' Day-Ahead Energy market schedules. Failure to comply with the Independent Transmission Provider's direction to shed load shall subject Customers to the penalty provisions of Section I.6.3.
9.5 System Reliability: Notwithstanding any other provisions of this Tariff, the Independent Transmission Provider reserves the right, consistent with Good Utility Practice and on a not unduly discriminatory basis, to Curtail Network Access Service without liability on the Independent Transmission Provider's part for the purpose of making necessary adjustments to, changes in, or repairs on its lines, substations and facilities, and in cases where the continuance of Network Access Service would endanger persons or property. In the event of any adverse condition(s) or disturbance(s) on the Independent Transmission Provider's Transmission System or on any other system(s) directly or indirectly interconnected with the Independent Transmission Provider's Transmission System, the Independent Transmission Provider, consistent with Good Utility Practice, also may Curtail Network Access Service in order to (i) limit the extent or damage of the adverse condition(s) or disturbance(s), (ii) prevent damage to generating or transmission facilities, or (iii) expedite restoration of service. The Independent Transmission Provider will give the Customer as much advance notice as is practicable in the event of such Curtailment. [The Independent Transmission Provider shall specify the rate treatment and all related terms and conditions applicable in the event that the Customer fails to respond to established Load Shedding and Curtailment procedures. The Independent Transmission Provider can assess a penalty for failure to curtail after a reasonable period of time.]
For any Direct Assignment Facilities, Ancillary Services, and applicable study costs, consistent with Commission policy, along with the following:
10.1 Monthly Access Charge: The Customer that is a Load-Serving Entity shall pay a monthly Access Charge, which shall be determined by multiplying its Load Ratio Share times one twelfth (1/12) of the Independent Transmission Provider's Annual Transmission Revenue Requirement specified in Part VIII. The Access Charge applies only to deliveries to load on the Independent Transmission Provider's System. The Access Charge does not apply to any deliveries to hubs, wheel throughs, or Exports to neighboring transmission systems.
10.2 Determination of Customer's Monthly Network Load: The Customer's monthly Load is its hourly Load coincident with the Independent Transmission Provider's Monthly Transmission System Peak.
10.3 Transmission Usage Charges: The Customer shall pay a Transmission Usage Charge for the quantity in MWh scheduled for Transmission Service. The Transmission Usage Charge will recover applicable Congestion Charges and losses, consistent with Sections F.3.3 and G.4.3, as applicable.
11.1 Operation Under the Network Operating Agreement: The Customer shall plan, construct, operate and maintain its facilities in accordance with Good Utility Practice and in conformance with the Network Operating Agreement.
11.2 Network Operating Agreement: The terms and conditions under which the Customer shall operate its facilities and the technical and operational matters associated with the implementation of Part II of the Tariff shall be specified in the Network Operating Agreement. The Network Operating Agreement shall provide for the Parties to (i) operate and maintain equipment necessary for integrating the Customer within the Independent Transmission Provider's Transmission System (including, but not limited to, remote terminal units, metering, communications equipment and relaying equipment), (ii) transfer data between the Independent Transmission Provider and the Customer (including, but not limited to, heat rates and operational characteristics of Resources, generation schedules for units outside the Independent Transmission Provider's Transmission System, interchange schedules, unit outputs for dispatch, voltage schedules, loss factors and other real time data), (iii) use software programs required for data links and constraint dispatching, (iv) exchange data on forecasted Loads and Resources necessary for long-term planning, and (v) address any other technical and operational considerations required for implementation of Part III of the Tariff, including scheduling protocols. The Network Operating Agreement will recognize that the Customer shall either (i) self-supply, contract for, or purchase from the Independent Transmission Provider all necessary Ancillary Services consistent with Good Utility Practice, which satisfies NERC and the [applicable regional reliability council] requirements. The Independent Transmission Provider shall not unreasonably refuse to accept contractual arrangements with another entity for Ancillary Services. The Network Operating Agreement is included under Part VII.
11.3 Network Operating Committee: A Network Operating Committee (Committee) shall be established to coordinate operating criteria for the Parties' respective responsibilities under the Network Operating Agreement. Each Customer shall be entitled to have at least one representative on the Committee. The Committee shall meet from time to time as need requires, but no less than once each calendar year.
12.1 Right of First Refusal: Prior to the effectiveness of a full auction mechanism for all Congestion Revenue Rights, Congestion Revenue Rights will be allocated to Customers with long-term firm contracts under which the Customer continues to pay the Access Charge. To ensure that these Customers are able to maintain that right until the time that Congestion Revenue Rights are auctioned, existing firm service Customers (wholesale requirements and transmission-only, with a contract term of one-year or more), have the right to continue to take Network Access Service and agreeing to pay the Access Charge when the existing contract expires, rolls over or is renewed. If at the end of the contract term, the Independent Transmission Provider's Transmission System cannot accommodate all of the requests for Congestion Revenue Rights, the existing firm service Customer must agree to accept a contract term at least equal to a competing request by any new Customer and to pay the Access Charge, as approved by the Commission, for such service. This priority for existing firm service Customers is an ongoing right that may be exercised at the end of all firm contract terms of one-year or longer. This section will remain in effect until the Independent Transmission Provider places into effect an auction mechanism for allocating all Congestion Revenue Rights.
12.2 Notice of Rollover: Consistent with requests for new service described in Section B.2.1 of the Tariff, a Customer must submit its request to exercise rollover rights no later than sixty (60) days prior to the date the current service agreement expires.
Ancillary Services are needed with transmission service to maintain reliability within and among the Service Areas affected by the transmission service. The Independent Transmission Provider is required to provide, and the Customer is required to purchase, the following Ancillary Services (i) Scheduling, System Control and Dispatch Service, (ii) Reactive Supply and Voltage Control from Generation Sources Service; and (iii) Energy Imbalance Service.
The Independent Transmission Provider is required to offer to provide the following Ancillary Services only to the Customer serving Load within the Independent Transmission Provider's Service Area (i) Regulation and Frequency Response Service, (ii) Operating Reserve-Spinning Reserve Service, and (iii) Operating Reserve-Supplement Reserve Service. The Customer serving Load within the Independent
The Independent Transmission Provider can fulfill its obligation to provide Ancillary Services by acting as the Customer's agent to secure these Ancillary Services from others or by operating a market for the services. The Customer may elect to (i) have the Independent Transmission Provider act as its agent and procure Regulation and Frequence Response Service and Operating Reserves through the markets in Part III or (ii) secure Regulation and Frequency Response Service and Operating Reserves from a third party or by self-supply when technically feasible.
This service is required to schedule the purchase, sale and movement of power through, out of, within, or into the Independent Transmission Provider's Service Area. This service can be provided only by the Independent Transmission Provider. The Customer must purchase this service from the Independent Transmission Provider. The charges for Scheduling, System Control and Dispatch Service are set forth below.
1.1 Billing Units and Calculation of Rates: The Independent Transmission Provider shall charge each Customer based on the product of:
(i) the Scheduling, System Control and Dispatch Service charge rates; and
(ii) the Customer's applicable billing units for the month, as follows: [Independent Transmission Provider to propose rate methodology.]
In order to maintain transmission voltages on the Transmission System within acceptable limits, generation facilities under the control of the Independent Transmission Provider are operated to produce (or absorb) reactive power. Thus, Reactive Supply and Voltage Control from Generation Sources Service (“Voltage Support Service”) must be provided for each Transaction on the Transmission System. The amount of Voltage Support Service that must be supplied with respect to the Customer's Transaction will be determined based on the reactive power support necessary to maintain transmission voltages within limits that are generally accepted in the region and consistently adhered to by the Independent Transmission Provider. Voltage Support Service is to be provided directly by the Independent Transmission Provider. The methodologies that the Independent Transmission Provider will use to obtain Voltage Support Service and the associated charges for such service are set forth below. [To be provided by the Independent Transmission Provider.]
Regulation and Frequency Response Service is necessary to provide for the continuous balancing of Resources (generation and interchange) with Load in order to maintain scheduled Interconnection frequency. Regulation and Frequency Response Service is accomplished by committing on-line generation whose output is raised or lowered (predominantly through the use of automatic generating control equipment) as necessary to follow the moment-by-moment changes in Load. The obligation to maintain this balance between Resources and Load lies with the Independent Transmission Provider. Each Load-Serving Entity must either purchase this service through the Independent Transmission Provider or make alternative comparable arrangements to satisfy its Regulation and Frequency Response Service obligation.
The Independent Transmission Provider shall establish Day-Ahead and Real-Time Markets for Regulation to procure through the Day-Ahead and Real-Time Markets that portion of Regulation Requirement not met through Self-Supply. The full Regulation Requirement shall be cleared through the Day-Ahead Market. The Real-Time Market will provide an alternate supply for Regulation Service during the Operating Day where (i) Suppliers scheduled in the Day-Ahead Market are inadequate; (ii) a scheduled Supplier is unable to provide Regulation Service (
The Market Rules for the Day-Ahead Market for Regulation are set forth in Section F.4. The Market Rules for the Real-Time Market for Regulation are set forth in Section G.4.
Energy Imbalance Service is provided when a difference occurs between the scheduled and the actual delivery of Energy to a Load located within the Independent Transmission Provider's Service Area. This service will be provided through the Real-Time Energy Market operated by the Independent Transmission Provider. The procedures that will be used are described in Part III below.
The Independent Transmission Provider shall provide procedures to establish adequate Operating Reserves that comply with applicable Reliability Rules. Operating Reserves are classified as follows:
(i) Spinning Reserve: Operating Reserves provided by Resources (Generation and Demand) located within the Independent Transmission Provider Service Area that are already synchronized to the Power System and can respond to instructions to change output level within ten (10) minutes;
(ii) Supplemental Reserve: Operating Reserves provided by Resources (Generation and Demand) that can respond to instructions to change output or consumption level within ten (10) minutes or some other specified time period.
Operating Reserves can be ranked in terms of quality. Spinning Reserves are a higher quality reserve product than Supplemental Reserves. Supplemental Reserves that can respond to instructions on a shorter time frame (
The Independent Transmission Provider shall establish Day-Ahead and Real-Time Markets for Operating Reserves. The full requirement for Operating Reserves shall be cleared through the Day-Ahead Market. The Real-Time Markets will provide an alternate supply for Operating Reserves during the Operating Day where (i) Suppliers scheduled in the Day-Ahead Market are inadequate; (ii) a scheduled Supplier is unable to provide Operating Reserves (
The Market Rules for the Day-Ahead Markets for Operating Reserves are set forth in Sections F.5 and F.6. The Market Rules for the Real-Time Markets for Operating Reserves are set forth in Sections G.6 and G.7.
A Congestion Revenue Right is a right held by a Customer which provides the Customer with a hedge against uncertain future Congestion Charges by paying the holder of the right a stream of specified congestion revenues. This section details the specific types of Congestion Revenue Rights, the specific properties of Congestion Revenue Rights, and how Congestion Revenue Rights are acquired.
The Independent Transmission Provider shall make available, through the processes identified in Section D.3, Receipt Point-to-Delivery Point Congestion Revenue Right Obligation as described below. In addition, upon request of Market Participants, the Independent Transmission Provider shall make available Receipt Point-to-Delivery
1.1 Receipt Point-to-Delivery Point Congestion Revenue Rights: A Receipt Point-to-Delivery Point right is specified by a Receipt Point and a Delivery Point, the total MW that are to be injected at the Receipt Point and withdrawn at the Delivery Point, whether the right is an Obligation or an Option, and the period of time for which the right is in effect.
1.1.1 Obligation Rights: Receipt Point-to-Delivery Point Congestion Revenue Right Obligations confer to the holder (i) the right to collect revenues equal to the applicable Marginal Congestion Component of the hourly Transmission Usage Charge from the Receipt Point to the Delivery Point when the Marginal Congestion Component is positive, and (ii) the obligation to pay an amount to the Independent Transmission Provider equal to the absolute value of the applicable Marginal Congestion Component of the hourly Transmission Usage Charge from the Receipt Point to the Delivery Point when the Marginal Congestion Component is negative.
1.1.2 Option Rights: Receipt Point-to-Delivery Point Transmission Option Rights confer to the holder the right to collect revenues equal to the applicable Congestion Charge component of the hourly Transmission Usage Charge from the Receipt Point to the Delivery Point when the Marginal Congestion Component is positive, but do not obligate the holder to pay the absolute value of the applicable Marginal Congestion Component of the hourly Transmission Usage Charge when the Marginal Congestion Component is negative.
1.1.3 Types of Receipt Points and Delivery Points: The Receipt Points and Delivery Points specified in the Receipt Point-to Delivery Point Congestion Revenue Right can be a Generator bus, a load bus, an Interface between the Independent Transmission Provider's Service Area and an adjacent Service Area, or a pre-defined set of buses (which can be either Zones or Hubs).
1.2.1 Definition of Flowgates and Flowgate Rights: A Flowgate is a transmission facility (such as a transmission line or a transformer or some other component of the electrical network) or group of facilities (e.g., an Interface) that constrains the power transfer capability of the network. A Flowgate Right is specified by a portion of the total MW capability over a particular transmission Flowgate in a specified direction. Flowgate Rights entitle the holder to collect Congestion revenues (as determined consistent with Section F.3.5.2) associated with the specified MW flow over the identified Flowgate in the specified direction in the Day-Ahead Market.
During the first two years of operation of the Independent Transmission Provider's Bid-based markets, the Independent Transmission Provider shall offer Congestion Revenue Rights for sale through the auction procedures in Section D.7 with terms of 1 year, 6 months, and 1 month. Beginning in the third year of operation of the Independent Transmission Provider's Bid-based markets, the Independent Transmission Provider shall offer Congestion Revenue Rights with terms of 10 years, 5 years, 1 year, 6 months, and 1 month. Upon request of Market Participants, the Independent Transmission Provider may also offer Congestion Revenue Rights for other terms. These term limitations will not apply to Congestion Revenue Rights acquired through the initial allocation procedures for implementation of Standard Market Design.
In any hour in which the Independent Transmission Provider is unable to accept all requested schedules for Transmission Service at the applicable Day-Ahead Transmission Usage Charges, holders of Receipt Point-to-Delivery Point Congestion Revenue Rights shall have scheduling priority from their designated Receipt Points to their designated Delivery Points over Customers that do not hold Congestion Revenue Rights. [The Independent Transmission Provider shall develop a method for determining how to implement such priority, which shall be inserted here.]
Transmission Service pursuant to each Existing Transmission Contract shall be provided by the Independent Transmission Provider for the account of the Existing Transmission Contract Transmission Owner, acting as agent for the Existing Transmission Contract Customer. The Independent Transmission Provider shall assess to the Existing Transmission Contract Transmission Owner all charges and payments associated with providing Transmission Service pursuant to this Tariff. Consistent with the provisions of this Tariff, the Transmission Owner may acquire Congestion Revenue Rights to hedge against the Congestion costs associated with Transmission Service provided pursuant to its Existing Transmission Contracts.
4.1 Conversion of Existing Transmission Contracts: Upon the mutual agreement of the parties to any Existing Transmission Contract, the Existing Transmission Contract Customer may terminate its Existing Transmission Contract in exchange for receiving Congestion Revenue Rights previously held by the Transmission Owner to support the Existing Transmission Contract described in Section D.3 with the same MW level of service and with the same Receipt Points and Delivery Points and termination date as specified in the Existing Transmission Contract.
5.1 Allocation of Congestion Revenue Rights: The aggregate set of Congestion Revenue Rights allocated to Customers shall not exceed an amount that is Simultaneously Feasible, as determined pursuant to Section D.5.8, in light of the total transmission capability in the Independent Transmission Provider's Service Area under normal operating conditions. In determining whether a set of Congestion Revenue Rights is Simultaneously Feasible, the Total Transfer Capability of the transmission system shall not be reduced by the transfer capability needed to support existing Customers.
5.2 Requirement to Conduct Periodic Auctions for Congestion Revenue Rights. The Independent Transmission Provider shall conduct periodic auctions over its OASIS, consistent with Section D.5, that will provide Bid-based markets to buy and sell Congestion Revenue Rights for a variety of terms. Each auction shall provide for the opportunity to buy and sell Receipt Point-to-Delivery Point Congestion Revenue Right Obligations, as described in Section D.1. Upon the request of Market Participants, auctions shall provide for the opportunity to buy and sell Receipt Point-to-Delivery Point Transmission Option Rights and Flowgate Rights, as soon as it is technically feasible to do so.
The periodic Congestion Revenue Rights auctions will also provide for the sale of Congestion Revenue Rights associated with transmission capability that becomes available after the initial allocation of Congestion Revenue Rights, for example, due to the expiration of initially allocated Congestion Revenue Rights.
All holders of Congestion Revenue Rights may resell their Congestion Revenue Rights outside the auction held pursuant to Section D.3.2. However, the Independent Transmission Provider shall make all Settlements with Primary Holders. Buyers of resold Congestion Revenue Rights that elect to become Primary Holders must meet the eligibility criteria in Section A.9 of this Tariff.
Sellers and potential buyers shall communicate all offers to sell and buy Congestion Revenue Rights, solely over the Independent Transmission Provider's OASIS.
The Independent Transmission Provider shall conduct periodic auctions to allow Market Participants to buy and sell Congestion Revenue Rights.
7.1 General Description of the Auction Process: In each auction, Market Participants will have the opportunity to submit Bids to buy and sell Congestion Revenue Rights for a specified term. In each auction, the Independent Transmission Provider shall consider all Bids and shall select a combination of Bids that (i) is Simultaneously Feasible in light of the Transmission Capability that is expected to be available over the term of the transactions and (ii) maximizes the combined net economic value (as expressed in the Bids) of the selected Bids. In order to maximize the net economic value of the selected Bids, the auction shall allow for the reconfiguration of Congestion Revenue Rights. That is, the Congestion Revenue Rights that are offered for sale may be converted into Congestion Revenue Rights of a different type or with different Receipt and Delivery Points.
7.2 Frequency of Congestion Revenue Rights Auction: The Independent
7.3 Responsibilities of the Independent Transmission Provider Prior to Each Auction
7.3.1 Establish Auction Rules: The Independent Transmission Provider shall use the auction rules and procedures consistent with this Tariff. [Independent Transmission Provider may file to add additional auction rules.]
7.3.2 Evaluate Creditworthiness: The Independent Transmission Provider shall evaluate each Bidder's ability to pay for Congestion Revenue Rights, consistent with the creditworthiness provisions of Section A.8. As a result of this evaluation, the Independent Transmission Provider shall state a limit before the auction on the value of the Congestion Revenue Rights that the entity may be awarded in the auction, and collect signed statements from each entity Bidding into the auction committing that entity to pay for any Congestion Revenue Rights that it is awarded in the auction. Bidders will not be permitted to submit Bids that exceed this allowable limit.
7.3.3 Information to be Made Available to Bidders: To aid Market Participants in their participation in the auction, the Independent Transmission Provider shall make the following information available before each auction:
(i) for each Generator bus, Load bus, external bus and Load Zone for each of the previous 5 years, if available, (a) the average Marginal Congestion Component of the LMP, relative to the Reference Bus, and (b) the average Marginal Losses Component of the LMP, relative to the Reference Bus;
(ii) for each of the previous two 6-month periods, (a) historical flow histograms for each of the closed Interfaces, and (b) historically, the number of hours that the most limiting facilities were physically constrained;
(iii)(a) Power Flow data to be used as the starting point for the auction, including all assumptions, (b) assumptions made by the Independent Transmission Provider relating to transmission maintenance outage schedules, (c) all limits associated with transmission facilities, contingencies, thermal, voltage and stability to be monitored as Constraints in the Optimum Power Flow determination, and (d) the Independent Transmission Provider summer and winter operating study results (non-simultaneous Interface Transfer Capabilities).
7.3.4 Other Responsibilities: The Independent Transmission Provider will establish an auditable information system to facilitate analysis and acceptance or rejection of Bids, to provide a record of all Bids, and to provide all necessary assistance in the resolution of disputes that arise from questions regarding the acceptance, rejection, award and recording of Bids. The Independent Transmission Provider will establish a system to communicate auction-related information to all auction participants.
The Independent Transmission Provider will receive Bids to buy Congestion Revenue Rights from any entity that meets the eligibility criteria established in this Tariff and will implement the auction Bidding rules previously established by the Independent Transmission Provider.
The Independent Transmission Provider will properly utilize an Optimal Power Flow program to determine the set of winning Bids for each auction and calculate the Market Clearing Price of all Congestion Revenue Rights at the conclusion of the auction, in the manner described in this Tariff.
7.4.1 Creditworthiness Information: Each Bidder must submit such information to the Independent Transmission Provider regarding the Bidder's creditworthiness as the Independent Transmission Provider may require consistent with Section A.8, along with a statement signed by the Bidder, representing that the Bidder is financially able and willing to pay for the Congestion Revenue Rights for which it is Bidding. The aggregate value of the Bids submitted by any Bidder into the auction shall not exceed that Bidder's ability to pay or the maximum value of Bids that Bidder is permitted to place, as determined by the Independent Transmission Provider (based on an analysis of that Bidder's creditworthiness).
Each Bidder must pay the Market Clearing Price for each Congestion Revenue Right it is awarded in the auction.
7.5.1 Bids to Sell Congestion Revenue Rights: Each Market Participant desiring to sell Congestion Revenue Rights Shall include the following information in its Bid:
(i) The type of Congestion Revenue Right (i.e., Receipt Point-to-Delivery Point Congestion Revenue Right Obligation, Receipt Point-to-Delivery Point Transmission Option Right, or Flowgate Congestion Revenue Right).
(ii) The Receipt and Delivery Points, if a Receipt Point-to-Delivery Point Right is offered.
(iii) The location and direction of the Flowgate, if a Flowgate Right is offered.
(iv) The MWs
(v) The minimum acceptable price, if any.
(vi) The term.
Each seller that offers Congestion Revenue Rights for sale that it has been awarded must provide verification of the award to the Independent Transmission Provider when the Bid is submitted.
7.6 Selection of Winning Bids and Determination of the Market Clearing Price: The Independent Transmission Provider shall determine the winning set of Bids in each auction as the set of Bids that maximizes the value (as expressed in the Bids) of the Congestion Revenue Rights, subject to the constraint that the selected set of Bids must be simultaneously feasible consistent with Section D.5.8.
The Market Clearing Price for each Congestion Revenue Right shall equal the change in the net economic value of all other Bidders that would result from awarding an additional 1 MW of that Congestion Revenue Right to a Market Participant.
7.7 Auction Settlement: The Independent Transmission Provider will determine prices in the auction for feasible Congestion Revenue Rights, consistent with Section 6.6. Each Bidder awarded Congestion Revenue Rights in the auction shall pay the applicable Market Clearing Price for those Congestion Revenue Rights that is awarded in the auction. Similarly, each Congestion Revenue Right holder selling Congestion Revenue Rights through the Auction shall be paid the applicable Market Clearing Price for those Congestion Revenue Rights that are sold in the auction.
7.8 Simultaneous Feasibility: The set of winning Bids selected in each auction shall be simultaneously feasible based on the Transfer Capability available for purchase within the Independent Transmission Provider's Service Area under normal operating conditions. A set of Bids shall be deemed simultaneously feasible if both of the following Conditions, A and B, are met:
The Power Flow simulations shall take into consideration the effects of parallel flows on the Transfer Capability of the Independent Transmission Provider's transmission system when determining which sets of injections and withdrawals are simultaneously feasible.
When performing the above Power Flows, injections for Receipt Point-to Delivery Point Congestion Revenue Rights that specify a Zone or a Hub as the injection location will be modeled as a set of injections at each bus in the injection Zone or Hub equal to the product of the number of Receipt Point-to-Delivery Point Congestion Revenue Rights and the percentage weights for each bus in the Zone or Hub.
When performing the above Power Flows, withdrawals for Receipt Point-to Delivery Point Congestion Revenue Rights that specify a Zone or Hub as the withdrawal location will be modeled as a set of withdrawals at each bus in the withdrawal Hub equal to the product of the number of Receipt Point-to Delivery Point Congestion Revenue Rights and the percentage weights for each bus in the Zone.
7.9 Responsibilities of the Independent Transmission Provider upon Completion of the Auction: The Independent Transmission Provider shall not reveal the Bid Prices submitted by any Bidder in the Auction until three months following the date of the auction, except as permitted by Section A.12. When these Bid Prices are posted, the names
Upon completion of the auction, the Independent Transmission Provider will collect payment for all Congestion Revenue Rights awarded in the auction. The Independent Transmission Provider will disburse the revenues collected from the sale of Congestion Revenue Rights to the Primary Holders upon completion of the Auction process. Each holder of a Congestion Revenue Right that offers that Congestion Revenue Right for sale in the auction shall be paid the Market Clearing Price for each Congestion Revenue Right sold by that holder. All remaining Auction revenues from the auction shall be allocated among those who pay the Access Charge. [The Independent Transmission Provider will file procedures explaining how these revenues will be allocated.]
The Independent Transmission Provider shall allow a Customer to exchange its Receipt Point-to-Delivery Point Congestion Revenue Right Obligation for a different Receipt Point-to-Delivery Point Congestion Revenue Right Obligation with different Receipt and/or Delivery Points as long as the exchange meets the condition specified in Section D.6.1 is met. In addition, as soon as it is technically feasible, the Independent Transmission Provider shall allow a Customer to acquire Receipt Point-to-Delivery Point Transmission Option Rights and Flowgate Rights in exchange for other Congestion Revenue Rights that the Customer may hold, as long as the exchange meets the condition specified in Section D.6.1. The MW levels of the original Congestion Revenue Rights and the new Congestion Revenue Rights in the exchange need not be the same, as long as the exchange meets the condition specified in Section D.6.1.
8.1 Condition for Exchanging Congestion Revenue Rights: In order for the Independent Transmission Provider to approve a request to exchange Congestion Revenue Rights, pursuant to Section D.6, the new Congestion Revenue Right (after being exchanged for the original Congestion Revenue Right), in combination with all other outstanding Congestion Revenue Rights held by others, must be Simultaneously Feasible as defined in Section D.5.8 in light of the total Transmission Capability in the Independent Transmission Provider's Service Area under normal operating conditions.
The Independent Transmission Provider shall award to all Market Participants that fund additions to the transmission system Congestion Revenue Rights to equal the capability created by the expansion. The Congestion Revenue Rights awarded in combination with all other awarded Congestion Revenue Rights, must be Simultaneously Feasible as described in Section D.5.8 in light of the Total Transfer Capability available under normal operating conditions. Such Market Participants shall be allowed to choose any set of Receipt Point-to-Delivery Point Obligation Rights that meet the requirements for Simultaneously Feasibility. Such Market Participants shall also be allowed to choose any set of Receipt Point-to-Delivery Point Option Rights and Flowgate Rights that meet the requirements for Simultaneous Feasibility, as soon as it is it is feasible to issue such rights. Such Market Participants may elect to receive no Congestion Revenue Rights if, but only if, all outstanding Congestion Revenue Rights are Simultaneously Feasible in light of the Total Transfer Capability available after the additions under normal operating conditions. [The Independent Transmission Provider file a Commission-approved, non-discriminatory methodology for allocating Congestion Revenue Rights among multiple Market Participants that fund any single transmission capability addition.]
The Independent Transmission Provider will operate Day-Ahead and Real-Time Markets for Energy and certain Ancillary Services in conjunction with Day-Ahead and Real-Time markets for transmission services. These markets will allocate transmission Transfer Capability and Generation Capacity among competing uses in different markets through Locational Marginal Pricing (LMP). The markets will be operated jointly to ensure that the prices for the products and services are internally consistent. The procedures for operating these markets are detailed below.
This Part III contains the procedures for Bidding and Scheduling of Energy and Bid-Based Ancillary Services, Bilateral Transaction Schedules and Self-Schedules in the Day-Ahead Market. Part III also contains the time requirements, notice provisions and sequence followed in administering Day-Ahead financial Settlement. These scheduling requirements support the operations of the Day-Ahead Markets for Energy, Regulation and Frequency Response, and Operating Reserves, the determination of the Day-Ahead Transmission Usage Charge, and the Day-Ahead financial Settlement of Congestion Revenue Rights.
Part III also contains the procedures for Scheduling and Bidding of Energy and Bid-Based Ancillary Services, and modification of, or submission of new, Bilateral Schedules and Self-Schedules, that will be used following the close of the Day-Ahead Market. These procedures include the time requirements, notice provisions and sequence followed in administering Real-Time Financial Settlement. These Bidding and scheduling requirements support the operations of the Real-Time Markets for Energy, Regulation and Frequency Response, Operating Reserves, and the determination of the Real-Time Transmission Usage Charge.
The Independent Transmission Provider shall provide all Market Services for Energy, Ancillary Services, and Transmission Service in accordance with the terms of the Tariff and related agreements.
The Independent Transmission Provider shall be the sole point of Application for all Market Services for Energy, Ancillary Services, and Transmission Service provided in the Independent Transmission Provider's Service Area. Each Market Participant that sells or purchases Energy, including demand side Resources, provides Ancillary Services, or Schedules Transmission Services subject to Transmission Usage Charges in the Independent Transmission Provider Administered Markets, utilizes Market Services and must take service as a Customer under the Tariff.
The Independent Transmission Provider has the right to schedule and dispatch Scheduled Resources and to direct that schedules be changed in an Emergency.
Following the start of the markets, the Independent Transmission Provider shall have the right to file changes to these market rules with the Commission to improve the competitiveness and efficiency of the markets.
The Independent Transmission Provider shall operate and maintain an OASIS that, among other things, will facilitate the posting of Bids to supply Energy, Ancillary Services and Demand Reductions by Suppliers for use by the Independent Transmission Provider and the posting of LMP, clearing prices for Bid-based Ancillary Services, and schedules for accepted Bids for Energy, Ancillary Services and Demand Reductions. The OASIS will be used to post schedules for Bilateral Transactions. The OASIS also will provide historical data regarding market clearing prices for each market in addition to Transmission Usage Charges.
Customers may utilize a variety of communications facilities to access the Independent Transmission Provider's OASIS, including but not limited to, conventional Internet service providers, wide area networks, and dedicated communications circuits. Customers shall arrange for and maintain all communications facilities for the purpose of communication of commercial data to the Independent Transmission Provider. Each Customer shall be the Customer of record for the telecommunications facilities and services it uses and shall assume all duties and responsibilities associated with the procurement, installation and maintenance of the subject equipment and software.
The Independent Transmission Provider will operate a Day-Ahead Market in order to develop a joint Day-Ahead Schedule for Transmission Service, Energy, and Ancillary Services. The Day-Ahead Schedule will be developed so as to maximize the combined economic value of Transmission Service, Energy, and Ancillary Services, based on the Bids submitted.
1.1 Day-Ahead Trading Deadline: Market Participants may submit Bids for purchase and sale of Energy, Ancillary Services and Transmission, Bilateral Transaction Schedules, Self-Schedules, and Ancillary Services Self-Supply Schedules no later than [to be supplied by Independent Transmission Provider] for use in establishing the Day-Ahead Schedule.
1.2 Rules for Self Schedules
1.2.1 Supplier-Committed Self Schedules
(i) Suppliers of Generation Resources for Energy may Self-Schedule these Resources in the Day-Ahead Markets.
(ii) Self-Schedules by Suppliers of Energy are required only to submit a MW quantity and a location.
1.2.2 Independent Transmission Provider-Committed Self Schedules
(i) Upon request of a Supplier, the Independent Transmission Provider shall develop a schedule for Generation or Demand Resources in which the Schedule optimizes the revenues over the Operating Day for the Resource. These are referred to in this Tariff as Independent Transmission Provider- Committed Self Schedules. This option will typically be used by Energy-Limited Resources, however this option is available to all Generation or Demand Resources.
(ii) Independent Transmission Provider-Committed Self-Schedules are required only to submit a MW quantity and a location.
(i) Suppliers of Resources for Regulation and Operating Reserves may Self-Supply these Resources in the Day-Ahead Markets.
(ii) The specific rules for Self-Supply of Regulation and Operating Reserves are in Sections F.4-F.6.
(i) All Internal Transactions must specify a Receipt Point, a Delivery Point, a MW quantity injected at the Receipt Point and a MW quantity withdrawn at the Delivery Point.
(ii) Internal Transactions may also, voluntarily, submit a price Bid ($/MW) over some or all of the MW range. This makes the transaction under the control of the Independent Transmission Provider.
(i) All External Transactions must specify a Receipt Point, a Delivery Point, a MW quantity injected at the Receipt Point and a MW quantity withdrawn at the Delivery Point. Either the Receipt Point or the Delivery Point must be a point at the boundary of the Independent Transmission Provider's Service Area. If the Receipt Point is a boundary point, then the External Transaction is an Import. If the Delivery Point is a boundary point, then the External Transaction is an Export. All External Transactions must specify a minimum run time.
(ii) The Independent Transmission Provider shall offer Market Participants with External Transactions two options for Day-Ahead scheduling. (1) External Transactions can be scheduled without a Price Bid. The Independent Transmission Provider shall take all appropriate steps to accommodate such transactions, such as reservation of ramping capacity. (2) External Transactions can be scheduled in the Day-Ahead Market with a Price Bid ($/MW) over some or all of the MW quantity being scheduled. Transactions with a Bid will only enter the Day-Ahead Schedule if the price is at or below the LMP at the transaction sink node.
(iii) External Transactions will be scheduled on a hourly basis.
1.4 Rules for Bidding: The Independent Transmission Provider shall evaluate all eligible Bids for Energy Supply and Demand, Regulation and Frequency Response, Operating Reserves and Day-Ahead Transmission Service. The requirements for Bid eligibility and the Bid Specifications are in Sections F.2.3, F.3.1, F.4.4, F.5.4 and F.6.4.
1.5 Bid-Based Security Constrained Unit Commitment and Determination of the Day-Ahead Schedule: The Independent Transmission Provider will develop a Security Constrained Unit Commitment schedule over the Operating Day using a computer algorithm that accepts all Self-Schedules and simultaneously maximizes the total value of the Bids, including Virtual Bids, submitted to (i) supply to (incorporating the costs of Start-up, No-load and Incremental Energy) and purchase from the Day-Ahead Market for Energy; (ii) provide sufficient Ancillary Services to support Energy purchased from the Day-Ahead Market; and (iii) receive Transmission Service to support Bilateral Transaction schedules and Self-Schedules submitted Day-Ahead. The Independent Transmission Provider may substitute higher quality Ancillary Services (i.e., shorter response time) for lower quality Ancillary Services when doing so would result in an overall least Bid cost solution.
In developing the Day-Ahead Schedule, the Independent Transmission Provider shall select Suppliers for Energy, Regulation and Frequency Response, and Operating Reserves for each hour of the upcoming day through its Day-Ahead Security-Constrained Unit Commitment, using Bids and/or schedules provided by the Suppliers. The Day-Ahead schedule will include commitment of sufficient Generators and price-sensitive Demand Bids to provide for the safe and reliable operation of the power system operated by the Independent Transmission Provider. The schedule shall honor all operating constraints included in the scheduled Bids. The Day-Ahead schedule shall list the twenty-four (24) hourly injections and withdrawals for: (a) each Customer whose Bid the Independent Transmission Provider accepts for the following Operating Day; and (b) Self-Schedules of Energy, Ancillary Services, and Transmission Service.
1.6 Determination of the Day-Ahead Prices: The Independent Transmission Provider shall calculate the Day-Ahead Energy LMPs and Flowgate LMPs based on a dispatch of committed Generation Resources to meet the Load that has Bid in and been scheduled Day-Ahead. The Day-Ahead Energy LMPs are calculated, according to the Independent Transmission Provider decision, for each Generator bus, load bus, and sets of buses that comprise Zones or Hubs. The Transmission Usage Charge for Bilateral Transactions that are scheduled Day-Ahead is the difference between the Energy LMP for the Delivery Point and the Energy LMP at the Receipt Point. The methodology for calculating the different types of LMPs is described in Sections F.2.4 and 3.3.
The Day-Ahead prices for Ancillary Services will be determined according to procedures described in Sections F.4.5, 5.5, 6.5 and 6.6.
1.7 Load Forecasts: All Load-Serving Entities shall provide their Day-Ahead Load forecasts to the Independent Transmission Provider. The Independent Transmission Provider shall develop an advisory forecast based on these forecasts and its own analysis of next day Load and shall post this forecast.
1.8 Reliability-Based Security Constrained Unit Commitment: In cases in which the sum of all Bilateral Schedules and all Day-Ahead Market purchases to serve Load within the Independent Transmission Provider's Service Area in the Day-Ahead schedule is less than the Independent Transmission Provider's Day-Ahead forecast of Load, the Independent Transmission Provider will commit Resources in addition to the reserves it normally maintains to enable it to respond to contingencies. These additionally-committed Resources are called Replacement Reserves. This commitment of Replacement Reserves will be the result of a Bid-Based Reliability-Based Security Constrained Unit Commitment conducted following the Day-Ahead Security Constrained Unit Commitment. The purpose of this additional commitment of Resources is to ensure that sufficient capacity is available to the Independent Transmission Provider in Real-Time to enable it to meet its Load forecast (including associated Ancillary Services).
In considering which additional Resources to schedule to meet the Independent Transmission Provider's Load forecast, the Independent Transmission Provider will evaluate whether unscheduled Imports can provide additional power at a price within any Bid Price caps set by the Independent Transmission Provider.
The Independent Transmission Provider will develop the Reliability-Based Security Constrained Unit Commitment schedule over the Operating Day using a computer algorithm that minimizes the total cost of committing the additional Generation and Demand Resources that provide Replacement Reserves based solely on the Start-up and No-load Bids of the additionally committed Resources. The Independent Transmission Provider shall use Bids submitted into the Day-Ahead Market. If such Bids are not sufficient to meet the forecast load, the Independent Transmission Provider may solicit additional Bids; these additional Bids will be considered eligible for the Real-Time Market in addition to the Reliability-Based Security Constrained Unit Commitment. Resources committed in the Reliability-Based Security Constrained Unit Commitment are
1.9 Reliability Forecast: In the Security Constrained Unit Commitment program, system operation shall be optimized based on Bids over the Operating Day. However, to preserve system reliability, the Independent Transmission Provider may take steps to ensure that there will be sufficient Resources available to meet forecasted Load and reserve requirements over the day beginning with the next Operating Day, typically completing a one week look ahead.
1.10 Posting the Day-Ahead Schedule: By [a pre-defined deadline to be supplied by Independent Transmission Provider] on the day prior to the Operating Day, the Independent Transmission Provider shall close the Day-Ahead scheduling process and post on its OASIS the Day-Ahead schedule for Energy, Regulation and Frequency Response, and Operating Reserves for each entity that submits a Bid or Self-Schedule. All schedules shall be considered proprietary, with the posting only visible to the appropriate scheduling Customer and Transmission Owners subject to the applicable Code of Conduct. The Independent Transmission Provider will post on the OASIS the aggregate Resources (Day-Ahead Energy, Regulation and Frequency Response and Operating Reserves schedules) and Load (Day-Ahead scheduled and forecast) for each Load bus or Zone, and the Day-Ahead LMP prices (including the Marginal Congestion cost Component and the Marginal Losses component) for each Generation Bus, Load Bus or Load Zone and Hub in each hour of the upcoming Operating Day.
The Independent Transmission Provider shall conduct the Day-Ahead Settlement based upon the Day-Ahead Prices determined in accordance with this Section.
1.11 Day Ahead Bid Revenue Sufficiency Guarantee: The Independent Transmission Provider shall ensure the minimum recovery of each Resource's Bid prices for Resources scheduled through the Day-Ahead Market or in subsequent commitments for reliability. The is called the Bid Revenue Sufficiency Guarantee.
(i) The Independent Transmission Provider shall determine, on a daily basis, if any Resource committed by the Independent Transmission Provider in the Day-Ahead Market will not recover Start-Up, No Load, and Energy Bid Price through revenues in the Day-Ahead Energy and Ancillary Services markets.
(ii) If the Start-Up and No Load Bids plus the net Energy and Ancillary Services Bid Price over the twenty-four (24) hour day of any Supply Resource exceeds the sum of its Day-Ahead LMP revenue and Ancillary Service revenue over the twenty-four (24) hour day, then that Supplier's Day-Ahead LMP revenue and Ancillary Service revenue shall be augmented by an additional payment, the Supply Bid Revenue Sufficiency Guarantee Payment, in the amount of the shortfall. This payment shall be supported through revenue collected from the Supply Bid Revenue Sufficiency Guarantee Charge.
(iii) If the total Day-Ahead Energy charges to any Demand Resource over the twenty-four (24) hour day exceeds its maximum willingness to pay, as reflected by the difference of its selected Day-Ahead Energy Bids and Start-up Cost Bid, the Demand Resource shall be augmented by a payment, the Demand Bid Revenue Sufficiency Guarantee Payment, in the amount of the overcharge. This payment is supported through revenues collected from the Demand Bid Revenue Sufficiency Guarantee Charge.
2.1 General: The Day-Ahead Market for Energy establishes clearing prices and settlement rules for Suppliers of Energy that have offered eligible Generation Capacity to the market and for Purchasers of Energy that have chosen not to Self-Supply or procure through bilateral contracts.
2.2 Independent Transmission Provider Obligations: The Independent Transmission Provider has the obligation to provide services (i) to (v) for the Day-Ahead Market for Energy. The rules governing these services are contained in this section:
(i) Establish and post on its OASIS rules that are consistent with this Tariff for eligibility to supply Energy in the Day-Ahead Market.
(ii) Establish and post on its OASIS the Bid data requirements and rules and provide the market functions that are consistent with this Tariff required for determination of hourly Day-Ahead LMPs for Energy and selection of Day-Ahead Energy Market Suppliers and Purchasers.
(iii) Establish and post on its OASIS the rules that are consistent with this Tariff for determination of any additional payments necessary to support efficient operations of the Day-Ahead Market for Energy and/or the efficient operation of other Day-Ahead Markets.
(iv) Provide the Settlement functions associated with purchase and sale of Energy in the Day-Ahead Market.
(v) Post the Day-Ahead LMPs for Energy.
2.3 Purchaser Rules and Obligations: Purchasers of Energy in the Day-Ahead Market shall provide the Bid information specified in Sections 2.3.1 to 2.3.3.
2.3.1 Specification of Bids: Purchasers of Day-Ahead Energy must provide the following Bid information. Purchasers must supply all information that is identified as a required Bid component. Purchasers may, but are not required to, submit information that is identified as an optional Bid component.
(i) MW desired to be purchased, with a default value of 0 MW. This is a required Bid component.
(ii) Location (transmission zone, aggregate, or single bus) that the purchaser desires to purchase the designated MWs of power. This is a required Bid component.
(iii) Maximum price ($/MW) at which the purchaser desires to purchase the designated MW of power. (A purchaser may indicate its desire to purchase the designated MWs of power regardless of price, if the purchaser has demonstrated to the Independent Transmission Provider in advance that it is financially capable of paying the highest possible price for the designated MWs.) This is a required Bid component.
(iv) Start-up Cost ($). This Bid component is an additional payment needed by the Purchaser of Energy to curtail its load This is an optional Bid component.
(v) Minimum Curtailment Time (hours). This Bid component is up to a maximum of 24 hours. This is an optional Bid component. If a Minimum Curtailment Time is not indicated, then the default time will be one hour.
(vi) Maximum Curtailment Time (hours). This Bid component is up to a maximum of 24 hours. This is an optional Bid component. If a Maximum Curtailment Time is not indicated, then the default time will be 24 hours.
(vii) Minimum Purchase Time (at least one hour). This is an optional Bid component
(viii) Maximum Purchase Time (hours). This is an optional Bid component.
(ix) Hours that the purchaser desires to purchase the designated MWs of power. This is a required Bid component.
2.3.2 Specification of Virtual Bids: Purchasers of Day-Ahead Virtual Energy must provide Bid components 2.3.1 (i) to (iii). In addition, the Bid shall identify that the Energy purchase is Virtual Energy if the purchase is not backed by actual load.
2.3.3 Period of Bids: The Demand Bids shall be hourly Bids for each hour of the Operating Day in which the price ($) and quantity (MW) components can vary hour by hour.
2.4.1 Eligibility to Supply: Suppliers of Day-Ahead Energy shall provide the Bid information specified in Section 2.4.2 . Suppliers of Day-Ahead Virtual Energy shall provide the Bid information specified in 2.4.3- 2.4.4 .
2.4.2 Specification of Bids. Suppliers are required to include the following price, quantity and data components in their Generation Bid. Suppliers must supply all information that is identified as a required Bid component. Suppliers may, but are not required to, submit information that is identified as an optional Bid component. The Bid Data requirements are additional data on Generator characteristics needed by the Independent Transmission Provider for market operations and reliability purposes.
(i) Start-Up ($). This is an optional Bid component (Market Participants can opt to exclude Start-up Costs in their Energy Bid by setting this cost to $0). Limits on the frequency with which Start-up Bid Costs can be changed must be consistent with the requirements of Part IV, Market Power Monitoring and Mitigation.
(ii) Minimum Generation (No-load) ($/hour). This is an optional Bid component (Market Participants can opt to exclude No-load Costs in their Energy Bid by setting this cost to $0/hour). Limits on the frequency with which Minimum Generation Bid Costs can be changed must be consistent with the requirements of Part IV, Market Power Monitoring and Mitigation.
(iii) Incremental Energy ($/MWh). Market Participants must provide prices for the full MW range of their Operable Capacity, from the Hourly Economic Minimum Level to the
(iv) Emergency Incremental Energy ($/MWh). Market Participants must provide a price for the Emergency MW range of their Operable Capacity, from the Hourly Economic Maximum Level to the Hourly Emergency Maximum Level. This is a required Bid component. The upper limit on the Bid price of Emergency Incremental Energy must be consistent with the requirements of Part IV, Market Power Monitoring and Mitigation. Pricing rules for Emergency uses of Generation Resources are in Section G, 3.7(iii).
(v) Normal Response Rate (MW/min). The expected response rate for Security Constrained Dispatch. This is a required Bid component.
(vi) Regulation Response Rate (MW/min). The response rate for units providing regulation. This is a required Bid component for Resources offering Regulation service.
(vii) Hourly Economic Minimum Level (MW). This is a required Bid component. Limits on the frequency with which the Hourly Economic Minimum Level can be changed must be consistent with the requirements of Part IV, Market Power Monitoring and Mitigation.
(viii) Hourly Economic Maximum Level (MW). This is a required Bid component.
(ix) Hourly Emergency Minimum Level (MW). This is the Minimum Level for a Generator in the event of an Emergency. This is a required Bid component.
(x) Hourly Emergency Maximum Level (MW). This is the Maximum Level for a Generator in the event of an Emergency. This is a required Bid component.
(xi) Start-up Time (hours). The number of hours required to start the Generator. This is a required Bid component.
(xii) Minimum Run Time (hours). This Bid component is up to a maximum of 24 hours. This is a required Bid component. Limits on the Minimum Run Time of particular Generators must be consistent with the requirements of Part IV, Market Power Monitoring and Mitigation.
(xiii) Maximum Run Time (hours). This is an optional Bid component.
(xiv) Minimum Down Time (hours). This is an optional Bid component.
(xv) Maximum Start-up Limit or Maximum Shut Down Limit in 24 Hours (integer number). This is an optional Bid component.
(xvi) Location.
(i) A Virtual Incremental Energy Bid ($/MWh) is an Incremental Energy Bid that specifies that the Bid is a Virtual Transaction,
(i) A Decremental Energy Bid ($/MWh) is a Bid to reduce the output of a Generator. Decremental Energy Bids must include (1) a price, (2) a MW quantity, and (3) a location. The upper limit on the Bid price of Decremental Energy must be consistent with the requirements of Part IV, Market Power Monitoring and Mitigation.
(ii) A Virtual Decremental Energy Bid ($/MWh) is a Decremental Energy Bid that specifies that the Bid is a Virtual transaction. The upper limit on the Bid price of Virtual Decremental Energy must be consistent with the requirements of Part IV, Market Power Monitoring and Mitigation.
(iii) A Decremental Emergency Energy Bid ($/MWh) is a Decremental Energy Bid to reduce the output of a Generator below its Hourly Economic Minimum Level down to its Hourly Emergency Minimum Level. The upper limit on the Bid price of Decremental Emergency Energy must be consistent with the requirements of Part IV, Market Power Monitoring and Mitigation. Pricing rules for Emergency uses of Generation Resources are in Section G, 3.7(iii).
2.4.5 Period of Bids to Supply Energy: A Customer may submit Bids to Supply Incremental Energy or Decremental Energy pursuant to Sections F.2.4.2-2.4.4 that can vary by price ($) and quantity (MW) in each Hour of the Day-Ahead Market.
The Independent Transmission Provider shall calculate the price of Energy at the Load buses and Generation buses in the Independent Transmission Provider Service Area and at the Interface buses between the Independent Transmission Provider Service Area and adjacent Service Areas on the basis of Energy LMPs. LMPs can be set by Bids to sell or purchase Energy, including External Transaction Imports with Bids, and by transmission Bids. If requested by Market Participants the Independent Transmission Provider will establish Hubs and Zones based on a pre-defined set of buses. The Independent Transmission Provider will calculate load-weighted average Energy LMPs for this pre-defined set of buses, defined as Hub Prices or Zone Prices (or Zonal-LMPs). The Energy LMPs, Hub Prices and Zone Prices shall include separate components for the marginal costs of Congestion and the marginal costs of losses. Energy LMPs determined in accordance with this Section shall be calculated and posted on a Day-Ahead basis for each hour of the Day-Ahead Energy Market by [time to be provided by Independent Transmission Provider].
2.5.1 Energy LMP Calculation: The Independent Transmission Provider will calculate for each bus on its system in each hour the Energy LMP, equal to the marginal cost of making an additional increment of Energy available at the bus in the hour, based on the Bids of sellers and buyers selected in the Day-Ahead Security Constrained unit Commitment for Energy supply and purchase. The Independent Transmission Provider shall designate one bus as the Reference Bus,
(i) Calculation of Marginal Congestion Component: The Independent Transmission Provider will calculate the marginal costs of Congestion at each bus as a component of the bus-level LMP. The Marginal Congestion Component (MCC) component of the Energy LMP at bus
(ii) Calculation of Marginal Losses Component: The Independent Transmission Provider will calculate the Marginal Losses Component (MLC) at each Load bus i. The MLC of the LMP at any bus i within the Independent Transmission Provider Service Area is calculated using the equation:
2.5.2 Hub Price Calculation: If requested by Market Participants, the Independent Transmission Provider shall calculate a Hub Price based on the Energy LMPs for a set of buses that comprise the Hub. These Hub Prices are the weighted average of the Energy LMPs at the buses that comprise the Hub. The weights will be pre-determined by the Independent Transmission Provider and remain fixed. [The Independent Transmission Provider may add procedures for determining the buses that comprise the Hub and procedures for changing the weights over time.] The Price for Hub
(i) If requested by Market Participants, the Independent Transmission Provider shall calculate a Zone Price based on the Energy LMPs for a set of buses that comprise the Zone. These Zone Prices are the weighted average of the Energy LMPs at the set of buses that comprise the Zone. The Zone bus weights will equal the fractional share of each load bus in the total load in the Zone in the Hour. [The Independent Transmission Provider may add procedures for determining the buses that comprise the Zone, and assigning weights to those buses, in response to changes in retail load.]
(ii) If the Zone price is used for Settlement purposes, it is subject to the following rules. (1) Each Zone shall include only the buses of Market Participants who agree to be in the Zone (and thus, who agree that their settlements will be calculated based on the zonal price). Alternatively, any one zone shall include only the buses of a single Market Participant. (2) A Market Participant who wants to be billed at a Zonal Price must include in its Zone all of the buses where Energy deliveries will be billed at the Zonal Price. A Market Participant shall not be allowed to settle Energy purchases at a bus or aggregation of buses if that bus or buses are not included in the Zone.
2.6.1 Bid Revenue Sufficiency Guarantee: The Independent Transmission Provider shall calculate, for each Resource scheduled for Energy in the Day-Ahead Market, the amount of the Bid Revenue Sufficiency Guarantee payment, pursuant to Section F.1.11.
2.6.2 Other Payments and Charges: [The Independent Transmission Provider may include in this section market rules for any other payments or charges associated with the efficient and reliable operations of the Day-Ahead Market for Energy.]
(i) [The Independent Transmission Provider may include in this section market rules, including specification of quantities of Energy purchased, calculation of market prices, and determination of out-of-market payments in the event of a shortfall in Energy due to a shortage of available capacity. The market rules shall be in accord with regional or local reliability authority rules and procedures and NERC guidelines.]
(ii) [The Independent Transmission Provider may include in this section procedures for soliciting additional Bids for Energy in the event that Bids and self-scheduled provision of Energy submitted in the Day-Ahead Markets fall short of the Bid-in Load.]
(i) Each purchaser of Day-Ahead Energy shall be charged for all of its Load scheduled to be served from the Independent Transmission Provider's Day-Ahead Energy Market at the Day-Ahead LMPs applicable to each relevant Load bus and hour.
(ii) If a Market Buyer elects to calculate and settle Energy purchases at Zonal-LMPs, and the Zonal price meets the conditions for settlement specified in Section 2.4(c)(ii), then the market buyer shall be charged for all of its load scheduled to be served from the Day-Ahead Energy Market at the Day-Ahead Zonal-LMPs applicable to each relevant Load Zone and time period.
(iii) On any day when a Market Participant is scheduled to purchase any Energy in the Day-Ahead Market for Energy and/or does not Self-Supply a sufficient amount of its forecasted obligation (based on the Day-Ahead Schedule) for Regulation and Operating Reserves, the Market Participant shall be charged a Day-Ahead Bid Revenue Sufficiency Guarantee Charge. The Market Participant's Day-Ahead Supply Bid Revenue Sufficiency Guarantee Charge on any given day shall equal the product of (i) the Market Participant's total load (in MWh) scheduled in the Day-Ahead Market (which shall equal the sum of the Market Participant's total purchases of Energy in the Day-Ahead Market for Energy plus the Market Participant's total load scheduled to be met from Bilateral Transactions) and (ii) the per unit Day-Ahead Supply Bid Revenue Sufficiency Guarantee Charge.
The per unit Day-Ahead Supply Bid Revenue Sufficiency Guarantee Charge for any given day shall equal (i) the aggregate Bid Revenue Sufficiency Guarantee payments payable to Resources in the Day-Ahead Market for that day, divided by (ii) the sum of the total loads (in MWh) of all Market Participants that are to be charged Day-Ahead Supply Bid Revenue Sufficiency Charges for that day.
(i) Suppliers of Day-Ahead Energy shall be paid for all Energy scheduled to be delivered in the Day-Ahead Energy Market at the Day-Ahead LMPs applicable to each relevant generation bus.
(ii) The Independent Transmission Provider shall pay Suppliers any additional payments necessary to provide Day-Ahead Energy in accord with efficient market operations, as specified in Section 2.5
(i) Market Participant's Day-Ahead Demand Bid Revenue Sufficiency Guarantee Charge on any given day shall equal the product of (i) the Market Participant's total quantity (in MWh) scheduled in the Day-Ahead Market (which shall equal the sum of the Market Participant's total sales of Energy in the Day-Ahead Market for Energy plus the Market Participant's total supply scheduled to be met from Bilateral Transactions) and (ii) the per unit Day-Ahead Demand Bid Revenue Sufficiency Guarantee Charge.
The per unit Day-Ahead Demand Bid Revenue Sufficiency Guarantee Charge for any given day shall equal (i) the aggregate Demand Bid Revenue Sufficiency Guarantee payments payable to Resources in the Day-Ahead Market for that day, divided by (ii) the sum of the total supply (in MWh) of all Market Participants that are to be charged Day-Ahead Demand Bid Revenue Sufficiency Guarantee Charges for that day.
3.1 General: Day-Ahead scheduling of Transmission Service allows Market Participants to obtain Transmission Service to support Bilateral Transactions. This section establishes (1) rules for Bidding and/or scheduling Transmission Service, (2) determining prices (
In addition, the Day-Ahead Energy LMPs and Flowgate LMPs are used for Settlement of Congestion Revenue Rights. Holders of Receipt Point-to-Delivery Point Congestion Revenue Rights that seek to settle them against Real-Time Energy LMPs can do so by scheduling transactions in the Day-Ahead Energy Market.
3.2.1 Information Provided by the Customer: Each Customer seeking to be
(i) MW to be transmitted;
(ii) The Point of Receipt and the Point of Delivery;
(iii) The hours when the power is to be transmitted;
(iv) The maximum Transmission Usage Charge ($ per MW) that the Customer is willing to pay to receive the Transmission Service. The Customer may indicate that it desires the indicated Transmission Service regardless of the Transmission Usage Charge, if the Customer has demonstrated to the Independent Transmission Provider that it is capable of paying the highest possible Transmission Usage Charge. The Customer may separately indicate the maximum Charge for Marginal Costs of Congestion and the maximum charge for Marginal Losses that it is willing to pay.
(v) The minimum number of consecutive hours that the Customer desires to receive the Transmission Service.
(vi) The maximum total Transmission Usage Charge (in $ per MW) that the Customer is willing to pay to receive Transmission Service over the total number of scheduled hours.
(vii) Whether the Customer desires to provide additional Energy at the receipt point, in an amount that reflects the Marginal Losses associated with the Transmission Service (which the Independent Transmission Provider shall determine at the close of the Day-Ahead Market) in lieu of paying the charge for Marginal Losses.
3.3 Calculation of Day-Ahead Transmission Usage Charges: The Independent Transmission Provider shall charge a Transmission Usage Charge to all Bilateral Transactions whose transmission service was scheduled in the Day-Ahead Market. This charge is the product of (a) the amount of Energy scheduled to be withdrawn by that Customer in each hour in MWh; and (b) the Day-Ahead LMP at the Point of Delivery (which could be a Load Zone in which Energy is scheduled to be withdrawn or the external bus where Energy is scheduled to be withdrawn if Energy is scheduled to be withdrawn at a location outside the Independent Transmission Provider Service Area), minus the Day-Ahead LMP at the Point of Receipt, in $/MWh. The Independent Transmission Provider shall divide each Transmission Usage Charge into separate components for Marginal Costs of Congestion and Marginal Costs of Losses.
3.3.1 Marginal Congestion Component: The Marginal Congestion Component of the Transmission Usage Charge shall be calculated as the Marginal Congestion Component of the Day-Ahead LMP at the Delivery Point minus the Marginal Congestion Component of the Day-Ahead LMP at the Receipt Point, as described in Section F.2.5(i).
3.3.2 Marginal Losses Component: The Marginal Losses Component of the Transmission Usage Charge shall be calculated as the Marginal Losses Component of the Day-Ahead LMP at the Delivery Point minus the Marginal Losses Component of the Day-Ahead LMP at the Receipt Point, as described in Section F.2.5(ii).
3.4 Flowgate LMP Calculation: The Independent Transmission Provider will, in addition to the calculation of the Energy LMPs, calculate Flowgate Locational Marginal Prices (FMPs) on the set of transmission constraints. The calculation for the Flowgate LMP (FMP) for each Transmission Constraint is defined in Section F.2.5.1(i). Independent Transmission Providers that offer Flowgate Rights must also calculate the Day-Ahead Flowgate LMPs (FMPs) on the Transmission Elements designated as Flowgates, based on a weighted average of the Transmission LMPs on the Transmission Elements that comprise the Flowgate:
3.5.1 Settlement of Receipt Point-to-Delivery Point Congestion Revenue Rights: For each hour in the Day-Ahead Market, the Independent Transmission Provider shall determine the Marginal Congestion Component of each Transmission Usage Charge associated with Transmission Service from a designated Receipt Point to a designated Delivery Point specified in each Receipt Point-to-Delivery Point Congestion Revenue Right (including both Obligation and Option Rights), consistent with Section F.3.3.1. In each instance when the applicable Marginal Congestion Component is positive, the Independent Transmission Provider shall pay to the Primary Holder of the Congestion Revenue Right an amount equal to the applicable hourly Marginal Congestion Component multiplied by the specified MWs. In each instance when the applicable Marginal Congestion Component is negative, the Independent Transmission Provider shall charge to each Primary Holder of an Obligation Right (but not the Primary Holder of an Option Right) an amount equal to the absolute value of the applicable Marginal Congestion Component multiplied by the specified MWs.
3.5.2 Settlement of Flowgate Rights: For each hour in the Day-Ahead Market, the Independent Transmission Provider shall determine, consistent with the provisions in Section F.3.4, the Flowgate LMP in each direction associated with each Flowgate on the transmission system operated by the Independent Transmission Provider.
(i) Holders of Flowgate Rights. For each hour of the Day-Ahead Market, the Independent Transmission Provider shall pay each Primary Holder of a Flowgate Right an amount equal to the applicable hourly Flowgate LMP multiplied by the MWs specified in the Primary Holder's Flowgate Right.
3.6.1 Hourly Congestion Charge Collection: The Hourly Congestion Charge Collection is defined here as the sum of the Hourly Energy Congestion Charge Collection plus the Hourly Transmission Congestion Charge Collection. The Hourly Energy Congestion Charge Collection is defined for any hour of the Day-Ahead Market as (i) the net amounts charged to purchasers of Energy in the Independent Transmission Provider's Day-Ahead Market associated with the Marginal Congestion Component of the hourly LMPs at the purchasers' buses, less (ii) the net amounts paid to sellers of Energy in the Independent Transmission Provider's Day-Ahead Market associated with the Marginal Congestion Component of the hourly LMPs at the sellers' buses. The Hourly Transmission Congestion Charge Collection is defined for any hour of the Day-Ahead Market as the net amounts charged to Customers for Transmission Service scheduled in the Day-Ahead Market associated with the Marginal Congestion Component of the applicable hourly Transmission Usage Charges.
3.6.2 Hourly Net Congestion Revenue Owed to Congestion Revenue Rights Holders: The Hourly Net Congestion Revenue owed to Congestion Revenue Rights Holders for any hour in the Day-Ahead Market is defined here as the net hourly amounts payable to Primary Congestion Revenue Rights Holders pursuant to Sections F.3.5.1 and F.3.5.2.
3.6.3 Determination and Disposition of Congestion Revenue Surplus or Deficit: For each hour of the Day-Ahead Market, the Independent Transmission Provider shall calculate the Hourly Congestion Charge Collection and the Hourly Net Congestion Revenue Owed to Congestion Revenue Rights
3.7.1 Hourly Marginal Loss Charge Collection: The Hourly Marginal Loss Charge Collection is defined here as the sum of the Hourly Energy Marginal Loss Charge Collection plus the Hourly Transmission Marginal Loss Charge Collection. The Hourly Energy Marginal Loss Charge Collection is defined for any hour of the Day-Ahead Market as (i) the net amounts charged to purchasers of Energy in the Independent Transmission Provider's Day-Ahead Market associated with the Marginal Losses Component of the hourly LMPs at the purchasers' buses, less (ii) the net amounts paid to sellers of Energy in the Independent Transmission Provider's Day-Ahead Market associated with the Marginal Losses Component of the hourly LMPs at the sellers' buses. The Hourly Transmission Marginal Loss Charge Collection is defined for any hour of the Day-Ahead Market as the net amounts charged to Customers for Transmission Service scheduled in the Day-Ahead Market associated with the Marginal Cost Component of the applicable hourly Transmission Usage Charges.
3.7.2 Determination and Disposition of Marginal Loss Revenue Surplus: For each hour of the Day-Ahead Market, the Independent Transmission Provider shall calculate the Hourly Marginal Loss Charge Collection and the Hourly Net Energy Revenue Owed to Generators for losses associated with all Transactions. For each hour of the Day-Ahead Market where the Hourly Marginal Loss Charge Collection exceeds the Hourly Net Energy Revenue Owed to Generators for Losses associated with all Transactions, the Independent Transmission Provider shall allocate the revenue surplus to reduction in the charge for Network Access Service. [The Independent Transmission Provider shall determine the exact allocation to each Customer and will file procedures for determining the allocation of the revenue surplus to each Customer.]
4.1 General: The Day-Ahead Market for Regulation establishes clearing prices and settlement rules for Suppliers that have offered eligible Regulation capacity to the market. The Transmission Provider shall procure Regulation through this market on behalf of Load-Serving Entities that have chosen not to Self-supply or purchase through bilateral contracts. Both Generation and Load may Bid to provide Regulation in the Day-Ahead Market if they meet the criteria for eligibility.
4.2 Independent Transmission Provider Obligations: The Independent Transmission Provider has the obligation to provide services (i) to (vii) for the Day-Ahead Market for Regulation. The rules governing these services are contained in this section:
(i) Establish and post on its OASIS Regulation criteria and requirements in accord with regional or local reliability authority rules and NERC guidelines.
(ii) Establish and post on its OASIS a Total Regulation Requirement for the Independent Transmission Provider's Service Area for each hour of the Operating Day. This hourly requirement enters the Day-Ahead Security Constrained Unit Commitment. The Total Regulation Requirement may be subdivided into locational Regulation Requirements; that is, those assigned to specific locations (or Zones) within the Service Area.
(iii) Allocate the obligation for meeting the Total Regulation Requirement among Load-Serving Entities. The obligation of each Load-Serving Entity in any hour shall be equal to the product of (1) the Load-Serving Entity's Real-Time load in the hour as a percentage of the total Real-Time load in the Independent Transmission Provider's Service Area in the hour and (2) the total Day-Ahead Total Regulation Requirement for the hour. The Load-Serving entity's forecasted Regulation obligation for purposes of Section F.2.8.1(iii) shall be equal to the product of (1) the Load-Serving Entity's Day-Ahead scheduled load in an hour and (2) the total Day-Ahead Regulation requirement in the hour.
(iv) Establish and post on its OASIS rules for eligibility to supply Regulation in the Day-Ahead Market that are consistent with this Tariff, including minimum technical requirements and performance standards for a Generator or Load to provide Regulation in response to signals sent by the Independent Transmission Provider.
(v) Establish and post on its OASIS the Bid data requirements and rules for self-scheduling and Bidding, and provide the market functions required for determination of hourly Day-Ahead Spinning Regulation Market Clearing Prices and selection of Day-Ahead Regulation Market Suppliers. Establish and post on its OASIS how these pricing and selection rules are modified to account for locational Regulation requirements. Establish how these pricing and selection rules are modified in the event of shortages in Bid-in Regulation capacity. [The Independent Transmission Provider shall include procedures for self-supply.]
(vi) Establish and post on its OASIS the rules for determination of any additional payments necessary to support efficient operations of the Day-Ahead Regulation Market and the efficient joint operation of the Day-Ahead Market for Regulation and other Day-Ahead Markets.
(vi) Provide the Settlement functions associated with purchase and sale of Regulation in the Day-Ahead Market.
(vii) Post the Day-Ahead Regulation Market Clearing Prices.
4.3 Purchaser Rules and Obligations: The Purchaser of Regulation Service has the obligations and rights set forth in (i) through (iv):
(i) Each Load-Serving Entity is required to fulfill its Operating Day Regulation obligation on the basis of either or both Self-Supply or procurement from the Day-Ahead and Real-Time markets for Regulation. The Transmission Provider shall procure Regulation Reserve on behalf of Load-Serving Entities and determine the final cost of each MW purchased.
(ii) A Load-Serving entity may meet its Regulation obligation through Self-Supply by offering into the Day-Ahead Market for Regulation its own Resources capable of supplying Regulation or Resources for which it has made contractual arrangements with third parties able to provide Regulation on a comparable basis. Such self-supplied Resources must be placed under the Independent Transmission Provider's control, and must meet the Independent Transmission Provider's rules for eligibility to supply Regulation (see Section 5.2 and 5.4.1). These self-supplied Resources are scheduled in the Day-Ahead Market for Regulation at a Supply Bid Price of $0/MWh. Also, a Load-Serving Entity shall be paid the applicable Day-Ahead Market Clearing Price for any Regulation self-supplied in excess of its obligation.
(iii) A Load-Serving Entity that has not fulfilled all of its Regulation obligation through Self-Supply is required to allow the Independent Transmission Provider to procure sufficient Regulation that it has not self-supplied through the Day-Ahead, and if necessary, the Real-Time Regulation Market to fulfill the obligation that is not self-supplied.
4.4.1 Eligibility to Supply: To be eligible to supply Regulation in the Day-Ahead Market for Regulation, a Supplier or a Generator contracted by a Supplier must meet criteria (i) to (v), as follow.
(i) Suppliers of Regulation may use only Generators and/or Load that are electrically within the Independent Transmission Provider's Service Area.
(ii) Suppliers of Regulation may use only Generators and/or Load that are able to respond to AGC Base Point Signals sent by the Independent Transmission Provider pursuant to the Independent Transmission Provider procedures.
(iii) Suppliers of Regulation may use only Generators and/or Load that meet Independent Transmission Provider standards for Generator or Load performance.
(iv) Suppliers of Regulation shall not use, contract to provide, or otherwise commit the capability that is designated to provide Regulation to provide Energy or Spinning Reserve to any party other than the Independent Transmission Provider.
(v) Suppliers of Regulation shall provide the Bid information specified in Section F.4.4.2.
4.4.2 Specification of Bids: Suppliers of Regulation must provide the Bid information in (i) to (vii), as follows.
(i) Availability Bid price ($/MWh).
(ii) Regulation Capability (MW) of the Generator supplying Regulation.
(iii) Response Rate (MW/Minute) of the Generator supplying Regulation.
(iv) Upper and Lower Regulation Limits (MW).
(v) Hours of availability to provide Regulation.
(vi) Any additional physical data required by the Independent Transmission Provider
(vii) Location of Resources
4.5 Calculation of Market Clearing Price: The Independent Transmission Provider shall calculate a Market Clearing Price for the Day Ahead Market for Regulation, using the following methodology.
The Independent Transmission Provider shall establish a Supplier Regulation Price for each Supplier based on the sum of the Supplier's Availability Bid and its Day-Ahead Unit-Specific Opportunity Cost (as defined below). The hourly Day-Ahead Regulation Market Clearing Price shall be the higher of (i) the highest Supplier Regulation Price needed to meet the Independent Transmission Provider's Regulation Requirement for each hour of the Next Day, or (ii) the highest Market Clearing Price in the hour for Operating Reserves.
The Unit-Specific Opportunity Costs of a Resource Bidding to sell Regulation each hour shall be equal to the product of:
(i) the deviation of the Regulation set point of the Generator that is required in order to provide Regulation from the Resource's expected output level if it had been scheduled or dispatched in economic merit order to provide Energy, times
(ii) the greater of (a) the $/MWh difference between the expected Energy LMP at the generation bus for the Resource and the Bid price for Energy from the Resource (at the megawatt level of the Regulation set point for the Resource) in the Real-Time Energy Market and (b) zero.
4.6.1 Bid Revenue Sufficiency Guarantee: The Independent Transmission Provider shall calculate for each Resource scheduled for Regulation in the Day-Ahead Market the amount of the Bid Revenue Sufficiency Guarantee payment, pursuant to Section F.1.11.
4.6.2 Other Payments and Charges: [The Independent Transmission Provider may include in this section market rules for any other payments or charges associated with the efficient and reliable operations of the Day-Ahead Market for Regulation.]
(i) [The Independent Transmission Provider may include in this section market rules, including calculation of market prices and determination of out of market payments, in the event of a shortfall in Regulation in the Day-Ahead Market due to a shortage of available capacity. The market rules shall be in accord with regional or local reliability authority rules and procedures and NERC guidelines.]
(ii) [The Independent Transmission Provider may include in this section procedures for soliciting additional Bids for Regulation in the event that Bids and self-supplied provision of Regulation submitted in the Day-Ahead Markets fall short of the Regulation Requirement for the Operating Day.
4.8 Settlement: The Independent Transmission Provider will provide timely settlement of sales of Regulation in the Day-Ahead Market for Regulation pursuant to Section 4.8.1.
(i) The Independent Transmission Provider shall pay each Supplier, the hourly Day-Ahead Market Clearing Price for Regulation times the Quantity (MW) of the Supplier's Regulation scheduled (
5.1 General: The Independent Transmission Provider shall establish bid-based markets for the types of Operating Reserve—Spinning Reserves (
5.2 Independent Transmission Provider Obligations: The Independent Transmission Provider has the obligation to provide services (i) to (vii) for the Day-Ahead Market for Spinning Reserve. The rules governing these services are contained in this section:
(i) Establish and post on its OASIS Spinning Reserve criteria and requirements in accord with regional or local reliability authority rules and NERC guidelines.
(ii) Establish and post on its OASIS a Total Spinning Reserve Requirement for the Independent Transmission Provider's Service Area for each hour of the Operating Day. This hourly requirement enters the Day-Ahead Security Constrained Unit Commitment. The Total Spinning Reserve Requirement may be sub-divided into locational Spinning Reserve Requirements; that is, assigned to specific locations (or Zones) within the Service Area.
(iii) Allocate the obligation for meeting the Total Spinning Reserve Requirement among Load-Serving Entities. The obligation of each Load-Serving Entity in any hour shall be equal to the product of (1) the Load-Serving Entity's Real-Time load in the hour as a percentage of the total Real-Time load in the Independent Transmission Provider's Service Area in the hour and (2) the total Day-Ahead Total Spinning Reserve Requirement for the hour. The Load-Serving Entity's forecasted Spinning Requirement obligation for purposes of Section F.2.8.1(iii) shall be equal to (1) the Load-Serving Entity's Day-Ahead scheduled load in an hour multiplied by (2) the total Day-Ahead Spinning Reserve requirement in the hour.
(iv) Establish and post on its OASIS rules for eligibility to supply Spinning Reserve in the Day-Ahead Market that are consistent with this Tariff, including minimum technical requirements and performance standards for a Generator or Load to provide Spinning Reserve.
(v) Establish and post on its OASIS the Bid data requirements and rules for self-scheduling and Bidding that are consistent with this Tariff, and provide the market functions required for determination of hourly Day-Ahead Spinning Reserve Market Clearing Prices and selection of Day-Ahead Spinning Reserve Market Suppliers. Establish how these pricing and selection rules are modified to account for locational Spinning Reserve requirements. Establish how these pricing and selection rules are modified in the event of shortages in Bid-in Spinning Reserve capacity.
(vi) Establish and post on its OASIS the rules for determination of any additional payments necessary to support efficient operations of the Day-Ahead Market for Spinning Reserve and the efficient joint operation of the Day-Ahead Market for Spinning Reserve and other Day-Ahead Markets.
(vii) Provide the Settlement functions associated with sale of Spinning Reserve in the Day-Ahead Market.
(vii) Post the Day-Ahead Market Clearing Prices for Spinning Reserve.
(i) Each Load-Serving Entity is required to fulfill its Operating Day Spinning Reserve obligation on the basis of either or both self-supply or procurement from the Day-Ahead and Real-Time markets for Spinning Reserve. The Independent Transmission Provider shall procure Spinning Reserve on behalf of Load-Serving Entities and determine the final cost of each MW purchased.
(ii) A Load-Serving Entity may meets its Spinning Reserve obligation through Self-Supply by offering its own Resources capable of supplying Spinning Reserves or Resources for which it has made contractual arrangements with third parties able to provide Spinning Reserves on a comparable basis. Such self-supplied Resources must be placed under the Independent Transmission Provider's control, and must meet the Independent Transmission Provider's rules for eligibility (see Section 5.2 and 5.4.1). These self-supplied Resources are scheduled in the Day-Ahead Spinning Reserves Market. A Load-Serving Entity shall be paid the applicable Day-Ahead Market clearing price for any Spinning Reserve self-supplied in excess of its obligation.
(iii) A Load-Serving Entity that has not fulfilled all of its Spinning Reserve obligation through Self-Supply is required to allow the Independent Transmission Provider to procure sufficient Spinning Reserve that it has not Self-Supplied through the Day-Ahead and, if necessary, Real-Time Spinning Reserve market to fulfill the obligation that is not Self-Supplied.
5.4.1 Eligibility to Supply: To be eligible to supply Spinning Reserve in the Day-Ahead Market for Spinning Reserve, a Supplier or a Generator contracted by a Supplier must meet criteria (i) to (iv), as follow.
(i) Suppliers of Spinning Reserve may use only Generators and/or Load that are
(ii) Suppliers of Spinning Reserve may use only Generators and/or Load that meet Independent Transmission Provider standards for Generator performance; similarly, Demand Resources must meet Independent Transmission Provider standards for response capability.
(iii) Suppliers of Spinning Reserve shall not use, contract to provide, or otherwise commit the capability that is designated to provide Spinning Reserve to provide Energy, Regulation or Supplemental Reserve to any party other than the Independent Transmission Provider.
(iv) Suppliers of Spinning Reserve shall provide the Bid information specified in Section 5.4.2.
5.4.2 Specification of Bids: Suppliers of Spinning Reserve must provide the Bid information in (i) to (vi), as follows.
(i) Availability Bid price ($/MWh).
(ii) Response Rate (MW/Minute) of the Generator supplying Spinning Reserve.
(iii) Hours of availability to provide Spinning Reserve.
(iv) Any additional physical data required by the Independent Transmission Provider.
(v) Location of Resource.
5.5.1 Methodology for Calculation of Clearing Price: The Independent Transmission Provider shall calculate a Market Clearing Price for the Day Ahead Market for Spinning Reserve, using the following methodology.
The Independent Transmission Provider shall establish a Supplier Spinning Reserve Price for each Supplier based on the sum of the Supplier's Availability Bid and its Day-Ahead Unit-Specific Opportunity Cost (as defined below). The hourly Day-Ahead Spinning Reserve Market Clearing Price shall be the higher of (i) the highest Supplier Spinning Reserve Price needed to meet the Independent Transmission Provider's Spinning Reserve Requirement for each hour of the Next Day, or (ii) the highest Market Clearing Price in the hour for Supplemental Reserves.
The Unit-Specific Opportunity Costs of a Resource Bidding to sell Spinning Reserve each hour shall be equal to the product of:
(i) the deviation of the set point (MWh) of the Generator that is required in order to provide Spinning Reserve from the Resource's output level if it had been scheduled or dispatched in economic merit order to provide Energy, times
(ii) the greater of (a) the $/MWh difference between the Energy LMP at the generation bus for the Resource and the Bid price for Energy from the Resource (at the megawatt level of the Spinning Reserve set point for the Resource) in the Day-Ahead Energy Market and (b) zero.
5.5.2 Calculation of Zonal or Locational Prices: Separate Day-Ahead Spinning Reserve Market Clearing Prices will be calculated for Spinning Reserve located in each distinct Reserve Location for which there is a separate Spinning Reserve requirement. When there are no binding transmission constraints between Reserve Locations, the Day-Ahead Ancillary Price for Spinning Reserve shall be the same in each of the locations.
5.5.3 Transmission for Operating Reserves: A Supplier located outside of a particular Reserve Location may provide Spinning Reserves if the necessary transmission arrangements to deliver Energy from the Supplier's capacity to the Reserve Location are made. The cost of any transmission service would have to be included in evaluating the total cost of Operating Reserves.
5.6.1 Bid Revenue Sufficiency Guarantee: The Independent Transmission Provider shall calculate, for each Resource scheduled for Spinning Reserve in the Day-Ahead Market the amount of the Bid Revenue Sufficiency Guarantee payment, pursuant to Section F.1.11.
5.6.2 Other Payments and Charges: [The Independent Transmission Provider may include in this section market rules for any other payments or charges associated with the efficient and reliable operations of the Day-Ahead Markets for Spinning Reserves.]
(i) [The Independent Transmission Provider may include in this section market rules, including specification of quantities, calculation of market prices, and determination of out of market payments in the event of a shortfall in the required system requirements for Spinning Reserves due to a shortage of available capacity. The market rules shall be in accord with regional or local reliability authority rules and procedures and NERC guidelines.]
(ii) [The Independent Transmission Provider may include in this section procedures for soliciting additional Bids for Spinning Reserves in the event that Bids and self-supplied provision of Spinning Reserves submitted in the Day-Ahead Markets fall short of the required system requirements for Spinning Reserves.]
5.8 Settlement: The Independent Transmission Provider will provide timely settlement of purchases and sales of Spinning Reserve in the Day-Ahead Market for Spinning Reserve pursuant to Sections 5.8.1.
(i) The Independent Transmission Provider shall pay each Supplier the hourly Day-Ahead Spinning Reserve Market Clearing Price times the quantity (MW) of the Supplier's Spinning Reserve capability provided in the hour.
6.1 General: The Independent Transmission Provider shall establish the types of Supplemental Reserves (
6.2 Independent Transmission Provider Obligations: The Independent Transmission Provider has the obligation to provide services (i) to (viii) for the Day-Ahead Markets for Supplemental Reserves. The rules governing these services are contained in this section:
(i) Establish and post on its OASIS Supplemental Reserve criteria and requirements in accord with regional or local reliability authority rules and NERC guidelines.
(ii) Establish and post on its OASIS Total Supplemental Reserves Requirements for the Independent Transmission Provider's Service Area for each Hour of the Operating Day. This hourly requirement enters the Day-Ahead Security Constrained Unit Commitment. The Total Supplemental Reserve Requirements may be subdivided into locational Supplemental Reserve Requirements; that is, assigned to specific locations (or zones) within the Service Area.
(iii) Allocate the obligation for meeting the Total Supplemental Reserve Requirement among Load-Serving Entities. The obligation of each Load-Serving Entity in any hour shall be equal to the product of (1) the Load-Serving Entity's Real-Time load in the hour as a percentage of the total Real-Time load in the Independent Transmission Provider's Service Area in the hour and (2) the Total Day-Ahead Total Supplemental Reserve Requirement for the hour. The Load-Serving Entity's forecasted Supplemental Reserve obligation for purposes of Section F.2.8.1 (iii) shall be equal to the product of (1) the Load-Serving Entity's Day-Ahead scheduled load in the hour as a percent of the total Day-Ahead load in the Independent Transmission Provider's Service Area in the hour and (2) the Total Day-Ahead Supplemental Reserve Requirement in the hour.
(iv) Establish and post on its OASIS rules for eligibility to supply Supplemental Reserves in the Day-Ahead Market that are consistent with this Tariff, including minimum technical requirements and performance standards for a Generator and/or Load to provide Supplemental Reserves.
(v) Establish and post on its OASIS the Bid data requirements and rules for self-scheduling and Bidding that are consistent with this Tariff, and provide the market functions required for determination of hourly Day-Ahead Supplemental Reserves Market Clearing Prices and selection of Day-Ahead Supplemental Reserves Market Suppliers. Establish how these pricing and selection rules are modified to account for locational Supplemental Reserves requirements. Establish how these pricing and selection rules are modified in the event of a shortage of Bid-in Supplemental Reserve capacity.
(vi) Provide the Settlement functions associated with purchase and sale of Supplemental Reserves in the Day-Ahead Market.
(vii) Post the Day-Ahead Supplemental Reserves Market Clearing Prices.
(i) Each Load-Serving Entity is required to fulfill its Operating Day Supplemental Reserves obligation on the basis of either or both Self-Supply or procurement from the Day-Ahead and Real-Time markets for Supplemental Reserves. The Independent Transmission Provider shall procure Supplemental Reserve on behalf of Load-Serving Entities and determine the final cost of each MW purchased.
(ii) A Load-Serving Entity may meet its Supplemental Reserve obligation through Self-Supply by offering into the Day-Ahead Market for Supplemental Reserves its own Resources capable of supplying Supplemental Reserves or Resources for which it has made contractual arrangements with third parties able to provide Supplemental Reserves on a comparable basis. Such self-supplied Resources must be placed under the Independent Transmission Provider's control, and must meet the Independent Transmission Provider's rules for eligibility (see Sections 6.2 and 6.4.1). These self-supplied Resources are scheduled in the Day-Ahead Reserves Market. A Load-Serving Entity shall be paid the applicable Day-Ahead Market clearing price for any Supplemental Reserve self-supplied in excess of its obligation.
(iii) A Load-Serving Entity that has not fulfilled all of its Supplemental Reserves obligation through self-supply is required to allow the Independent Transmission Provider to procure sufficient Supplemental Reserves that it has not Self-Supplied through the Day-Ahead and, if necessary, Real-Time Supplemental Reserves market to fulfill the obligation that is not Self-Supplied.
6.4.1 Eligibility to Supply: To be eligible to supply Supplemental Reserves in the Day-Ahead Markets for Supplemental Reserve, a Supplier or a Generator contracted by a Supplier must meet criteria (i) to (iv), as follow.
(i) Subject to Independent Transmission Provider requirements, Suppliers of Supplemental Reserves may use Generators and/or Load that are electrically within or outside the Independent Transmission Provider's Service Area.
(ii) Suppliers of Supplemental Reserves may use only Generators and/or Load that meet Independent Transmission Provider standards for Generator performance.
(iii) Suppliers of Supplemental Reserves shall not use, contract to provide, or otherwise commit the capability that is designated to provide Supplemental Reserves to provide Energy, Regulation and Frequency Response, or Spinning Reserve to any party other than the Independent Transmission Provider.
(iv) Suppliers of Supplemental Reserves shall provide the Bid information specified in Section 4.2.
6.4.2 Specification of Bids: Suppliers of Supplemental Reserves must provide the Bid information in (i) to (iv), as follows.
(i) Availability Bid price ($/MWh).
(ii) Response Rate (MW/Minute) of the Resource supplying Supplemental Reserve.
(iii) Hours of availability to provide Supplemental Reserve.
(iv) Any additional physical data required by the Independent Transmission Provider.
(v) Location of Resource.
6.5.1 Methodology for Calculation of Prices: The Independent Transmission Provider shall calculate a Market Clearing Price for each Day-Ahead Market for Supplemental Reserves, using the following methodology.
The Independent Transmission Provider shall establish a Supplier Estimated Supplemental Reserve Price for each Supplier based on the sum of the Supplier's Availability Bid and its Day-Ahead Unit-Specific Opportunity Cost (as defined below). The hourly Day-Ahead Supplemental Reserve Market Clearing Price shall be the higher of (i) the highest Supplier Supplemental Reserve Price needed to meet the Independent Transmission Provider's Supplemental Reserve Requirement for each hour of the Next Day, or (ii) the Market Clearing Price in the hour for a lower quality Supplemental Reserve.
The Unit-Specific Opportunity Costs of a Resource Bidding to sell Supplemental Reserves each hour shall be equal to the product of:
(i) the deviation of the set point (MWh) of the Generator that is expected to be required in order to provide Supplemental Reserve from the Resource's output level if it had been scheduled or dispatched in economic merit order to provide Energy, times
(ii) the absolute value of the difference between the Energy LMP at the generation bus for the Resource and the Bid price for Energy from the Resource (at the megawatt level of the Supplemental Reserve set point for the Resource) in the Day-Ahead Energy Market.
6.5.2 Calculation of Zonal or Locational Prices: Separate Day-Ahead Supplemental Reserve Market Clearing Prices will be calculated for Supplemental Reserve located in each distinct Reserve Location for which there is a separate Supplemental Reserve requirement. When there are no binding transmission constraints between Reserve Locations, the Day-Ahead Ancillary Price for Supplemental Reserve shall be the same in each of the locations.
6.5.3 Transmission for Operating Reserves: A Supplier located outside of a particular Reserve Location may provide 10-Minute Supplemental Reserve if the necessary arrangements Energy from the Supplier's capacity to the Reserve Location are made. The cost of any transmission service would have to be included in evaluating the total cost of Operating Reserves.
6.6.1 Bid Revenue Sufficiency Guarantee: The Independent Transmission Provider shall calculate, for each Resource scheduled for Supplemental Reserves in the Day-Ahead Market the amount of the Bid Revenue Sufficiency Guarantee payment, pursuant to Section F.1.11.
6.6.2 Other Payments and Charges: [The Independent Transmission Provider may include in this section market rules for any other payments or charges associated with the efficient and reliable operations of the Day-Ahead Markets for Supplemental Reserves.]
(i) [The Independent Transmission Provider may include in this section market rules, including specification of quantities of Supplemental Reserve purchased, calculation of market prices, and determination of out-of-market payments in the event of a shortfall in the required system requirements for Supplemental Reserves due to a shortage of available capacity. The market rules shall be in accord with regional or local reliability authority rules and procedures and NERC guidelines.]
(ii) [The Independent Transmission Provider may include in this section procedures for soliciting additional Bids for Supplemental Reserves in the event that Bids and self-supplied provision of Supplemental Reserves submitted in the Day-Ahead Markets fall short of the required system requirements for Supplemental Reserves.]
6.8 Settlement: The Independent Transmission Provider will provide timely settlement of sales of Supplemental Reserves in the Day-Ahead Markets for Supplemental Reserves pursuant to Sections 6.8.1.
(i) The Independent Transmission Provider shall pay each Supplier the hourly Day-Ahead Supplemental Reserve Market Clearing Price times the quantity (MW) of the Supplier's Supplemental Reserve capability provided in the hour.
The Independent Transmission Provider will operate a Real-Time Market in order to develop a post Day-Ahead Schedule and Real Time Dispatch Schedule for Transmission Service, Energy, and Ancillary Services. The Real-Time Schedule will be developed so as to maximize the combined economic value of transmission service, Energy, and Ancillary Services, based on the Bids submitted.
1.1 General: The Independent Transmission Provider shall establish procedures for modification of the Day-Ahead Schedule and development of the Real-Time Schedule and dispatch that incorporate components (i) to (vi), as follow.
(i) The Independent Transmission Provider will allow Market Participants that have had selected in the Day-Ahead Schedule (1) a Quantity of Energy, whether a purchase or sale, Regulation or Operating Reserve, (2) a Bilateral Transaction, or (3) a Self-Schedule or Self-Supply, to change the Quantities in the Schedule at any time following the close of the Day-Ahead Market but before the [Scheduling Deadline to be provided by the Independent Transmission Provider] prior to each Dispatch Hour in the Operating Day.
(ii) The Independent Transmission Provider will allow Suppliers or Purchasers of Energy and Suppliers of Regulation or
(iii) The Independent Transmission Provider will allow Market Participants to submit new Bilateral Transactions and Self-Schedules at any time following the close of the Day-Ahead Market but before the [Scheduling Deadline to be provided by the Independent Transmission Provider] prior to each Dispatch Hour in the Operating Day.
(iv) The Independent Transmission Provider will post on its OASIS the Deadlines for Scheduling Revised or New Quantities and for submission of Price Bids into the Real-Time Market, consistent with the Tariff.
(v) The Independent Transmission Provider shall establish scheduling procedures for External Transactions during each Hour and Quarter-Hour of the Operating Day, consistent with the requirements established by the Commission.
(vi) A Supplier or Purchaser in the Real-Time Market, as well as a Bilateral Schedule or Self-Schedule that submits a Price Bid, that follows Independent Transmission Provider Dispatch Instructions that deviate from the previously selected schedules submitted by the Supplier or Purchaser in the Day-Ahead Market, shall be provided with a Bid Revenue Sufficiency Guarantee, pursuant to Section G.2.3.
(i) Suppliers that wish to increase the amount of Energy scheduled above the amounts scheduled in the Day-Ahead Market, regardless of the applicable Real-Time Energy LMP, may so inform the Independent Transmission Provider [before the scheduling deadline provided by the Independent Transmission Provider] prior to each Dispatch Hour in the Operating Day.
(ii) Such Suppliers of Energy are required to submit a MW quantity and a location.
(i) All Internal Transactions submitted or modified after the Day-Ahead Schedule must specify a Receipt Point, a Delivery Point, a MW quantity injected at the Receipt Point and a MW quantity withdrawn at the Delivery Point.
(ii) Internal Transactions may voluntarily submit a Price Bid ($/MW) over some or all of the MW range which indicates the Customer's willingness to reduce or eliminate the Transaction in the next Security Constrained Dispatch time period at the Independent Transmission Provider's instruction when the applicable Real-Time Transmission Usage Charge reaches or exceeds the price Bid.
(iii) Internal Transactions may voluntarily submit a Decremental Energy Bid (in $/MW) over some or all of the MW range, which indicates the Customer's willingness to reduce the amount of Energy supplied at the Receipt Point at the Independent Transmission Provider's instruction (while retaining the amount of Energy withdrawn at the Delivery Point) when the Real-Time Energy LMP at the Receipt Point falls below the Decremental Energy Bid.
(i) All External Transactions submitted or modified after the Day-Ahead Schedule must specify a Receipt Point, a Delivery Point, a MW quantity injected at the Receipt Point and a MW quantity withdrawn at the Delivery Point. Either the Receipt Point or the Delivery Point must be a point at the boundary of the Independent Transmission Provider Service Area. All External Transactions must specify a minimum run time.
(ii) The Independent Transmission Provider shall offer Market Participants with External Transactions submitted after the Day-Ahead Schedule or modifying the Day-Ahead Schedule two options for scheduling. (1) External Transactions can be scheduled without a Price Bid. (2) External Transactions can be scheduled with a Price Bid ($/MW) over some or all of the MW quantity being scheduled.
(iii) External Transactions that are Exports may voluntarily submit a Decremental Energy Bid (in $/MW) over some or all of the MW range, which indicates the Customer's willingness to reduce the amount of Energy supplied at the Receipt Point at the Independent Transmission Provider's instruction (while retaining the amount of Energy withdrawn at the Delivery Point) when the Real-Time Energy LMP at the Receipt Point falls below the Decremental Energy Bid. External Transactions that are imports may voluntarily submit an Incremental Energy Bid (in $/MW) over some or all of the MW range, which indicates the Customer's willingness to reduce the amount of Energy withdrawn at the Delivery Point at the Independent Transmission Provider's instruction (while retaining the amount of Energy injected at the Receipt Point) when the Real-Time Energy LMP at the Delivery Point rises above the Incremental Energy Bid.
(iv) The Independent Transmission Provider will adjust External Transactions schedules on quarter hour notice.
(v) The Independent Transmission Provider shall accept Short Notice External Transactions (SNETs) following the Real-Time Trading Deadline up to some later SNET Deadline set by the Independent Transmission Provider. SNETs are not eligible to set Real-Time LMPs. SNETs have the lowest priority in the event of Curtailment of Customers.
1.4 Rules for Bidding: The Independent Transmission Provider shall evaluate accept all eligible Bids for Energy Supply and Demand, Regulation, and Operating Reserves. The requirements for Bid eligibility and the Bid Specifications are in Sections G 3.4, G.5.4 and G.7.4.
2.1 Intra-Day Security Constrained Unit Commitment: The Independent Transmission Provider may undertake a periodic intra-day Security-Constrained Unit Commitment for Resources with Start-up and No-load costs not committed in the Day-Ahead Schedule.
2.2 Security Constrained Dispatch: The Independent Transmission Provider shall run a Security Constrained Dispatch every five minutes to minimize the total Bid Production Costs of meeting the system Load and maintaining scheduled interchanges with adjacent Service Areas over the next Security Constrained Dispatch Interval. Bid Production Costs, for this purpose, will be calculated using selected Day-Ahead and Real-Time Bids for Energy and Ancillary Services submitted into the Real-Time Market. The Independent Transmission Provider shall dispatch the Power System consistent with the Bids that are submitted by Suppliers and accepted by the Independent Transmission Provider, while satisfying the actual system Load.
2.3 Intra-Day Bid Revenue Sufficiency Guarantee: The Independent Transmission Provider shall ensure the minimum recovery of each Reserve's Bid prices for Resources scheduled after the close of the Day-Ahead Market, committed on an intra-day basis, or dispatched through the Real-Time Market.
(i) The Independent Transmission Provider shall determine, on a daily basis, if any Resource committed by the Independent Transmission Provider in the Real-Time Market will not recover its Start-Up, No Load and Energy Bid Price through revenues in the Real-Time Energy and Ancillary Services markets.
(ii) If the Start-Up and No Load Bids plus the net Energy and Ancillary Services Bid Price over the twenty-four (24) hour day of any Supply Resource scheduled, committed, or dispatched by the Independent Transmission Provider exceeds its Real-Time LMP revenue and Ancillary Service Revenue over the twenty-four (24) hour day, then that Supplier's Real-Time LMP revenue, the Real-Time Supply Bid Revenue Sufficiency Guarantee payment, shall be augmented by an additional payment in the amount of the shortfall. Resources not scheduled, committed, or dispatched by the Independent Transmission Provider, but which continue to operate shall not receive such a payment. This payment shall be supported through revenue collected from the Supply Bid Revenue Sufficiency Guarantee Charge.
(iii) If the total Real-Time Energy charges to any Demand Resource over the twenty-four (24) hour day exceeds its maximum willingness to pay, as reflected by the difference of its Real-Time Energy Bids and Start-up Cost Bid, the Demand Resource shall be augmented by a payment, the Demand Bid Revenue Sufficiency Guarantee Payment, in the amount of the overcharge. This payment is supported through revenues collected from the Demand Bid Revenue Sufficiency Guarantee Charge.
3.1 General: The Real-Time Market for Energy establishes clearing prices and settlement rules for Suppliers of Energy that have offered eligible Energy capacity to the market and for Purchasers of Energy that have chosen not to self-supply or procure through bilateral contracts.
3.2 Independent Transmission Provider Obligations: The Independent Transmission Provider has the obligations to provide services (i) to (v) for the Real-Time Market for
(i) Establish and post on its OASIS rules that are consistent with this Tariff for eligibility to supply Energy in the Real-Time Market.
(ii) Establish and post on its OASIS the Bid data requirements and rules that are consistent with this Tariff and provide the market functions required for determination of hourly Real-Time Energy Market Clearing Prices and selection of Real-Time Energy Market Suppliers.
(iii) Establish and post on its OASIS the rules that are consistent with this Tariff for determination of any Additional Payments necessary to support efficient operations of the Real-Time Energy Market and/or the efficient operation of other Real-Time Markets.
(iv) Provide the Settlement functions associated with purchase and sale of Energy in the Real-Time Market.
(v) Post the Real-Time LMPs for Energy.
3.3 Purchaser Rules and Obligations
3.3.1 Specification of Bids. Bids to Purchase Energy in the Real-Time Market for Energy shall have the same price, quantity and data requirements as Bids to Purchase Energy in the Day-Ahead Market for Energy, as set forth in Section F.2.3.1. Virtual Demand Bids are not permitted in the Real-Time Market.
3.4 Supplier Rules and Obligations
3.4.1 Eligibility to Supply
(i) Suppliers of Real-Time Energy may not re-submit capacity selected for Energy in the Day-Ahead Market. Suppliers of Real-Time Energy may lower the Bid Price of capacity not selected for Energy in the Day-Ahead Market.
(ii) Suppliers of Real-Time Energy shall provide the Bid information specified in Section F.2.4.2.
3.4.2 Specification of Bids: Bids to Supply Energy in the Real-Time Energy Market, including Incremental and Decremental Energy, have the same price, quantity and data requirements as Bids to Supply Energy in the Day-Ahead Market for Energy, as set forth in Sections F.2.3 (b)-(d). Virtual Supply Bids are not permitted in the Real-Time Market.
3.4.3 Period of Bids to Supply Energy: Bids to Supply Incremental Energy or Decremental Energy pursuant to Sections F.3.4.1-3.4.2 can vary by price ($) and quantity (MW) in each Hour of the Real-Time Market.
3.5 Calculation of Real-Time Locational Marginal Prices for Energy
(i) Immediately in advance of each Security Constrained Dispatch Interval, the Independent Transmission Provider shall post the Real-Time Energy LMPs for each bus on its system that it estimates will clear the market and match Generation with Load during the upcoming Security Constrained Dispatch Interval, based on the Real-Time Bids submitted. These estimated Energy LMPs shall be called Ex Ante LMPs. The pricing calculations for each of these LMPs should be the same as those for the Day-Ahead Market, as set forth in Section F.2.4, with the modifications contained in this Section G.3.5.
(ii) Power system operations in the Real-Time Market, including, but not limited to, the determination of the least costly means of serving Load, depend upon the availability of a complete and consistent representation of Generator outputs, Loads, and power flows on the network. In calculating LMPs, the Independent Transmission Provider shall obtain a complete and consistent description of conditions on the electric network by using the most recent power flow solution produced by the Independent Transmission Provider's dispatch software and/or software that measures actual system conditions in Real-Time, such as a State Estimator.
3.5.1 Ex Post Energy LMP Calculation: At the close of each Security Constrained Dispatch Interval, the Independent Transmission Provider shall calculate Energy LMPs for each bus on its system that shall be used for settlement of the Real-Time Market. These LMPs shall be called Ex Post Energy LMPs. The Ex Post Energy LMP for a Security Constrained Dispatch Interval at a given bus shall be equal to the lower of (a) the Ex Ante Energy LMP for that bus; and (b) the marginal cost of making available to the bus the Energy actually produced during the Security Constrained Dispatch Interval by suppliers that submitted Real-Time Energy Bids.
3.5.2 Determination of Energy LMPs by Fixed Block Resources: In calculating LMPs in the Day-Ahead Market, the Bid of any Fixed Block Unit (
3.5.3 Five Minute Real-Time LMPs: During the Operating Day, the LMP calculation shall be performed every [five minutes, or some other minute by minute interval determined by the system technology and software], using the Independent Transmission Provider's LMP methodology, producing a set of Real-Time Prices based on system conditions during the preceding interval.
3.6 Calculation of Additional Payments and Charges
3.6.1 Bid Revenue Sufficiency Guarantee: The Independent Transmission Provider shall calculate, for each Resource scheduled, committed or dispatched for Energy in the Real-Time Market, the amount of the Bid Revenue Sufficiency Guarantee payment, pursuant to Section G.2.3.
3.6.2 Undergeneration by Suppliers
(i) [The Independent Transmission Provider may file to establish pricing rules, including market-based penalties, for Suppliers of Energy that persistently provide less Energy in Real-Time than instructed. One market-based penalty is to require the Supplier to buy Regulation at the Real-Time Market Clearing Price for Regulation in a quantity equivalent to the Energy not provided.]
(ii) [Exemptions: If the Independent Transmission Provider proposes penalties, suppliers, such as intermittants, that have constraints on following Dispatch Instructions or other operating limitations should be exempt from these penalties.]
(iii) Replacement Reserve Penalty [The Transmission Provider may file to establish market-based penalties for Suppliers of Regulation that provide less Regulation in Real-Time than instructed.]
3.6.3 Other Payments and Charges: [The Independent Transmission Provider may include in this section market rules for any other payments or charges associated with the efficient and reliable operations of the Real-Time Markets for Energy.]
3.7 Market Rules for Shortages or Emergencies
(i) [The Independent Transmission Provider may include in this section market rules, including calculation of market prices and determination of out-of-market payments, in the event of a shortfall in Energy in the Real-Time Market due to a shortage of available capacity or an Emergency. The market rules shall be in accord with regional or local reliability authority rules and procedures and NERC guidelines.]
(ii) After the Day-Ahead Schedule is published, and up to a pre-specified period prior to each Dispatch Hour, the Independent Transmission Provider may, after giving notice to affected Resources, in order to prevent or address an Emergency, raise their Bid-in upper operating limits to their maximum and make the additional capacity available to the Scheduling for the Real-Time Market.
(iii) In the event of Emergency, Incremental Energy purchased above a Generator's Hourly Economic Maximum Level and up to the Generator's Hourly Emergency Maximum Level will be settled at the Real-Time LMPs. Decremental Energy purchased below the Hourly Economic Minimum Level and up to the Hourly Emergency Minimum Level will be settled at the higher of (1) the Bid Price for the Decremental Emergency Energy and (2) Real-Time LMPs.
3.8 Settlement: The Independent Transmission Provider will provide timely settlement of purchases and sales of Energy in the Real-Time Market for Energy pursuant to Sections G.3.7.1 and G.3.7.2.
3.8.1 Settlement when Actual Energy Injections are Less than Scheduled Energy Injections: When the actual Energy injections from a Supplier over a Security Constrained Dispatch Interval are less than its Energy scheduled in the Day-Ahead Market to be injected over that SCE interval, the Supplier shall pay for the difference in a charge equal to the product of: (a) the Real-Time Energy LMP calculated for that Security Constrained Dispatch Interval at the applicable Supplier's bus; and (b) the difference between the
3.8.2 Settlement when Actual Energy Injections are Greater than Scheduled Energy Injections: When the actual Energy injections from a Supplier over a Security Constrained Dispatch Interval are greater than the Energy scheduled in the Day-Ahead Market to be injected over that Security Constrained Dispatch Interval, the Supplier shall be paid for the difference in a payment equal to the product of: (a) the Real-Time Energy LMP calculated for that Security Constrained Dispatch Interval at the applicable Supplier's bus; and (b) the difference between the actual Energy injections and the scheduled Energy injections at that bus.
3.8.3 Settlement when Actual Energy Withdrawals are Less than Scheduled Energy Withdrawals: When a Customer's actual Energy withdrawals over a Security Constrained Dispatch Interval are less than its Energy withdrawals scheduled in the Day-Ahead Market over that Security Constrained Dispatch Interval, the Customer shall be paid the product of: (a) the Real-Time Energy LMP calculated for that Security Constrained Dispatch Interval at the applicable Customer's bus (or at the Customer's zone, if the Customer elects to calculate and settle Energy purchases at Zonal-LMPs and meets the conditions specified in Section F.2.4(c)(ii)); and (b) the difference between the scheduled Energy withdrawals and the actual Energy withdrawals at that bus.
3.8.4 Settlement when Actual Energy Withdrawals are Greater than Scheduled Energy Withdrawals: When a Customer's actual Energy withdrawals over a Security Constrained Dispatch Interval are greater than its Energy withdrawals scheduled in the Day-Ahead Market over that Security Constrained Dispatch Interval, the Customer shall pay for the difference in a charge equal to the product of: (a) The Real-Time Energy LMP calculated for that Security Constrained Dispatch Interval at the applicable Customer's bus (or at the Customer's zone, if the Customer elects to calculate and settle Energy purchases at Zonal-LMPs and meets the conditions specified in Section F.2.4(c)(ii)); and (b) the difference between the actual Energy withdrawals and the scheduled Energy withdrawals at that bus.
4.1 General: As in the Day-Ahead Market, Real-Time Energy LMPs serve dual functions, providing (1) the prices for sales and purchases of Energy and (2) market-based prices for Congestion Management, including Congestion Charges to Bilateral Transactions, and Marginal Losses.
4.2 Transmission Bids: Customers may submit Bilateral Transaction Schedules that indicate whether or not they are willing to pay the Marginal Congestion Charge component of the Transmission Usage Charge. If the Bid indicates that the Customer is not willing to pay Congestion Charges, then the Bilateral Transaction will be scheduled only if there is no Marginal Congestion Charge in the Real-Time Market. If the Bid indicates that the Customer is willing to pay Congestion Charges, then the Bilateral Transaction will be scheduled regardless of the Marginal Congestion Charge in the Real-Time Market.
The Independent Transmission Provider shall charge a Transmission Usage Charge to all Bilateral Transactions whose transmission service was scheduled after the determination of the Day-Ahead schedule, or who schedule additional transmission service after the determination of the Day-Ahead schedule. This charge is the product of (a) the amount of Energy scheduled (as of pre-determined trading deadline) to be withdrawn by that Customer in each hour, minus the amount of Energy scheduled Day-Ahead to be withdrawn by that Customer in that hour, in MWh; and (b) the Real-Time LMP at the Point of Delivery (which could be a Load Zone in which Energy is scheduled to be withdrawn or the external bus where Energy is scheduled to be withdrawn if Energy is scheduled to be withdrawn at a location outside the Independent Transmission Provider Service Area), minus the Real-Time LMP at the Point of Receipt, in $/MWh. The Independent Transmission Provider shall divide each Transmission Usage Charge into separate components for Marginal Costs of Congestion and Marginal Costs of Losses.
4.3.1 Marginal Congestion Component: The Marginal Congestion Component of the Transmission Usage Charge shall be calculated as the Marginal Congestion Component of the Real-Time LMP at the Delivery Point minus the Marginal Congestion Component of the Real-Time LMP at the Receipt Point, as described in Section F.2.5(i).
4.3.2 Marginal Losses Component: The Marginal Losses Component of the Transmission Usage Charge shall be calculated as the Marginal Losses Component of the Real-Time LMP at the Delivery Point minus the Marginal Losses Component of the Real-Time LMP at the Receipt Point, as described in Section F.2.5(ii).
4.4 Calculation of Flowgate LMPs: The Independent Transmission Provider shall calculate and post Ex-Post Flowgate LMPs for the Real-Time Market.
4.5 Marginal Loss Charge Collection: The Real-Time Marginal Loss Charge Collection for any SCD interval is defined here as the sum of the Real-Time Energy Marginal Loss Charge Collection plus the Real-Time Transmission Marginal Loss Charge Collection for that SCD interval. The Real-Time Energy Marginal Loss Charge Collection is defined for any SCD interval of the Real-Time Market as (i) the sum of the net amounts associated with the Marginal Loss Component of the applicable Real-Time Energy LMP charged to: (a) each Supplier whose actual Energy injections over the SCD interval are less than its Energy scheduled in the Day-Ahead Market to be injected over that SCD interval and (b) each Purchaser whose actual Energy withdrawals over the SCD interval exceed its Energy scheduled in the Day-Ahead Market to be withdrawn over that SCD interval; less: (ii) the sum of the net amounts associated with the Marginal Loss Component of the applicable Real-Time Energy LMP paid to (c) each Supplier whose actual Energy injections over the SCD interval exceed its Energy scheduled in the Day-Ahead Market to be injected over that SCD interval and (d) each Purchaser whose actual Energy withdrawals over the SCD interval are less than its Energy scheduled in the Day-Ahead Market to be withdrawn over that SCD interval. The Real-Time Transmission Marginal Loss Charge Collection for any SCD interval is defined for any SCD interval of the Real-Time Market as the net amounts charged to Customers for Transmission Service scheduled in the Real-Time Market for the SCD interval associated with the Marginal Cost Component of the applicable hourly Transmission Usage Charges; less the net amounts associated with the Marginal Cost Component of the applicable hourly Transmission Usage Charges paid to Customers for Transmission Service scheduled in the Day-Ahead Market for reductions in Transmission Service in the Real-Time Market during the SCD interval.
4.5.1 Determination and Disposition of Marginal Loss Revenue Surplus: For each SCD interval of the Real-Time Market, the Independent Transmission Provider shall calculate the Marginal Loss Charge Collection and the Net Energy Revenue Owed to Generators for Losses associated with all Transactions. For each SCD interval of the Real-Time Market where the Marginal Loss Charge Collection exceeds the Net Energy Revenue Owed to Generators for Losses associated with all Transactions, the Independent Transmission Provider shall allocate the revenue surplus to reduction in the charge for Network Access Service. [The Independent Transmission Provider shall determine the exact allocation to each Customer and will file procedures for determining the allocation of the revenue surplus to each Customer.]
4.6 Disposition of Other Real-Time Revenue Surplus or Deficit: The Independent Transmission Provider shall calculate, for each Operating Day, the interval of the Real-Time Market, and the net revenue surplus or deficit from the operation of the Real-Time Market (defined as the difference between the revenues collected from all sources and all payment made to all sources, excluding the surplus for losses calculated pursuant to Section G.4.5). The Independent Transmission Provider shall allocate the revenue surplus or deficit for the Operating Day to the Transmission Owners. [The Independent Transmission Provider shall file procedures for determining the allocation of the surplus or deficit to Transmission Owners.]
5.1 General: The Transmission Provider may require additional Regulation capability in response to system conditions in the Operating Day. The Real-Time Market for Regulation establishes clearing prices and settlement rules for eligible Suppliers of Regulation that have offered Regulation capacity following the close of the Day-Ahead Market. The Transmission Provider shall procure Regulation in this market on behalf of Purchasers who choose not to Self-supply or purchase through bilateral contracts. Both Generation and Load may to provide Regulation in the Real-Time Market if they meet criteria for eligibility.
5.2 Independent Transmission Provider Obligations: The Independent Transmission Provider has the obligation to provide services (i) to (viii) for the Real-Time Market for Regulation. The rules governing these services are contained in this section:
(i) Establish and post on its OASIS criteria and requirements in accord with local reliability authority rules and NERC guidelines such that there is sufficient provision of Regulation in the Real-Time Dispatch.
(ii) Establish and post on its OASIS rules for eligibility to supply Regulation in the Real-Time Market.
(iii) Provide Base Point Signals to Generators providing Regulation to direct the Generator's output.
(iv) Establish and post on its OASIS the Bid data requirements and rules and provide the market functions required for determination of hourly Real-Time Regulation Market Clearing Prices and selection of Real-Time Regulation Market Suppliers. Establish how the pricing rules and selection procedures will be modified in the event of a shortage of Regulation capacity during the Operating Day.
(v) Monitor the Suppliers' performance to ensure that they provide Regulation Service as required.
(vi) Establish and post on its OASIS the rules for determination of any Additional Payments necessary to support efficient operations of the Real-Time Regulation Market and/or the efficient operation of other Real-Time Markets.
(vii) Provide the Settlement functions associated with purchase and sale of Regulation in the Real-Time Market.
(viii) Post the Real-Time Regulation Market Clearing Prices.
5.3 Purchaser Rules and Obligations
(i) Market Participants with a Regulation Requirement may fulfill their requirement by (1) self-scheduling an eligible Generator or Demand-Side Resource, (2) a bilateral contract with an eligible Supplier, or (3) purchasing from the Regulation Market.
(ii) Self-suppliers and purchasers of Regulation through Bilateral Contract must provide data on location and physical capabilities of the Generator or Supplier providing Regulation (see Section 4.2).
(i) Suppliers of Regulation may only use Generators and/or Load that are electrically within the Independent Transmission Provider's Service Area.
(ii) Suppliers of Regulation may only use Generators and/or Load that are able to respond to AGC Base Point Signals sent by the Independent Transmission Provider pursuant to the Independent Transmission Provider Procedures.
(iii) Suppliers of Regulation may only use Generators and/or Load that meet Independent Transmission Provider standards for Generator performance.
(iv) Suppliers of Regulation shall not use, contract to provide, or otherwise commit the capability that is designated to provide Regulation to provide Energy or Spinning Reserve to any party other than the Independent Transmission Provider.
(v) Suppliers of Regulation shall provide the Bid information specified in Section 4.2.
(vi) Suppliers of Real-Time Regulation may not re-submit capacity selected for Energy in the Day-Ahead Market. Suppliers of Real-Time Regulation may lower the Bid Price of capacity selected for Energy in the Day-Ahead Market.
Suppliers of Regulation must provide the following Bid information:
(i) Availability Bid price ($/MWh).
(ii) Regulation Capability (MW) of the Generator supplying Regulation.
(iii) Response Rate (MW/Minute) of the Generator supplying Regulation.
(iv) Upper and Lower Regulation Limits (MW).
(v) Hours of availability to provide Regulation.
(vi) Any additional physical data required by the Independent Transmission Provider.
(i) Bids rejected by the Independent Transmission Provider in the Day-Ahead Market may be modified and resubmitted into the Real-Time Market by the Supplier to the Independent Transmission Provider. [The Independent Transmission Provider Tariff will provide Procedures].
(ii) Bids in the Day-Ahead Market that are not accepted by the Independent Transmission Provider shall be automatically considered for the Real-Time Market, unless withdrawn by the Supplier.
(iii) If a Supplier reduces its available MW subsequent to being scheduled to provide Regulation or Operating Reserves (either Day-Ahead or in a Supplemental Commitment), and if it, as a result, can no longer provide both the amount of Energy it was scheduled to provide Day-Ahead and the amount of Regulation and Operating Reserves it was scheduled to provide, the Independent Transmission Provider will first reduce the amount of Operating Reserves it is scheduled to provide, and then will reduce the amount of Regulation it is scheduled to provide, until the total amount of Energy, Regulation and Operating Reserves it is scheduled to provide is equal to its available MW (or until it is no longer scheduled to provide Regulation or Operating Reserves).
5.5 Calculation of Market Clearing Price: The Independent Transmission Provider shall calculate a Market Clearing Price for the Real-Time Market for Regulation, using the following methodology.
The Independent Transmission Provider shall establish a Supplier Regulation Price for each Supplier based on the sum of the Supplier's Availability Bid and its Real-Time Unit-Specific Opportunity Cost (as defined below). The Real-Time Regulation Market Clearing Price shall be the higher of (i) the highest Supplier Regulation Price needed to meet the Independent Transmission Provider's Regulation Requirement for each Dispatch Interval, or (ii) the highest Market Clearing Price in Dispatch Interval for Spinning Reserves or Supplemental Reserves.
The Unit-Specific Opportunity Costs of a Resource for bidding to sell Regulation shall be equal to the product of:
(i) the deviation of the Regulation set point of the Generator that is required to provide Regulation from the Resource's output level if it had been scheduled or dispatched in economic merit order to provide Energy, times
(ii) the greater of (a) the $/MWh difference between the Real-Time Energy LMP at the generation bus for the Resource and the Real-Time Bid price for Energy from the Resource (at the megawatt level of the Regulation set point for the Resource) in the Real-Time Energy Market or (b) zero.
5.6 Calculation of Additional Payments and Charges
5.6.1 Bid Revenue Sufficiency Guarantee: Resources scheduled for Regulation in the Real-Time Market are eligible for the Bid Revenue Sufficiency Guarantee, pursuant to Section G.2.3.
5.6.2 Failure to Provide Regulation in Real-Time: The Independent Transmission Provider shall, if a Resource providing Regulation Service trips off line, immediately attempt to re-establish a supply for the remainder of that Resource's commitment. Any additional cost incurred by the Independent Transmission Provider as a result of covering the defaulting Resource's remaining commitment shall be reimbursed to the Independent Transmission Provider by the defaulting Supplier. If the Availability payment for the replacement Regulation Service decreases, the Independent Transmission Provider shall not pay the defaulting Supplier the difference in cost.
5.6.3 Other Payments and Charges: [The Independent Transmission Provider may include in this section market rules for any other payments or charges associated with the efficient and reliable operations of the Real-Time Markets for Regulation.]
(i) [The Independent Transmission Provider may include in this section market rules, including specification of quantities and calculation of prices, in the event of a shortfall in the required system requirements for Regulation in the Real-Time Market. The market rules shall be in accord with regional or local reliability authority rules and procedures and NERC guidelines.]
5.8 Settlement: The Independent Transmission Provider will provide timely settlement of purchases and sales of Regulation in the Real-Time Market for Regulation pursuant to Sections 5.8.1and 5.8.2.
(i) The Independent Transmission Provider shall calculate the total obligation for Regulation for each Load-Serving Entity for each hour of the Operating Day. The total hourly obligation for each Load-Serving Entity in an Operating Day shall equal the product of (a) the total Regulation requirement for the Independent Transmission Provider's Service Area for the hour of the Operating Day and (b) the ratio of (1) the Load-Serving Entity's total actual Load in the hour to (2) the total actual Load in the Independent Transmission Provider's Service Area in the hour of the of the Operating Day. The net obligation for Regulation of a Load-Serving Entity in an hour of the Operating Day shall be equal to
(ii) For each hour of the Operating Day, each Load-Serving Entity shall be charged an amount equal to the product of (1) the aggregate net amount paid by the Independent Transmission Provider in the Day-Ahead and Real-Time Markets to procure Regulation for the hour, and (2) the ratio of (a) the Load-Serving Entity's net obligation for Regulation in the hour to (b) the sum of the net obligations for Regulation of all Load-Serving Entities in the Independent Transmission Provider's Service Area in the hour.
(i) The Independent Transmission Provider shall pay Suppliers the Real-Time Regulation Market Clearing Price times the quantity (MW) of Regulation capability.
(ii) The Independent Transmission Provider shall pay Suppliers any Additional Payments necessary to provide Real-Time Regulation in accord with efficient market operations.
(i) The Independent Transmission Provider may establish:
(1) Resource performance measurement criteria;
(2) Procedures to disqualify Suppliers using Resources that consistently fail to meet such criteria; and
(3) Procedures to re-qualify disqualified Suppliers, which may include a requirement to first demonstrate acceptable performance for a time.
(ii) The Independent Transmission Provider shall establish and implement a Performance Tracking System to monitor the performance of Resources that provide Regulation Service.
(iii) Payments by the Independent Transmission Provider to each Supplier of Regulation Service may be based on the Resource's performance with respect to the performance indices. Suppliers that fail to perform at a level consistent with these indices may forfeit all or a substantial portion of their Availability payments, which would otherwise be payable for the subject hour. Suppliers that consistently fail to perform adequately may be disqualified by the Independent Transmission Provider, pursuant to Independent Transmission Provider Procedures. [The Independent Transmission Provider would include such procedures in this section.]
6.1 General: The Transmission Provider may require additional Spinning Reserves capability in response to system conditions in the Operating Day. The Real-Time Market for Spinning Reserve establishes clearing prices and settlement rules for eligible Suppliers of Spinning Reserve that have offered Spinning Reserve capacity to the market. The Transmission Provider shall procure Regulation in this market on behalf of Purchasers who choose not to Self-supply or purchase through Bilateral Contracts. Both Generation and Load may Bid to provide Spinning Reserve in the Real-Time Market if they meet criteria for eligibility.
6.2 Independent Transmission Provider Obligations: The Independent Transmission Provider has the obligation to provide services (i) to (viii) for the Real-Time Market for Spinning Reserve. The rules governing these services are contained in this section:
(i) Establish and post on its OASIS Spinning Reserve criteria and requirements in accord with local reliability authority rules and NERC guidelines.
(ii) Establish and post on its OASIS rules for eligibility to supply Spinning Reserve in the Real-Time Market.
(iii) Establish and post on its OASIS minimum technical requirements and performance standards for a Generator and/or Load to provide Spinning Reserve.
(iv) Establish and post on its OASIS the Bid data requirements and rules and provide the market functions required for determination of hourly Real-Time Spinning Reserve Market Clearing Prices and selection of Real-Time Spinning Reserve Market Suppliers. It shall make this selection with the objective of minimizing the cost of meeting Load and providing all necessary Ancillary Services in that hour. Establish how the pricing rules and selection procedures will be modified in the event of a shortage of Spinning Reserve capacity during the Operating Day.
(v) Establish and post on its OASIS the rules for determination of any Additional Payments necessary to support efficient operations of the Real-Time Spinning Reserve Market and/or the efficient operation of other Real-Time Markets.
(vi) Provide the Settlement functions associated with purchase and sale of Spinning Reserve in the Real-Time Market.
(vii) Post the Real-Time Spinning Reserve Market Clearing Prices.
6.3.1 Market Participants with a Spinning Reserve Requirement may fulfill their requirement by
(i)(1) self-supplying an eligible Generator or Demand-Side Resource; (2) a bilateral contract with an eligible Supplier; or (3) purchasing from the Spinning Reserve Market.
(ii) Self-suppliers and purchasers of Spinning Reserve through Bilateral Contract must provide data on location and physical capabilities of the Generator or Supplier providing Spinning Reserve (see Section 4.2)
6.4 Supplier Rules and Obligations: Suppliers whose Generators or demand side Resources have not been scheduled to provide Spinning Reserve and which still have Capacity that is synchronized with the grid and has not been committed for use in any other way may submit Bids to provide Spinning Reserve to the Independent Transmission Provider.
(i) Suppliers of Spinning Reserve may only use Generators and/or Load that are electrically within the Independent Transmission Provider's Service Area.
(ii) Suppliers of Spinning Reserve may only use Generators and/or Load that meet Independent Transmission Provider standards for Generator performance.
(iii) Suppliers may not contract to provide, or otherwise commit any Capacity from a Generator that has been scheduled to operate or to provide Operating Reserves, in either the Day-Ahead commitment or any supplemental commitment conducted by the Independent Transmission Provider.
(iv) Suppliers of Spinning Reserve shall not use, contract to provide, or otherwise commit the capability that is designated to provide Spinning Reserve to provide Energy, Regulation or Supplemental Reserve to any party other than the Independent Transmission Provider. Suppliers may enter into alternate sales arrangements utilizing any capacity that has not been scheduled to operate or to provide Operating Reserves.
(v) Suppliers of Spinning Reserve shall provide the Bid information specified in Section 4.2.
(vi) Suppliers may not increase the Energy Bids made for the portions of those Generators that have been scheduled Day-Ahead to provide Spinning Reserve.
(vii) Suppliers selected for Spinning Reserve in the Day-Ahead Market may not re-submit that capacity at a higher price into the Real-Time Market for Spinning Reserve. They may lower the Bid Price of the capacity not selected Day-Ahead to ensure selection in the Real-Time Market.
6.4.2 Specification of Bids: Suppliers of Spinning Reserve must provide the following Bid information:
(i) Response Rate (MW/Minute) of the Generator supplying Spinning Reserve.
(ii) Hours of availability to provide Spinning Reserve.
(iii) Any additional physical data required by the Independent Transmission Provider.
6.5.1 Methodology for Calculation of Prices: The Independent Transmission Provider shall calculate a Market Clearing Price for the Real-Time Market for Spinning Reserve, using the following methodology.
The Independent Transmission Provider shall establish a Supplier Spinning Reserve Price for each Supplier based on its Real-Time Unit-Specific Opportunity Cost (as defined below). The Real-Time Spinning Reserve Market Clearing Price shall be the higher of (i) the highest Supplier Spinning Reserve Price for each Dispatch Interval needed to meet the Independent Transmission Provider's Spinning Reserve Requirement, or (ii) the highest Market Clearing Price in the Dispatch Interval for Supplemental Reserves.
The Unit-Specific Opportunity Costs of a Resource Bidding to sell Spinning Reserve shall be equal to the product of:
(i) the deviation of the set point (MWh) of the Generator that is required to provide Spinning Reserve from the Resource's output level if it had been scheduled or dispatched in economic merit order to provide Energy, times
(ii) the greater of (a) the $/MWh difference between the Real-Time Energy LMP at the generation bus for the Resource and the Bid price for Energy from the Resource (at the megawatt level of the Spinning Reserve set
6.5.2 Calculation of Zonal or Locational Prices: Separate Real-Time Spinning Reserve Market Clearing Prices will be calculated for Spinning Reserve located in each distinct Reserve Location for which there is a separate Spinning Reserve requirement. When there are no binding transmission constraints between Reserve Locations, the Real-Time Spinning Reserve Market Clearing Price shall be the same in each of the locations.
6.5.3 Transmission for Operating Reserves. A Supplier located outside of a particular Reserve Location may provide Spinning Reserves if the necessary transmission arrangements to deliver Energy from the Supplier's capacity to the Reserve Location are made. The cost of any transmission service would have to be included in evaluating the total cost of Operating Reserves.
Suppliers scheduled for Spinning Reserve shall not receive Opportunity Cost payments for capacity that was not available to be scheduled to generate Energy.
6.6.1 Bid Revenue Sufficiency Guarantee: Resources scheduled for Spinning Reserve in the Real-Time Market are eligible for the Bid Revenue Sufficiency Guarantee, pursuant to Section G.2.3.
6.6.2 Failure to Perform in Real-Time: When reserve is activated, the Independent Transmission Provider shall measure actual performance against expected performance and may charge financial penalties to Suppliers of Spinning Reserve which fail to perform in accordance with their accepted Bids. [The Independent Transmission Provider may file penalties.]
6.6.3 Other Payments and Charges: [The Independent Transmission Provider may include in this section market rules for any other payments or charges associated with the efficient and reliable operations of the Real-Time Markets for Spinning Reserves.]
6.7 Market Rules for Shortages or Emergencies
(i) [The Independent Transmission Provider may include in this section market rules, including specification of quantities, calculation of market clearing prices, and determination of out of market payments in the event of a shortfall in the required system requirements for Spinning Reserves due to a shortage of available capacity or an Emergency.]
(ii) In the event of a shortfall of total capacity available for Operating Reserves in the Real-Time Market, the Independent Transmission Provider shall first reduce the amount of Supplemental Reserve that is procured, followed by the amount of Supplemental Reserve, followed by the amount of Spinning Reserve.
6.8 Settlement: The Independent Transmission Provider will provide timely settlement of purchases of Spinning Reserves and sales of Spinning Reserve in the Real-Time Market for Spinning Reserve pursuant to Sections 6.8.1 and 6.8.2.
(i) The Independent Transmission Provider shall calculate the total obligation for Spinning Reserve for each Load-Serving Entity for each hour of the Operating Day. The hourly total obligation of each Load-Serving Entity in an Operating Day shall equal the product of (a) the total Spinning Reserve Requirement for the Independent Transmission Provider's Service Area for the hour of the Operating Day and (b) the ratio of (1) the Load-Serving Entity's total actual Load in the hour to (2) the total actual Load in the Independent Transmission Provider's Service Area in the hour of the Operating Day. The net obligation for Spinning Reserve of a Load-Serving Entity in an hour of the Operating Day shall be equal to the greater of the Load-Serving Entity's total obligation minus the amount of Spinning Reserve that is Self-Supplied in the Day-Ahead Market or (b) zero.
(ii) For each hour of the Operating Day, each Load-Serving Entity shall be charged an amount equal to the product of (1) the aggregate net amount paid by the Independent Transmission Provider in the Day-Ahead and Real-Time Markets to procure Spinning Reserve for the hour and (2) the ratio of the Load-Serving Entity's net obligation for Spinning Reserve in the hour to the sum of the net obligations for Spinning Reserve of all Load-Serving Entities in the Independent Transmission Provider's Service Area in the hour.
(i) The Independent Transmission Provider shall pay each Supplier selected to provide more Spinning Reserve in an hour than it was scheduled Day-Ahead the Real-Time Spinning Reserve Market Clearing Price at its location, multiplied by the amount (MW) of Spinning Reserve that Supplier provided that was in excess of the amount scheduled to be provided Day-Ahead, if any.
(i) The Supplier shall pay the Independent Transmission Provider for any Spinning Reserve that it was scheduled Day-Ahead to provide in an hour but did not provide. The payment will be the Real-Time Spinning Reserve Market Clearing Price at its location, multiplied by the amount (MW) of scheduled Spinning Reserve that Supplier did not provide.
(ii) The Supplier shall pay the Independent Transmission Provider any Additional Payments associated with failure to perform according to its Real-Time schedule, pursuant to Section 6.6.
6.9 Failure to Provide Operating Reserves: If a Supplier reduces its available capacity subsequent to being scheduled to provide Regulation Service or Operating Reserves (either Day-Ahead or in a commitment of Replacement Reserves), and if the Independent Transmission Provider must, as a result, reduce the amount of Operating Reserves that Supplier is scheduled to provide in accordance with this Tariff, the Independent Transmission Provider will first reduce the lowest quality Supplemental Reserve that Generator is scheduled to provide.
If it is still necessary to reduce the amount of Operating Reserves that Supplier is scheduled to provide, the Independent Transmission Provider will reduce the amount, in order of quality, of the higher quality Supplemental Reserves that Generator is scheduled to provide.
Finally, if it is still necessary to reduce the amount of Operating Reserves that Supplier is scheduled to provide, the Independent Transmission Provider will reduce the amount of Spinning Reserve that Generator is scheduled to provide.
If a Supplier scheduled Day-Ahead to provide Operating Reserves trips off-line and consequently is unable to provide Spinning Reserve, or if the amount of Operating Reserves a Supplier is scheduled to provide is decreased due to a reduction in that Supplier's capacity, it shall be charged the Real-Time Operating Reserve price at its location in each hour for the relevant category of Operating Reserves applied to the reduction in the amount of Operating Reserves it was scheduled Day-Ahead to provide at that location.
If the Independent Transmission Provider calls for a Supplier of any category of Operating Reserves (other than a Supplier that has previously tripped off-line) to generate Energy with part or all of the capacity that the Independent Transmission Provider has scheduled to provide any category of Operating Reserves, and that Supplier fails to provide the amount of Energy requested by the Independent Transmission Provider within the time applicable for the scheduled Operating Reserves, the Independent Transmission Provider shall:
(i) not pay the non-performing Supplier for any shortfall in the amount of Energy provided;
(ii) charge the Supplier for any shortfall in the amount of Energy provided, at the Real-Time LMP for Energy at that Supplier's location;
(iii) charge the Supplier a regulation penalty; and
(iv) reduce any Availability payments for the scheduled Operating Reserves, and any Opportunity Cost payments, if applicable, that the Supplier would otherwise have received for the 24-hour billing period in which that Supplier failed to perform as scheduled. The Availability payments and the Opportunity Cost payments, if applicable, that the Supplier would have received will be calculated by multiplying the average ratio of the amount of Energy supplied to the amount of Energy scheduled, during any activation of that Supplier during that 24-hour billing period by the applicable Availability payments and Opportunity Cost payments, if applicable, that the Supplier would otherwise have received.
If a Generator providing Operating Reserves has repeatedly failed to provide Energy when called upon by the Independent Transmission Provider, the Independent Transmission Provider may preclude that Generator from providing Operating Reserves in the future. If a specific Generator has been precluded from supplying Operating Reserves, the Independent Transmission Provider shall require that Generator to pass
7.1 General: The Transmission Provider may require additional Supplemental Reserves capability in response to system conditions in the Operating Day. The Real-Time Markets for Supplemental Reserves establish clearing prices and settlement rules for eligible Suppliers of Supplemental Reserve that have offered Supplemental Reserve capacity to the market. The Transmission Provider shall procure Supplemental Reserves for Purchasers that have chosen not to Self-supply or purchase through Bilateral Contracts. Both Generation and Load may Bid to provide Supplemental Reserves in the Real-Time Market if they meet criteria for eligibility.
7.2 Independent Transmission Provider Obligations: The Independent Transmission Provider has the obligation to provide services (i) to (vii) for the Real-Time Markets for Supplemental Reserves. The rules governing these services are contained in this section:
(i) Establish and post on its OASIS Supplemental Reserves criteria and requirements in accord with local reliability authority rules and NERC guidelines.
(ii) Establish and post on its OASIS rules for eligibility to supply Supplemental Reserves in the Real-Time Market.
(iii) Establish and post on its OASIS minimum technical requirements and performance standards for a Generator to provide Supplemental Reserves.
(iv) Establish and post on its OASIS the Bid data requirements and rules and provide the market functions required for determination of hourly Real-Time Supplemental Reserves Market Clearing Prices and selection of Real-Time Supplemental Reserves Market Suppliers. Establish how the pricing rules and selection procedures will be modified in the event of a shortage of Supplemental Reserves capacity during the Operating Day.
(v) Establish and post on its OASIS the rules for determination of any Additional Payments necessary to support efficient operations of the Real-Time Supplemental Reserves and/or the efficient operation of other Real-Time Markets.
(vi) Provide the Settlement functions associated with purchase and sale of Supplemental Reserves in the Real-Time Market.
(vii) Post the Real-Time Supplemental Reserves Market Clearing Prices.
(i) Market Participants with Supplemental Reserves requirements may fulfill their requirement by (1) self-supplying an eligible Generator or Demand-Side Resource, (2) a bilateral contract with an eligible Supplier, or (3) purchasing from the Supplemental Reserves Market.
(2) Self-suppliers and purchasers of Supplemental Reserves through Bilateral Contracts must provide data on location and physical capabilities of the Generator or Supplier providing Supplemental Reserve (see Section 4.2).
(i) During the day, Suppliers that have not been scheduled to provide Supplemental Reserves and which still have capacity that has not been committed for use in any other way may submit Bids to provide Supplemental Reserves to the Independent Transmission Provider.
(ii) The Real-Time Bids may differ from Bids that were made by those Suppliers in the Day-Ahead commitment subject to possible Bid restrictions imposed to mitigate market power.
(iii) Suppliers Bidding to supply Supplemental Reserves that have not already been scheduled to provide Supplemental Reserves may change their Real-Time Bids from one hour to the next subject to possible Bid restrictions imposed to mitigate market power.
(iv) The Independent Transmission Provider shall notify each Supplier of Supplemental Reserves that has been scheduled in the Real-Time dispatch of the amount of Supplemental Reserves it must provide. Any Supplier whose Bid to provide Supplemental Reserves is accepted by the Independent Transmission Provider in the Real-Time dispatch must make its Generators or demand side Resources available for dispatch by the Independent Transmission Provider. Suppliers of Supplemental Reserves shall respond to direction by the Independent Transmission Provider to activate.
(i) Subject to Independent Transmission Provider requirements, Suppliers of Supplemental Reserves may use Generators and/or Load that are electrically within or outside the Independent Transmission Provider's Service Area.
(ii) Suppliers of Supplemental Reserve may only use Generators and/or Load that meet Independent Transmission Provider standards for Generator performance.
(iii) Suppliers of Supplemental Reserves shall not use, contract to provide, or otherwise commit the capability that is designated to provide Supplemental Reserves to provide Energy, Regulation or Spinning Reserve to any party other than the Independent Transmission Provider.
(iv) Suppliers of Supplemental Reserves shall provide the Bid information specified in Section 4.2.
(v) Suppliers may not use, contract to provide or otherwise commit any capacity on any Resource that has been scheduled to provide Supplemental Reserves in the Day-Ahead commitment or in the Real-Time dispatch.
7.4.2 Specification of Bids: Suppliers of Supplemental Reserves must provide the following Bid information:
(i) Response Rate (MW/Minute) of the Generator supplying Supplemental Reserve.
(ii) Hours of availability to provide Supplemental Reserve.
(iii) Any additional physical data required by the Independent Transmission Provider.
7.5.1 Methodology for Calculation of Prices: The Independent Transmission Provider shall calculate a Market Clearing Price for each Real-Time Market for Supplemental Reserves, using the following methodology.
The Independent Transmission Provider shall establish a Supplier Supplemental Reserve Price for each Supplier based on Unit-Specific Opportunity Cost (as defined below). The Real-Time Supplemental Reserve Market Clearing Price shall be the higher of (i) the highest Supplier Supplemental Reserve Price needed to meet the Independent Transmission Provider's Supplemental Reserve Requirement for each Dispatch Interval, or (ii) the Market Clearing Price in any Dispatch Interval for any lower quality Supplemental Reserve.
The Unit-Specific Opportunity Costs of a Resource Bidding to sell Supplemental Reserve in each Dispatch Interval shall be equal to the product of:
(i) the deviation of the set point (MWh) of the Generator that is required in order to provide Supplemental Reserve from the Resource's output level if it had been scheduled or dispatched in economic merit order to provide Energy, times
(ii) the absolute value of the difference between the Real-Time Energy LMP at the generation bus for the Resource and the Bid price for Energy from the Resource (at the megawatt level of the Supplemental Reserve set point for the Resource) in the Real-Time Energy Market.
7.5.2 Calculation of Zonal or Locational Prices. Separate Real-Time Supplemental Reserve Market Clearing Prices will be calculated for Supplemental Reserve located in each distinct Reserve Location for which there is a separate Supplemental Reserve requirement. When there are no binding transmission constraints between Reserve Locations, the Real-Time Ancillary Price for Supplemental Reserve shall be the same in each of the locations.
7.5.3 Transmission for Operating Reserves. A Supplier located outside of a particular Reserve Location may provide Supplemental Reserve if the necessary transmission arrangements to deliver Energy from the Supplier's capacity to the Reserve Location are made. The cost of any transmission service would have to be included in evaluating the total cost of Operating Reserves.
7.6.1 Bid Revenue Sufficiency Guarantee: Resources scheduled for Supplemental Reserves in the Real-Time Market are eligible for the Bid Revenue Sufficiency Guarantee, pursuant to Section G.2.3.
7.6.2 Failure to Perform in Real-Time: When reserve is activated, the Independent Transmission Provider shall measure actual performance against expected performance and shall charge financial penalties as detailed in Section 6.9, to Suppliers of Reserves which fail to perform in accordance with their accepted Bids. [The Independent Transmission Provider may file penalties.]
7.6.3 Exceptions: Notwithstanding anything to the contrary in this Rate Schedule, no payments shall be made to any Supplier providing Operating Reserves for reserves provided by that Supplier in excess
The market clearing price paid to Suppliers of any category of Operating Reserve shall not be determined by any Bid to supply Operating Reserve that has not been accepted by the Independent Transmission Provider.
7.6.5 Other Payments and Charges: [The Independent Transmission Provider may include in this section market rules for any other payments or charges associated with the efficient and reliable operations of the Real-Time Markets for Supplemental Reserves.]
(i) [The Independent Transmission Provider may include in this section market rules, including specification of quantities, calculation of market clearing prices, and determination of out of market payments in the event of a shortfall in the required system requirements for Supplemental Reserves due to a shortage of available capacity or an Emergency.]
(ii) In the event of a shortfall of total capacity available for Supplemental Reserves in the Real-Time Market, the Independent Transmission Provider shall first reduce the amount of any lower quality Supplemental Reserve that is procured, in order of quality, followed by the amount of higher quality Supplemental Reserves.
7.8 Settlement: The Independent Transmission Provider will provide timely settlement of purchases of Supplemental Reserves and sales of Supplemental Reserves in the Real-Time Market pursuant to Sections 7.8.1 and 7.8.2.
(i) The Independent Transmission Provider shall calculate the total obligation for Supplemental Reserve for each Load-Serving Entity for each hour of the Operating Day. The hourly total obligation of each Load-Serving Entity in an Operating Day shall equal the product of (a) the total Supplemental Reserve Requirement for the Independent Transmission Provider's Service Area for the hour of the Operating Day and (b) the ratio of (1) the Load-Serving Entity's total actual Load in the hour to (2) the total actual Load in the Independent Transmission Provider's Service Area in the hour of the Operating Day. The net obligation for Supplemental Reserve of a Load-Serving Entity in an hour of the Operating Day shall be equal to the greater of the Load-Serving Entity's total obligation minus the amount of Supplemental Reserve that is Self-Supplied in the Real-Time Market or (b) zero.
(ii) For each hour of the Operating Day, each Load-Serving Entity shall be charged an amount equal to the product of (1) the aggregate net amount paid by the Independent Transmission Provider in the Real-Time Markets to procure Supplemental Reserve for the hour and (2) the ratio of the Load-Serving Entity's net obligation for Spinning Reserve in the hour to the sum of the net obligations for Supplemental Reserve of all Load-Serving Entities in the Independent Transmission Provider's Service Area in the hour.
(i) The Independent Transmission Provider shall pay each Supplier selected to provide more Supplemental Reserve in an hour than it was scheduled Day-Ahead the Real-Time Supplemental Reserve Market Clearing Price at its location, multiplied by the amount (MW) of Supplemental Reserve that Supplier provided that was in excess of the amount scheduled to be provided Day-Ahead, if any.
(i) The Supplier shall pay the Independent Transmission Provider for any Supplemental Reserves that it was scheduled Day-Ahead to provide in an hour but did not provide. The payment will be the Real-Time Supplemental Reserve Market Clearing Price at its location, multiplied by the amount (MW) of Day-Ahead scheduled Supplemental Reserve that the Supplier did not provide.
(ii) The Supplier shall pay the Independent Transmission Provider any Additional Payments associated with failure to perform according to its Real-Time schedule, pursuant to Section 7.6.3.
8.1.1 Payments to Suppliers. The Independent Transmission Provider shall determine, on a daily basis, if any Resource that it has committed to provide Replacement Reserves for the operating day pursuant to Section F.1.8 has not recovered its Start-up, No-load, and Energy Bid Prices through revenues in the Real-Time Energy and Ancillary Services Markets. If the Start-up, No-load, and Energy Bids over the twenty-four (24) hour Operating Day of any such Resource exceed its combined Revenue from the Real-Time Markets for Energy and Ancillary Services, then that Resource's revenue shall be augmented by an additional payment, called the Real-Time Bid Revenue Sufficiency Guarantee payment, in the amount of the revenue shortfall.
8.1.2 Charges to Customers. A purchase of Real-Time Energy is deemed to be made by any Customer whose actual Energy injections in any hour of the Operating Day is less than its injections scheduled for that hour in the Day-Ahead Market, and by any Customer whose actual Energy withdrawals in any hour in the Operating Day exceed its withdrawals scheduled for that hour in the Day-Ahead Market. All uninstructed purchases of Real-Time Energy,
(i) If the sum of all uninstructed purchases of Real-Time Energy greater than or equal to the aggregate MWhs of Replacement Reserves committed over the Operating Day, then the Replacement Reserve charge for each Customer i shall be calculated as:
(ii) If the sum of all uninstructed purchases of Real-Time Energy is less than the aggregate MWhs of Replacement Reserves committed over the Operating Day, then the Replacement Reserve charge for each Customer i shall be calculated as:
8.1.3 Unrecovered Bid Revenue Sufficiency Guarantee Payments. Any amounts of Bid Revenue Sufficiency Guarantee payments for an Operating Day made pursuant to Section G.8.1.1 that are not recovered through Replacement Reserve charges for the Operating Day pursuant to Section G.8.1.2 shall be recovered in a separate charge to all Load-Serving Entities in the Independent Transmission Provider's Service Area. The charge for each Load-Serving Entity for the Operating Day shall equal to the product of (a) the total amounts of Bid Revenue Sufficiency Guarantee payments for an Operating Day made pursuant to Section G..8.1.1 that are not recovered through Replacement Reserve charges for the Operating Day pursuant to G.8.1.2 and (b) the ratio of (1) the Load-Serving Entity's total actual Load over the Operating Day to (2) the total actual Load within the Independent Transmission Provider's Service Area over the Operating Day.
8.2.1 Payments to Suppliers. The Independent Transmission Provider shall pay each Resource scheduled, committed, or dispatched by the Independent Transmission Provider after the close of the Day-Ahead Market (other than a Resource committed to supply Replacement Reserves) the real-time Bid Revenue Sufficiency Guarantee payment for the Operating Day, calculated pursuant to Section G.2.3(ii).
8.2.2 Charges to Customers. A purchase of Real-Time Energy is deemed to be made by any Customer whose actual Energy injections in any hour of the Operating Day
where:
Each Independent Transmission Provider must file a market monitoring plan in accordance with the Commission's regulations as part of this Tariff.
1.1 Participating Generator Agreements: The participating generator agreement between the Independent Transmission Provider and a generator will include a provision to require that all available capacity of the generator must be scheduled or offered to the Day-Ahead and Real-Time markets at bids that do not exceed specified Bid caps under non-competitive conditions to be specified in the agreement.
1.2.1 The Safety-Net Bid Cap: The MMU will establish a safety-net Bid cap that will apply to all markets at all times.
1.2.2 Generator-specific Bid Caps: The MMU will establish for each Generator identified in Section H.1.4.1 below Bid caps that may apply to each Bid-in parameter when mitigation is warranted. These shall include: Bid caps for Energy, regulation service, operating reserves, start-up costs, no-Load costs, incremental and decremental Energy costs, and any other parameter allowed to vary in Day-Ahead and Real-Time markets.
1.3 Determination of Available Capacity: Available capacity is all capacity not scheduled or on an outage.
1.3.1 Adjustments to Available Capacity to Reflect Risk of Forced Outages in Real-Time Market: Independent Transmission Provider may file provisions.
1.3.2 Available Capacity Reduced by Forced Outages Subject to Audit: Units declaring a forced outage would be subject to audit by the MMU. If the outage was not proved to be justified, then the Generator shall be subject to a penalty. [The Independent Transmission Provider shall specify the type of penalty.]
1.4.1 Local Non-competitive Conditions: The MMU shall identify specific Generators that are frequently needed to support the operation of the grid and sellers that own facilities in identified Load pockets with fewer than __independent suppliers. Participating Generator Agreements for these entities will require that they be subject to Local Market Power Mitigation.
1.4.2 Other Non-competitive Conditions: The MMU shall identify other non-competitive conditions as necessary.
1.5.1 Market Power Mitigation Independent of Market Conditions: The Independent Transmission Provider may not accept any Bid into the Day-Ahead or Real-Time markets that exceeds the higher of: (a) the safety-net Bid cap specified in Section H.1.2.1; or (b) the bid cap specified in a Participating Generator Agreement.
1.5.2 Market Power Mitigation Triggered by Section H.1.4.1: When mitigation is triggered by Section H.1.4.1, the units will be required to offer all available capacity to the Day-Ahead and Real-Time markets at bids that do not exceed applicable bid caps determined in H.1.2.2.
1.5.3 Market Power Mitigation Triggered by Section H.1.4.2: To be specified.
The transmission and power markets administered by the Independent Transmission Provider will be monitored on an on-going basis by the Market Monitoring Unit (MMU). The MMU reports directly to the Commission and the governing board of the transmission provider.
2.1 Data Requirements and Data Collection: The MMU shall collect and evaluate data provided by the Independent Transmission Provider and Market Participants in order to identify inefficiencies in the markets or the market design, and individual Market Participant behavior that may be a prohibited exercise of market power or a violation of this Tariff or other market rules.
2.1.1 Obligations of Market Participants: As a condition of participating in the markets operated by the Independent Transmission Provider, all Market Participants shall be required to comply with information requests from the MMU. Any disputes concerning whether the information is necessary or how the information is to be provided or how any confidential information could be used should first be attempted to be resolved either through dispute resolution or the Commission's Office of Market Oversight and Investigations (Hotline). If the parties are then unable to resolve the dispute, a complaint under Section 206 of the Federal Power Act may be filed.
2.1.2 Generator-Specific data: The MMU shall have the responsibility to collect all Generator-specific data needed to evaluate whether a seller is exercising market power and to establish Bid restrictions that may be imposed when markets are not sufficiently competitive. The data shall include, at a minimum: start-up, no Load, and shut-down costs, environmental restrictions, fuel costs, maintenance costs, heat rates, ramp rates, high and low operating levels, and minimum run times.
2.1.3 Data Acquired in the Course of Conducting Market Operations: The MMU shall have immediate access to all Bid data submitted to the Independent Transmission Provider.
2.1.4 Other Publically Available Data: The Market Monitor shall collect all data needed to assess the overall competitiveness of its markets. The data would include, but not be limited to, information on market shares of Generation Capacity by type and location, information on planned and unplanned Generator and transmission outages, and plans for transmission expansions and upgrades, and Generator interconnection requests.
2.1.5 Confidentiality: All information obtained by the MMU, that is specific to a Market Participant, shall be treated confidentially.
2.2 Framework for Analyzing Market Structure and Generator Conduct
2.2.1 Obligations of the Market Monitor: The MMU shall conduct a structural analysis of the markets in the region to include in a state of the market report to the Commission, the committee of state representatives, and the transmission provider's Board of Directors. In addition, the MMU must evaluate the conduct of Market Participants. Any flaws in the market rules that are identified by the Market Monitor, and any Market Participant conduct that indicates exercises of market power, shall be remedied prospectively, unless the conduct violates existing rules, in which case the consequences shall be predetermined and specified in this Tariff.
2.2.1 Structural Analysis: The MMU shall develop an analysis of the overall competitiveness of the markets operated by the Transmission Provider. The analysis will be performed at least annually and will report on the following at a minimum: market concentration by Generator type and region, transmission constraints and Load pockets that may give rise to market power concerns, conditions for entry or new supply, the development of demand response, and development of a competitive benchmark.
2.2.2 Conduct Analysis: The MMU will monitor the conduct of individual Market Participants. The Market Monitor shall review planned transmission and generation outages to ensure that scheduling outages are not used to enhance or create opportunities to exercise Generator market power. Analysis of Market Participant conduct may include a review of Bidding behavior to identify any auction design flaws that may give Market Participants an unanticipated incentive and ability to manipulate market-clearing prices or up-lift payments. Finally, the Market Monitor shall evaluate the effectiveness of the Participating Generator Agreements in mitigating market power where market structure is not sufficiently competitive.
2.3 Annual Reports: No later than May 31 of each year, the Market Monitor shall file a State of the Markets Report with the Commission which includes the results of the Market Monitor's structural and conduct analyses. This report shall address such
2.4 Periodic Reports: The Market Monitor shall submit a report to the Commission if it detects behavior that cannot be cured within the Market Monitor's authority or if it detects behavior that would require a change in market rules. These reports should be made as soon as practicable after the behavior is detected.
3.1 Physical Withholding: Entities may not physically withhold the output of an Electric Facility (Generating unit or Transmission Facility) by (a) falsely declaring that an Electric Facility has been forced out of service or otherwise become unavailable, or (b) failing to comply Section H.1.5.2.
3.2 Economic Withholding: Entities may not economically withhold by submitting high bids that are not consistent with the caps specified in Section H.1.2.
3.3 Availability Reporting: Entities must comply with all reporting requirements governing the availability and maintenance of a Generating Unit or Transmission Facility, including proper Outage scheduling requirements. Entities must immediately notify the Transmission Provider when capacity changes or resource limitations occur that affect the availability of the unit or facility or the ability to comply with dispatch instructions.
3.4 Factual Accuracy: All applications, schedules, reports, or other communications to the Transmission Provider or the Market Monitor must be submitted by a responsible company official who is knowledgeable of the facts submitted. All information submitted must be true to the best knowledge of the person submitting the information.
3.5 Information Obligation: Entities must comply with requests for information or data by the Market Monitor or the Transmission Provider that are consistent with the Tariff.
3.6 Cooperation: Entities must assist and cooperate in investigations or audits conducted by the Market Monitor.
3.7 Physical Feasibility: All Bids or schedules that designate Resources must be physically feasible within the limits of the Resource,
3.8 Enforcement: The Market Monitor is responsible for the enforcement of the rules in this section. Violations of these rules will be subject to the following penalties: [to be added]
This section sets forth terms and conditions requiring each Load-Serving Entity to meet its share of the region's Resource Adequacy Requirement. The Resource Adequacy Requirement will ensure that in the future each Load-Serving Entity will have secured generation, transmission, and demand response resources sufficient to meet real-time load and a reasonable operating reserve margin necessary to maintain the stable and reliable operation of the transmission system.
[Additional details will be completed and filed by each Independent Transmission Provider as part of its compliance filing.]
(i) [There may be regional variation in forecast methodology. Some regions may wish to do a bottom up forecast. The following wording will then be needed.] [Annually, on or before _____ (each Independent Transmission Provider shall insert the relevant date here), each Load Serving Entity shall submit its demand forecast for the Planning Horizon.]
(ii) Annually, on or before _____ [each Independent Transmission Provider shall insert the relevant date here], the Independent Transmission Provider shall assign a share of the region's Resource Adequacy Requirement to each Load Serving Entity within the region based on the ratio of the load.
(i) Annually, on or before _____ [each Independent Transmission Provider shall insert the relevant date here], each Load Serving Entity shall submit a proposed plan to meet its assigned Resource Adequacy Requirement to the Independent Transmission Provider.
(ii) Plans for meeting the assigned Resource Adequacy Requirement may rely upon generation, transmission, and/or demand response, subject to the standards set forth in this section of the Tariff, and Independent Transmission Provider's review of operational feasibility.
(iii) The Independent Transmission Provider shall audit each plan for compliance with the standards set forth in Section I.4 and for operational feasibility. [Each Independent Transmission Provider shall establish a review and resubmission process, with reasonable time frames, to achieve compliant and operationally feasible plans within a specified end date.]
(ii) Each Load-Serving Entity must satisfy the Independent Transmission Provider that the resources to be relied upon for future Resource Adequacy Requirements are in compliance with the standards of this section of the Tariff and are operationally feasible, dedicated to serving the Load-Serving Entity without prior or conflicting claim, and can be delivered to the load to be served as and if needed to meet future requirements.
(ii) [Each Independent Transmission Provider shall list in its open access electricity transmission Tariff specific requirements it intends to impose on each Load-Serving Entity such that the Load Serving Entity's resources qualify to meet its share of the Resource Adequacy Requirement.]
[Each Independent Transmission Provider shall list in its open access electricity transmission Tariff specific penalties it intends to impose.]
(i) Each Load-Serving Entity that has not met its allocated share of the Resource Adequacy Requirement, shall be subject to penalty rates for spot market energy purchases during the last year of the Planning Horizon to the extent of the resource shortage whenever the Independent Transmission Provider's market has available less than a minimally acceptable level of operating reserves.
(ii) Penalties will increase on a graduated basis as the Independent Transmission Provider's operating reserves level falls below minimally acceptable levels. (For example, for deficiencies up to 1 percent, the penalty would be $500/MWh, plus the prevailing market price for energy. As the operating reserve level falls, the premium of the penalty over the prevailing market price for energy would increase: over 1 percent up to 2 percent, the penalty would be $600/MWh; over 2 percent up to 3 percent, the penalty would be $700/MWh; and so forth.)
(i) A Load-Serving Entity that fails to implement curtailment (load shedding) when ordered by the Independent Transmission Provider shall be assessed a penalty of $1,000 per MWh, in addition to the LMP, for all unauthorized energy taken following an instruction to implement curtailment (load shedding).
Each Independent Transmission Provider must file its transmission planning and expansion plan as part of this Tariff.
1.0 This Service Agreement, dated as of______, is entered into, by and between______ (the Independent Transmission Provider), and ______ (“Customer”).
2.0 The Customer has been determined by the Independent Transmission Provider to have a Completed Application for Network Access Service under the Tariff.
3.0 The Customer has provided to the Independent Transmission Provider an Application deposit, if applicable, in accordance with the provisions of Section B.2.2 of the Tariff.
4.0 Service under this agreement shall commence on the later of (1) the requested service commencement date, or (2) the date on which construction of any Direct Assignment Facilities and/or Network Upgrades are completed, or (3) such other
5.0 The Independent Transmission Provider agrees to provide and the Customer agrees to take and pay for Network Access Service in accordance with the provisions of Part II of the Tariff and this Service Agreement.
6.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below.
7.0 The Tariff is incorporated herein and made a part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials.
1. This Service Agreement dated as of ________ is entered into by and between ________ (Independent Transmission Provider) and ________ (Customer).
2. The Customer represents and warrants that it has met all applicable requirements set forth in the Independent Transmission Provider's Tariff and has complied with all applicable Procedures under the Tariff.
3. The Independent Transmission Provider agrees to provide and the Customer agrees to pay for Market Services in accordance with the provisions of the Independent Transmission Provider's Tariff and to satisfy all obligations under the terms and conditions of the Independent Transmission's Provider's Tariff, as may be amended from time-to-time, filed with the Federal Energy Regulatory Commission (Commission). The Independent Transmission Provider and the Customer all agree that this Service Agreement shall be subject to, and shall incorporate by reference, all of the terms and conditions of the Independent Transmission Provider's Tariff and Procedures.
4. It is understood that, in accordance with the Independent Transmission Provider's Tariff, the Independent Transmission Provider may amend the terms and conditions of this Service Agreement by notifying the Customer in writing and make the appropriate filing with the Commission.
5. The Customer represents and warrants that:
(a) The Customer is an entity duly organized, validly existing and/or otherwise qualified to do business under the laws of the State of ______ and is in good standing under its [insert organizational document] and the laws of the State of [insert state of organization];
(b) This Service Agreement, or any Transaction entered into pursuant to the Service Agreement, as applicable, has been duly authorized;
(c) The execution, delivery and performance of this Service Agreement will not materially conflict with, constitute a material breach of, or a material default under, any of the terms, conditions, or provisions of any law or order of any agency of government, the [insert organizational document] of the Customer, any contractual limitation, organizational limitation or outstanding trust indenture, deed of trust, mortgage, loan agreement, other evidence of indebtedness, or any other agreement or instrument to which Customer is a party or by which it or any of its property is bound, or in a material breach of, or a material default under, any of the foregoing; and
(d) This Service Agreement is the legal, valid, and binding obligation of the Customer enforceable in accordance with its terms, except as it may be rendered unenforceable by reason of bankruptcy or other similar laws affecting creditors' rights, or general principles of equity.
The Customer warrants and covenants that, during the term of the Service Agreement, the Customer shall be in compliance with all federal, state, and local laws, rules, and regulations related to the Customer's performance under the agreement.
4. Service under this Service Agreement shall commence on the later of: _______, or such other date as it is permitted to become effective by the Commission. Service under this Service Agreement shall terminate on ______.
5. The Independent Transmission Provider agrees to provide and the Customer agrees to take and pay for, or to supply to the Independent Transmission Provider, Energy, capacity, and Ancillary Services in accordance with the provisions of the Independent Transmission Provider's Tariff and this Service Agreement.
6. Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below:
7. Cancellation Rights:
If the Commission or any regulatory agency having authority over this Service Agreement determines that any part of this Service Agreement must be changed, the Independent Transmission Provider shall offer to the Customer an amended Service Agreement reflecting such changes. In the event that the Customer does not execute such an amendment within thirty (30) days, or longer if the Parties mutually agree to an extension, after the Commission's action, this Service Agreement and the amended Service Agreement shall be void.
8. Early Termination by the Customer:
The Customer may terminate service under this Service Agreement no earlier than ninety (90) days after providing the Independent Transmission Provider with written notice of the Customer's intention to terminate; except that a Load-Serving Entity must continue to take service under the Independent Transmission Provider's Tariff as long as it continues to serve Load within the Independent Transmission Provider's Service Area. In the event that tax-exempt financing of a Customer is jeopardized by its participation under this Service Agreement, the Customer is jeopardized by its participation under this Service Agreement, the Customer may terminate this Service Agreement upon thirty (30) days written notice to the Independent Transmission Provider. The Customer's provision of notice to terminate service under this Service Agreement shall not relieve the Customer of its obligation to pay any rates, charges, or
9. The Customer hereby appoints the Independent Transmission Provider as its agent for the limited purpose of effectively transacting on the Customer's behalf in accordance with the Customer's written instructions, listed herein and the terms of the Independent Transmission Provider's Tariff and Procedures. The Customer agrees to pay all amounts due and chargeable to the Customer in accordance with the terms of the Independent Transmission Provider's Tariff and Procedures.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials.
[To be provided by Independent Transmission Provider.]
To be filed by the Independent Transmission Provider based on the following guidelines:
Available Transfer Capability must be calculated on a regional basis by an independent entity. In an RTO or ISO, the Independent Transmission Provider may calculate Available Transfer Capability. Vertically integrated utilities not a part of an RTO or ISO must contract with an independent entity to calculate Available Transfer Capability on its system. The calculation of Available Transfer Capability must take into account the effect of other transmission systems in the interconnection (
To be filed by the Independent Transmission Provider.
To be filed by the Independent Transmission Provider.
To be filed by the Independent Transmission Provider.
We set forth below specific examples of undue discrimination and impediments to competition that continue to exist in the electric industry. Some of the examples that we provide do not use specific names because they are for the most part based on complaints made through the Commission's Enforcement Hotline, which are handled on a confidential basis. Other examples, which illustrate the potential for discrimination, establish that transmission providers have both the incentive and ability to exercise transmission market power against competitors in the market to supply energy.
The following is an example derived from informal, non-public inquiries to the Commission
In February, a competing generator recognizes an opportunity to sell power into a vertically integrated transmission provider's system during the summer months (June, July, and August) and, therefore, requests monthly firm service for the desired points for that time period. The transmission provider, which would prefer that its merchant function capture the sales anticipated by the competitor, now must evaluate whether sufficient Available Transfer Capability will be available to honor its competitor's request. Although the formula for calculating Available Transfer Capability is required to be public, the transmission provider has the sole responsibility for, and a great deal of discretion in, its calculation, and will be very conservative in its estimates of expected contingencies, outages and the like. In this example, the transmission provider assumes two generating units will be unavailable, reducing Available Transfer Capability below the level where the requested transmission can occur, so it denies the request for summer service. But after the competitor's request is denied, the transmission provider's affiliate can ask in May for weekly firm service over the summer. So, when the affiliate's request is made, it is granted. Discretion on the part of the transmission provider in calculating Available Transfer Capability coupled with the affiliate's knowledge of how the calculations work enable the affiliate to secure the necessary firm service and win the sale opportunity.
The following is another example derived from informal, non-public inquiry by the Commission regarding how TLRs are used.
The facts: There are three neighboring, interconnected transmission systems, WestCo, CentralCo, and EastCo. (Their relative locations match their names).
CentralCo has 10,000 MW of generation and 8,000 MW of load west of a constrained line that divides its system. The line is limited to 1,500 MW of transfer capability. CentralCo has 1,000 MW of generation and 2,000 MW of load east of the constraint. Its cost of generation on either side of the constraint is comparable, and averages about $25 per MWh.
Under its normal dispatch pattern, CentralCo would generate 1,000 MW from its generation in the east to serve the eastern load, and would generate 9,000 MW from its western generation, 8,000 MW to meet its western load and 1,000 to meet the remainder of the 2,000 MW load in the east. This means that 1,000 MW of generation would usually flow across the constrained line for CentralCo to meet its own load, leaving 500 MW of west-to-east ATC on the constrained line.
NewGen, a generator located in WestCo's service area, wants to sell 100 MW for one day to a buyer in EastCo's service area. NewGen's cost of generation is $22 per MWh.
To make the sale, NewGen must secure 100 MW of transmission across CentralCo's system (including the constrained line), to make the sale. Therefore, NewGen requests transmission service through CentralCo's system. Under normal operating conditions, CentralCo's constrained line has available 500 MW of Available Transfer Capability, leaving plenty of transfer capability to accommodate the sale. Since its OASIS lists 500 MW of Available Transfer Capability, CentralCo grants the request.
If CentralCo were an RTO, it would have no financial interest in which generator makes any particular sale, and would focus on ensuring optimal and reliable system operation. Thus, it would dispatch the system to ensure that the 100 MW NewGen transaction would flow, since it could do so while still optimizing the dispatch of the CentralCo generators. But CentralCo has a financial incentive to block the NewGen transaction in order to make the sale itself and it has the information to make it happen. CentralCo, as transmission provider, knows the flow patterns on its system and the identity (and affiliation) of all generators flowing power on its system. This means that CentralCo's transmission arm would not need to engage in any prohibited off-OASIS
CentralCo can block a portion of the competitor's transaction by changing its own dispatch pattern and declaring a TLR across the constrained line. CentralCo would reduce generation on the east side to 500 MW and increase generation from the west by the same amount to meet the eastern load. This would increase its own use of the constrained line to 1,500 MW which, in addition to the 100 MW of scheduled use by NewCo, would exceed the thermal limits of the line. CentralCo, as security coordinator for its own system, has great discretion as to when and for how long to declare a TLR across the constrained line. In this situation, rather than redispatching its own generators to accommodate NewGen's transaction, it could declare a TLR and curtail a portion of the NewGen's transmission transaction.
By curtailing transmission for a portion of the competitor's sale, this TLR allows CentralCo to step in to provide EastCo's needed 100 MW (following NewCo's transmission curtailment), possibly at an inflated price due to the TLR and the buyer's need to immediately secure replacement power.
The Commission is concerned that the use of emergency procedures offers opportunities for discrimination. A high incidence of TLRs reduces certainty in the market because it frustrates the expectations of bulk power sellers and their customers.
A market participant that operates a control area may derive a market benefit. The primary function of a control area operator is to maintain a balance between the energy coming onto the grid and the energy being taken off. The North American Electric Reliability Council (NERC) refers to this primary function as balancing and the responsible entity as the balancing authority.
A transmission customer outside the organized spot market of an ISO or RTO is expected to keep its own grid energy inputs and withdrawals in balance. For example, the customer may be a municipal utility that buys 50 megawatts from noon to 1 o'clock to meet a load that is expected to hover around 50 megawatts at that hour. The transmission customer cannot achieve exact balance in part because retail loads are not completely predictable.
A balancing authority outside an RTO or ISO is today typically also a market participant that serves its own power customers. In most cases, it is a large vertically integrated public utility that generates and buys power to meet the power needs of its native load. Such a balancing authority may be able to lower the cost of acquiring balancing energy and achieve a competitive advantage over other market participants that do business on its transmission system. It can rely on a neighboring balancing authority to loan it energy without having to pay for the energy. Further, it may avoid a penalty for excessive deviation. It can later return the energy taken in kind to the neighboring authority and may thus face a lower balancing cost than other energy providers. Although this problem may incur infrequently, it results in an undue cost preference for the investor-owned utility and its customers vis-a-vis the costs that other energy providers incur and pass on to their customers.
NERC has recognized a related reliability problem associated with excessive unplanned borrowing of energy in a highly competitive market and is in the process of writing new rules to alleviate this problem.
The Commission, in the proposed rule leading to Order No. 2000, using the then-current terminology of the control area operator, said that, in an RTO,
The Commission has not addressed this issue generically, however, for public utility transmission providers that are not in an RTO. There is a need for a tariff that addresses this issue explicitly for all public utility transmission providers.
The Order No. 888
To illustrate, a point-to-point transmission customer, such as a power marketer, may be required to reserve transmission for a complete transaction, that is, from an actual generator to an actual power-consuming load. If it is announced today, for example, that generation will be available tomorrow from a particular generator, the marketer may be able to buy the power but unable to reserve the transmission if it has not yet identified a buyer and named its location on the grid. That is, it can name a point of receipt but cannot yet name a point of delivery, so it may be denied a reservation for firm transmission service.
A vertically integrated transmission provider with a native load, however, can buy the power from the same generator, naming that generator as the point of receipt and its native load network as the point of delivery, saying it intends to reduce its own generation to meet its native load power needs. The transmitting public utility is given a transmission reservation. Later, the public utility can find a buyer for the power and say it is making a sale from its freed-up generation, designated as the point of receipt, to the buyer's point of delivery—taking a second transmission reservation for the same power. In effect, the public utility will have reserved transmission for a purchase from the generator and a sale to the buyer in a manner that is not available to the marketer. The public utility is said to have “parked” the power at its native load location while it sought a buyer for the power. Parking can also occur if the buyer is known and transmission to the buyer is reserved, allowing the public utility time to search for a seller to match the buyer's power needs. The time delay involved in parking affords flexibility to a vertically integrated transmission provider that is not available to all transmission customers.
“Hubbing” is similar but does not necessarily involve a time delay. Instead, it involves having more than one seller or more than one buyer, or both. Using the method just described for parking, a transmitting public utility with a native load may reserve transmission to buy power from several sellers and to sell power to several buyers. In effect, it may use its combined native load transmission network location as a hub for trading. It may acquire a portfolio of generators from which to obtain power to meet the power needs of a collection of power buyers, without having to match individual buyers and sellers. This hubbing allows the public utility to capture market efficiencies by combining resources to satisfy collective needs, and to gain a competitive advantage over others who cannot establish a hub because they are required by Point-to-Point Transmission Service rules to match a particular generator with a particular load for each transmission reservation.
This example shows another undesirable difference between two transmission services available to both wholesale and unbundled retail customers, Network Integration Transmission Service and Point-to-Point Transmission Service.
Today, the Commission concludes that the inherent differences in flexibility between the two types of tariff services, including the one described above, are resulting in undue preferences and thereby impeding the most efficient trading of power over the interstate transmission grid. Accordingly, the Commission proposes to create a single transmission service and equalize the playing field so that all transmission customers can park, hub or exercise equal creativity and flexibility in structuring transactions and serving customers.
Transmission transfer capability may be set aside by the transmission provider for either of two reliability-related reasons. One relates to the reliability of the transmission system itself and the other relates to generation reliability. As an example of the first, the power loading on a transmission line may be less than the line's capacity so that it can take up the power flows it must absorb if a parallel line should go out of service. The industry refers to this type of unused transmission capacity as a transmission reliability margin, or TRM. While reliability rules forbid a transmission provider from loading a line beyond its reliability limit, these rules are not necessarily mandatory or enforceable. However, there have been few complaints about discriminatory violations of TRM reliability limits.
Most complaints have related to transmission transfer capability that is set aside to provide for adequate generation. A vertically integrated public utility may have decided in the past that, to achieve adequate generation resources (including reserves), it was more economical to build stronger transmission interconnections with neighbors that could share their extra generation when needed than to build extra generation in its own service area. When Order No. 888 was under consideration, such utilities argued that some transmission transfer capability should be set aside for this generation reliability function.
Since Order No. 888 issued, at least two issues related to CBM have been controversial. One is whether all network transmission customers, including for example municipal utilities within the transmission owner's service territory, have an equal opportunity to set aside transmission for this purpose. The second is whether those who set aside transmission for CBM are reserving it and paying for it under the terms of the
The second issue is best explained with an example. Suppose a transmission-owning public utility sets aside 100 MW of transfer capability at its interface with a neighboring utility to help ensure adequate generation for the public utility's native load customers. Suppose further that the public utility's native load is 600 MW, and the collective amount of point-to-point transmission customer imports is 200 MW and the line's total capacity is 900 MW. Under the usual method of allocating transmission costs to customers, the point-to-point customer would pay for and receive 200 MW of transmission service and the public utility would pay for 600 MW of transmission system cost but receive 600 MW of transmission service and 100 MW of reserved capacity. In some cases, the transmission provider's merchant affiliate has used the CBM set-aside on a non-firm basis to make sales without paying for the transmission capacity used.
In 1998 the Commission received complaints alleging that some transmission-owning utilities were inappropriately reducing Available Transfer Capability to reflect transmission reliability requirements and capacity benefit margins.
In 1999, the Commission initiated a generic inquiry into policies for transmission reliability set-asides. In particular, the Commission convened a conference in May 1999 in which it examined the practices of use, and the alleged abuses, of CBM.
In July 1999, the Commission issued an order clarifying the method for computing ATC, including provisions dealing with CBM.
NERC called on each region to develop and document its own methodologies and guidelines for determining TRM and CBM.
The lack of standards for TRM and CBM impedes the development of basic information required by Order Nos. 888 and 889 as a basis for eliminating undue discrimination in the provision of interstate transmission services. Further impeding competition is continued uncertainty about whether and how to account for CBM in determining ATC and how CBM costs should be allocated. The industry needs Commission guidance to achieve standardization in these areas.
The existing definition of ATC coordination does not meet the needs of all members of the marketplace (all market participants) because there are too many diverse opinions that will not allow for consensus. * * * It is impossible to meet the existing definition of coordination due to differing market objectives, and regional business practices and transmission provider tariffs, and corporate objectives. Until these issues are resolved, coordination will not occur. Available Transfer Capability Coordination Task Force,
The Commission continues to receive complaints that transmission service to deliver power to bundled retail customers continues to be superior to transmission services for wholesale and unbundled retail transmission customers. In
Although NSP later withdrew its objection to equal transmission curtailment treatment for all transmission customers, the case points out a difficulty the Commission has in ensuring transmission access that is not unduly discriminatory for all transmission customers—retail and wholesale—unless all transmission customers take service under the same tariff.
As an example of a specific seams problem, incompatible ramping rules have made power sales among the ISO systems in the Northeast unnecessarily difficult and prevented some trades. Among the operating protocols of a transmission provider are rules for increasing and decreasing the power output of a generator (called “ramping”) connected to the transmission system. To implement a transaction between two systems, generation in the supplying system must be increased, or “ramped” up, and generation in the receiving system must be decreased, or “ramped” down. The ramping up and ramping down in the two systems should begin at the same time, last for the same length of time, and end at the same time. But different systems can have different rules about the timing and rate of ramping. For example, PJM allows ramping to occur every fifteen minutes; it can occur, for example, at 1 p.m., 1:15 p.m., 1:30 p.m, 1:45 p.m., 2 p.m., and so forth. New York and New England require ramping to occur on the hour, at 1 p.m or 2 p.m. but not within an hour. Thus, PJM's ramping rules permit a sale from PJM to New York to begin on the half hour by ramping up generation in PJM, but New York's ramping rules do not allow a buyer in New York to receive the power because it cannot ramp down generation on the half hour. Also, systems may place different limits on the amount of ramping that may occur on the interface with a neighboring system. Then, one system may allow an amount to be exported that the neighbor will not allow to be imported.
Several efforts are underway at the Commission or within the industry to address seams problems and the
Many panelists at the Commission's seams conference urged us to develop standards for RTOs before they begin operating—indeed before they invest heavily in software development for a unique set of regional transmission rules and market designs.
Another seams problem can arise from different market price mitigation rules in neighboring regions. When western electric power prices were high in 2001, for a short time the Commission applied price mitigation to certain generators in California for spot market sales of power within California.
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The following outlines the Order No. 888-A
Currently, five ISOs operate organized markets for energy and ancillary services, California ISO, PJM, New York ISO, ISO-New England and ERCOT. This appendix discusses how Standard Market Design would handle various trading strategies that were allegedly used for market manipulation in these ISOs, including those described by Enron Corporation in two memoranda as being used in the California wholesale markets. Standard Market Design incorporates lessons we have learned from experience in these organized markets. In many cases the proposed market rules have been designed to avoid the market design flaws that were the basis for these trading strategies. For others, Standard Market Design relies on strong market monitoring by the Independent Transmission Provider's Market Monitoring Unit and the Commission Office of Market Oversight and Investigation to ensure compliance with the market rules and to detect new market manipulation strategies.
In memoranda dated December 6, 2000 and December 8, 2000, attorneys for Enron detailed various trading strategies that were being used in California wholesale markets. The strategies discussed in the Enron memoranda were mainly tailored to take advantage of flaws in the California market design, particularly its congestion management system. Standard Market Design uses a different congestion management system that would make most of these strategies infeasible.
Most of the strategies described in the Enron memoranda depended on the development of a day-ahead schedule for power sales that was developed without determining whether that day-ahead schedule was physically feasible. In real time, the California ISO made payments to entities to relieve congestion. This created an incentive for an entity to create congestion in the day-ahead schedule at no cost so that the same entity would be paid to relieve that congestion in real time.
Standard Market Design uses a nodal congestion management system, Locational Marginal Pricing (LMP) together with a physically feasible and financially binding day-ahead schedule. The use of a nodal congestion management system ensures that all transmission constraints are considered in developing day-ahead schedules and any congestion is reflected in the prices for energy and transmission services.
A few of the strategies in the Enron memoranda appear to depend on the marketer providing false information to the ISO. Thus, these strategies rely on evading or violating the market rules rather than on market design flaws. Standard Market Design addresses these types of strategies by requiring an active market monitoring program that will detect violations of market rules and take appropriate action against entities that violate the market rules.
The specific strategies in the Enron memoranda are discussed below.
This strategy appears to be designed to evade the requirement for balanced day-ahead schedules by the California ISO. Standard Market Design does not require load or generation to submit balanced day-ahead schedules. Therefore, such a strategy is not necessary to offer excess generation to the market. The market rules provide sellers with varying methods to do this. However, there are scheduling requirements and entities that do not follow them may be subject to penalties.
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This strategy appears designed to exploit a flaw in the California market design that is not present in Standard Market Design. The day-ahead schedule for energy developed by the PX market did not take into account transmission constraints. As such, the schedule that was developed was often not physically feasible. Second, entities were then paid to relieve the congestion in real-time that resulted from the infeasible day-ahead schedule. In contrast, Standard Market Design uses a security constrained day-ahead schedule for energy. This means the day-ahead schedule accounts for all transmission system constraints needed for reliable system operations. Thus, the day-ahead schedules in the Standard Market Design will not have the type of manufactured congestion discussed in the Enron memoranda. Standard Market Design also uses a more efficient congestion management system, LMP, than that used by the California ISO. Under LMP, the entities that cause congestion are charged for that congestion. Thus, there would be no need for separate payments by the ISO to relieve congestion as occurred in California.
The strategy was designed to take advantage of the fact that there was a price cap in effect in only part of the market. This problem was eliminated in California when West-wide mitigation measures were imposed. Standard Market Design will apply consistent market mitigation measures across all regions. Thus, the incentive for this type of strategy is significantly reduced. Also, Standard Market Design includes a resource adequacy requirement for load serving entities that avoids or minimizes the energy shortage conditions that made this strategy possible.
This strategy appears to exploit a loophole in the California congestion management system that allowed an entity to get a payment for shipping power that wasn't actually shipped. In contrast, under Standard Market Design the day-ahead schedule would be financially binding so a marketer could not cancel the arrangement without a financial penalty. Also, Standard Market Design uses LMP to manage congestion rather than separate payments to relieve congestion.
This strategy appears designed to exploit a flaw in the way that congestion charges were paid in California. Under LMP, the entity would only be paid in real time for power
The strategy relies on the flaws in the congestion management system in California. The zonal congestion system used in California provides more opportunities to game congestion than the nodal congestion system under LMP. Because of the separation of the day-ahead market (formerly administered by the PX) and the real-time balancing market (administered by the ISO), there are numerous ways that market participants can create artificial congestion in the day-ahead market and then be paid to relieve the congestion in real time. Under LMP, the entity that caused the congestion would pay for the congestion.
Standard Market Design proposes a day-ahead and real-time market for ancillary services. Financial bids for ancillary services are not permitted. Bidders would be required to identify specific units that would be used to provide the ancillary services. Market monitoring would be used to ensure that ancillary service bids are backed by real resources.
This strategy is also based on virtual bidding, something that is allowed under Standard Market Design for energy markets. Virtual bidding should cause the prices in the day-ahead and real-time markets to converge. This by itself does not harm customers. It means that a customer that buys power in real time will pay approximately the same as a customer that buys power day ahead. However, under Standard Market Design, bidders would be required to specifically identify energy bids that are not backed by physical resources. This is important for reliability purposes, to ensure that the transmission provider can ensure that sufficient physical resources are committed to meet the projected load. In contrast, Enron apparently indicated the ancillary bids were backed by physical resources when they were not. This could have affected reliability if Enron was actually called on to supply the ancillary services.
This strategy appears designed to exploit two flaws in the California system that do not exist in Standard Market Design. First, because Standard Market Design uses security-constrained unit commitment and dispatch procedures in operating their energy markets, market participants could not schedule transactions day-ahead or real-time that are physically impossible. Second, the congestion management system under Standard Market Design is fully integrated with the energy markets and therefore would not provide separate payments for relieving congestion as in California. Under LMP, if more entities were trying to schedule an export than the physical capacity of the line, this excess would be reflected in the market clearing prices for the energy exports, which in turn would be used to compute appropriate congestion charges. Thus, there would be nothing to gain in using this strategy.
The main purpose of this strategy is to evade California's price caps which apply to in-state generation, but not to external generation purchased “out of market.” Under Standard Market Design there would be consistent market mitigation measures across the country. Therefore, there would not be the opportunity to take advantage of the differences in market rules. In California, the “Ricochet” strategy ended when consistent West-wide mitigation rules went into effect.
The reason for this strategy is that Enron would get paid for ancillary services if the energy was labeled as firm, but would not get paid for ancillary services if it was labeled as non-firm. Under Standard Market Design all transmission service would be under Network Access Service so there would be no difference in the ancillary service requirements. Thus, there would be no reason for this strategy.
This strategy exploited a loophole in the CA ISO congestion management system that does not exist under the LMP system used in Standard Market Design. As the memorandum notes, CA ISO paid congestion charges whether any power flowed or not. Under Standard Market Design if an entity sold energy in the day-ahead market it would either have to provide the energy in real time or buy back its position (it would be charged the real-time price for the energy). Also, the strategy may be related to the fact that the day-ahead schedule for energy developed by the Cal PX did not account for transmission constraints. CA ISO then paid congestion charges to entities to relieve the congestion they had created through their scheduling. The security constrained day-ahead schedules required in Standard Market Design takes into account transmission constraints. So, there is not the same opportunity for this type of market manipulation.
Because several components of Standard Market Design are based on market designs in effect in the Eastern ISOs markets—PJM, New York and New England—it is important to turn to these markets to verify that the Standard Market Design rules protect against market manipulation. In this regard, the following points are important. First, the Eastern ISO markets have recognized almost from the start of market operations that no market design can protect against market power due to structural conditions, such as the high concentration of firms in a region or load pocket and/or the lack of price-sensitive demand. For this reason, the Standard Market Design includes market power mitigation rules.
Second, there have been several years of learning in the Eastern ISO markets on market design. Small details of market design can turn out to have major effects on market performance. We have used this experience in developing the market rules for Standard Market Design.
Like the California markets, the Eastern ISO markets have been alleged to be subject periodically to physical and economic withholding of capacity by firms and other measures employed as a means to increase market prices for energy, ancillary services and installed capacity, and to manipulate the prices for transmission rights. However, these attempts have been more sporadic and have had a far less significant economic impact than California. This is due in part to the fact that approximately 85 percent of demand is covered under long-term contracts and therefore is unaffected by spot price volatility. In general, the Eastern markets are considered relatively competitive and have a range of measures in place to monitor and mitigate locational market power.
The previous section examined whether the Enron strategies in California could be used to manipulate prices under the Standard Market Design. This section reviews some of the publicly known examples of market manipulation in the Eastern ISO markets and discusses whether and how the Standard Market Design would prevent such activity.
The Eastern ISO energy markets have been subject to forms of market manipulation and market power, including both economic and physical withholding. Most exercise of market power in the energy markets occurs in two types of system conditions: (1) The existence of persistent transmission constraints in some locations and (2) periods of system-wide shortage of energy, such as exists on peak-load days or during emergencies. Locations that are on the import side of persistently congested transmission lines (sometimes called “load pockets”) present the most opportunity for exercise of market power due to the high concentration that occurs in these locations. Generators in these locations are typically closely monitored and/or placed under contract to prevent bid price increases. Hence, this section will not consider market power in these locations.
During capacity shortages or system emergencies, market power is more diffuse, reflecting the possibility that all generation will have to be dispatched. For example, the PJM market monitor believes that high energy prices in the summer of 1999 were the result of the interaction of high demand levels with supply curves that exhibited steep slopes over very narrow ranges of output. Some firms appear to have withheld capacity and changed bid parameters during peak hours as a means to drive up prices (
During periods of shortage, interactions between the energy markets and the markets for ancillary services and installed capacity are also more significant. Market power in each type of market can affect the other. Price increases in the energy markets will lead to higher prices for ancillary services, since the prices in the latter markets reflect the opportunity costs associated with forgone energy sales.
(a) In PJM, certain generators were increasing their minimum run times to the full 24 hours of the day and submitting high price bids. Under the PJM energy market rules, the bids were evaluated over the full day; hence, under normal conditions, high price bids would be rejected. However, in Maximum Generation Emergencies, PJM was required to take all economic offers, regardless of the number of hours of the day in which such offers were economic, prior to taking other emergency measures, such as recalling capacity resources. This allowed these generators to run at a high price all day and set LMPs higher than the $1,000 bid cap. PJM estimated that in 1999, excess energy payments to just one plant of $8 million resulted from this bidding technique. The Commission approved PJM's market rule revision to address this problem, which restricted the bid sufficiency guarantee only to the hours in which the generator bid was economic during the emergency.
Under the proposed Standard Market Design market rules, as in PJM, a generator's bid offer must be considered over the full day. Hence in normal circumstances, as in PJM, changing the generator's minimum run time should not confer any competitive advantage. The Standard Market Design rules explicitly require that the Transmission Provider must evaluate how emergency conditions affect market prices. In complying with this requirement, the Commission will evaluate whether the rules prevent market manipulation, whether by adopting the PJM rules or some other measures.
(b) In New England, generators were bidding very high low operating levels—that is, setting a high minimum output level. By the existing rules in New England, these generators were not eligible to set the Energy Clearing Price but were eligible for uplift payments based on their bid. The ISO proposed, and the Commission accepted, that generators would be required to bid their physical low operating levels, subject to adjustment for emissions or economic efficiency reasons.
Under Standard Market Design, the Transmission Provider is given authority to put limits on the frequency with which physical bid parameters can be changed, and other limits on how the operating characteristics of the generators are bid. These potential bid restrictions can be used to address any evidence of market manipulation or to anticipate such behavior.
Bid-based ancillary service markets typically have fewer eligible suppliers (particularly until demand-side resources participate) than the energy markets as well as inelastic demand (unless demand curves for reserves are established). Locational reserve requirements may narrow the markets further. Finally, as noted above, market power in the energy markets is transferred to the ancillary service markets through opportunity cost payments and other market rules.
As in the energy markets, Standard Market Design auctions alone cannot solve structural sources of market power in the regulation and operating reserves markets. Rather, these problems must be addressed through a combination of market power mitigation measures, such as bid caps, and structural solutions, such as encouraging entry into these markets by generators with flexible start-times.
The congestion management system based on LMP and financial transmission rights proposed in the Standard Market Design and in use in PJM and New York presents a clear advantage over the transmission line-loading relief (TLR) methods used in other parts of the country. The LMP-based method has caused far fewer instances of transmission curtailments.
Care must be taken to discriminate between legitimate transactions and those aiming to favor owners of certain generation or transmission assets. Increasing congestion is not necessarily a sign of intentional activity to congest; all the Eastern ISOs report increasing congestion as market trading increases simply because there is more demand for distant resources and associated transmission. In addition, changes in congestion accounting may increase the amount of apparent congestion
An important financial linkage in the Standard Market Design is between the congestion management system and the holding of Congestion Revenue Rights. The Standard Market Design rules aim to find a method of allocation, trade and settlement of such rights that is equitable, transparent, provides appropriate incentives for maintenance of and investment in transmission assets, and is resistant to manipulation. The following example shows how market manipulation can occur.
This problem is generic to electricity markets with transmission rights. The rights established under Standard Market Design, which include financial rights analogous to FTRs in PJM, are susceptible under some conditions to manipulation by transmission owners and their affiliates. The Standard Market Design requires market monitoring and appropriate transmission maintenance oversight and incentives to mitigate such problems.
Each of the Eastern ISO markets has an installed capacity requirement and an ISO-operated capacity market (with the exception of New England, in which the market was terminated). The design of these markets is different in each ISO, as is the market structure (that is, the degree of firm concentration in the market); hence, the problems experienced in each market have also been different. As discussed in this proposed rule preamble (Section H), for various reasons the proposed Standard Market Design includes a resource adequacy requirement similar in purpose to what is called here “installed capacity” but does not include either specific rules for a tradable capacity product or a centralized market to provide such adequacy. However, regions may choose to establish such markets. This section discusses some of the market manipulation that has been experienced in the existing ICAP markets. The Commission will evaluate any proposals for new markets for resource adequacy on the basis that they do not result in a repeat of the flaws detected in the existing ISO installed capacity markets.
The subsequent modifications of the New England ICAP requirements and markets will not be reviewed here. In a June 28, 2000, order, the Commission agreed with the ISO that the existing installed capability auction market was not useful and that it could produce inflated prices unrelated to the actual harm created by installed capability deficiencies.
In PJM, each load-serving entity has the obligation to own capacity, have a bilateral contract for capacity, or purchase capacity credits through a centralized market equal to its peak load plus a reserve margin. To qualify as a capacity resource, a generating unit must pass tests regarding overall capability and the ability to deliver energy to PJM load, which requires adequate transmission capability. Load-serving entities can use their capacity resources to produce energy for export from the PJM control area, but such transactions are subject to recall by PJM in emergencies. If a load-serving entity's capacity resources are less than its obligation, then it is considered deficient and subject to a penalty. In 2001, the capacity credit market was operated on a daily, monthly and multi-monthly basis as well as on an “interval” basis defined by seasons (the daily market serves residual demand after the markets for longer-term credits close).
Between January and April 2001, a single firm raised the price in the daily capacity credit market for a sustained period of time by essentially being in a position that required all buyers that were short of capacity to have to purchase some or all of their capacity from it. The determination that this price increase was the exercise of market power through economic withholding was made on the basis of the excess capacity available at the time as well as calculation of the opportunity cost of that capacity, which is the sale of the firm energy output forward into a neighboring market. Effective June 2001, the Commission approved market rule changes that diminished the incentive to economically withhold by spreading the revenues accruing to owners of excess capacity to all compliant load-serving entities rather than to the single firm.
All existing customers using transmission service, whether through bundled contracts, service agreements under the
This proposed rule gives the region a choice between an initial allocation or an auction of Congestion Revenue Rights. The first portion, “Phase I,” deals with regions that start with an allocation of Congestion Revenue Rights to existing long-term customers based on their historical use of the system. In this sense there is a link between paying the access charge and receiving Congestion Revenue Rights. However, this is not a one-to-one link,
The following answers the question of whether and how the following customers currently receiving various services will pay access charges or receive Congestion Revenue Rights. All service in the following examples would be performed under Network Access Service upon implementation of Standard Market Design.
These customers would receive no Congestion Revenue Rights (however, transactions under which power is taken off the grid pay an access charge; those under which power is not taken off the grid do not pay an access charge). These contracts would be converted to Network Access Service at the time Standard Market Design is implemented through the SMD Tariff.
a. Load-Serving Entity (service to load within a single Transmission Provider's area)—These customers currently pay and would continue to pay the access charge, and would receive a direct allocation of Congestion Revenue Rights.
b. Internal, Non-Load Serving Transactions (service within a single Transmission Provider's area from generator to hub, hub-to-hub, or to support sales to the spot market)—The customer currently has specific rights to capacity between stated points and, for this, pays the access charge. Under Standard Market Design, it would be permitted to retain its priority rights, albeit in the form of Congestion Revenue Rights rather than firm transmission capacity rights through Phase I. For this continued right, however, the customer must continue to pay the access charge to receive a direct allocation of Congestion Revenue Rights. In other words, it could choose to either (1) continue the point-to-point contract, including paying the access charge, and for that would receive a direct allocation of Congestion Revenue Rights; or (2) terminate the contract, meaning the customer would no longer pay the access charge, no longer receive specific transmission capacity rights between points, and, therefore, would not receive a direct allocation of Congestion Revenue Rights. Under the second choice, the customer would instead schedule service in the day-ahead and real-time markets and pay the applicable congestion and loss charges.
c. Through and Out (export by generator or marketer)—Consistent with internal, load-serving transactions (above), the customer currently has specific rights to capacity between stated points and, for this, pays the access charge, but would no longer be required to pay the access charge to export power to another region. It would be permitted to retain its priority rights, albeit in the form of Congestion Revenue Rights rather than firm transmission capacity rights through Phase I so long as it continued to pay an access charge on the source Transmission Provider's system. In addition, the access (or scheduling) charge paid by all load-serving entities taking power off of the grid on the sink side of a transaction involving two Transmission Providers' systems would include a portion of the transmission costs from the source side of the transaction, as explained below.
Under Phase II, Congestion Revenue Rights (other than those assigned to an entity on a “life of the facility” basis as a result of the customer paying for the network upgrades) will be auctioned off rather than allocated to particular customers. The link between paying the access charge and receiving Congestion Revenue Rights will no longer exist once we move to a full auction, since any entity can acquire Congestion Revenue Rights through the auction, with no requirement to pay an access charge to get them. Instead, the link moves to the revenue side,
a. At the time of direct allocation—this is defined above (long-term customers pay the access charge and get the direct allocation of Congestion Revenue Rights)
b. At the time of the auction—this is defined above for various categories of customers (some customers will continue to pay the access charge, which will be reduced by auction revenues, but all Congestion Revenue Rights will be auctioned)
a. At the time of direct allocation—When a customer requests firm service under the existing
b. At the time of the auction—Under Standard Market Design, customers generally will no longer request to build facilities to receive “firm” service, since all service will be allocated based on the customer's willingness to pay congestion costs. Rather, customers will request an economic expansion in order to avoid paying the cost of congestion. For economic expansions that are not rolled in to the embedded cost charge, the customer will pay the Transmission Provider the cost of the new facilities in order to acquire the Congestion Revenue Rights, and will continue to pay the access charge to receive Network Access Service.
a. At the time of direct allocation—reliability expansions benefit all users of the grid; therefore, the costs are rolled-in to the access charge either regionally or to a license plate zone. Accordingly, any newly created Congestion Revenue Rights associated with the expansion will be auctioned.
b. At the time of the auction—the introduction of the full auction would have no impact on reliability expansions, which will continue to be rolled-in either regionally or to a license plate zone with any newly created Congestion Revenue Rights associated with the expansion offered in an auction.
a. At the time of direct allocation—currently, the interconnecting generator pre-pays for transmission service and receives credits against the monthly cost of transmission service, whether the generator is the customer or it is chosen as a network resource by a load-serving entity. To the extent the generator is a long-term transmission customer, it would receive Congestion Revenue Rights associated with its transmission service (otherwise the network customer that chose the generator as a network resource would receive the Congestion Revenue Rights).
b. At the time of the auction—a generator would be treated in the same fashion as other customers under the
a. At the time of direct allocation—A merchant transmission owner does not receive service, but rather is a transmission owner. A customer using this facility would also have to pay for service across the RTO plus a rate for service on the merchant facility. Accordingly, the merchant transmission owner would pay for the full cost of constructing the new facilities and would receive the Congestion Revenue Rights associated with its facility for the economic life of the facility. The full amount of those rights may be subject to change based on changes in the overall grid over time (
b. At the time of the auction—the introduction of the full auction will not change the way merchant facilities are addressed—the merchant transmission owner would pay for the full cost of constructing the new facilities and would receive the Congestion Revenue Rights associated with its facility for the economic life of the facility.
This rulemaking proposes to eliminate transaction fees (the access charge) on through and out transactions. This, by definition, raises the possibility of cost shifts, resulting in winners and losers. This scenario has been previously faced and resolved within a Transmission Provider's service area, with the result being the elimination of pancaked rates, and can be resolved across multiple service areas as well.
Currently, all transmission customers pay a share of the embedded costs of the transmission system. Under Standard Market Design, only load-serving entities (
Current situation on a hypothetical RTO (or transmission provider's system): 90 percent of the embedded costs are paid for by bundled retail customers, network customers, and point-to-point customers who serve load within the RTO. 10 percent of the embedded costs are paid for by point-to-point customers exporting power to another RTO or moving power within the RTO but not to load.
Standard Market Design will have two transmission rate impacts: First, the non-load serving transactions will no longer pay the access charge. Second, the inter-regional transfers will be netted across RTOs and the load-serving entities on the net importing RTO will pay a load ratio share of the embedded costs of the exporting RTO. On first blush, it would appear that the load-serving entities on both RTOs will pay more of the embedded costs to make up for the fact that exporting generators will no longer pay an access charge. While this is true with respect to transmission costs, it ignores the intended benefit of this rate change—lower generation costs.
First, access charges paid by generators for the first leg of a transaction, whether to serve load in the same or a neighboring RTO, are ultimately paid by the purchaser of the power. So, recovering these costs directly from the load-serving entities will not increase the overall cost of delivered power.
More importantly, removing this additional transaction fee reduces the cost of reaching generation on a neighboring RTO. The removal of the transaction cost makes cheaper generation available across a broader area, which leads to a more optimal dispatch and lower generation cost for all customers.
For example, assume load is served at a particular location in RTO A at an LMP of $25, and that there is a generator on neighboring RTO B willing and able to sell at $24 (
The precise details of how current contracts will be transitioned and how embedded transmission costs associated with inter-regional transactions will be netted across regions should be left to regions to work out in compliance filings.
Wholesale electric grid operations are highly interdependent, and a failure of one part of the generation, transmission or grid management system can compromise the reliable operation of a major portion of the regional grid. Similarly, the wholesale electric market—as a network of economic transactions and interdependencies—relies on the continuing reliable operation of not only physical grid resources, but also the operational infrastructure of monitoring, dispatch and market software and systems. Because of this mutual vulnerability and interdependence, it is necessary to safeguard the electric grid and market resources and systems by establishing minimum standards for all market participants, to assure that a lack of security for one resource does not compromise security and risk grid and market failure for the market or grid as a whole.
The purpose of these standards is to ensure that electric market participants have a basic Security Program protecting the electric grid and market from the impacts of acts, either accidental or malicious, that aren't authentic or could cause wide-ranging, harmful impacts on grid operations and market resources. A basic Security Program for electric grid and market resources (hereafter referred to as market resources) shall cover governance, planning, prevention, operations, incident response, and business continuity.
Security standards for market resources will primarily focus on electronic systems, which include hardware, software, data, related communications networks, control systems as they impact the grid or market, and personnel (hereafter the word cyber shall refer to all of these aspects). In addition, physical security will be addressed to the extent that it is necessary to assure a secure physical environment for cyber resources.
This initial set of security standards represent a minimum set of measures derived from commonly accepted industry standards and practices, such as the Common Criteria, CTSEC, ITSEC, IPSEC, ISO 17799, NIST Guidelines, and the NERC Security Guidelines. Market participants are encouraged to review their individual situation and tolerance for risk and implement a Security Program that goes beyond these basic security standards herein.
These standards are intended to ensure that appropriate mitigating plans and actions are in place, recognizing the role of the participant in the marketplace and the risks being managed. For the purpose of these security standards, participants are defined as, and the standards shall apply to:
• The market operations of RTO's and ISO's, and their market connections to Control Areas,
• Marketers,
• Transmission Owners,
• Power Producers,
• Load-serving entities and other power purchasers,
• NERC and the Reliability Authorities, and
• Tagging (or other similar dispatching) Organizations.
Further, if a power-generating unit participates directly in the grid (
These security standards shall become effective on January 1, 2004. Beginning 2004, on January 1 of each year, every participant shall file with FERC a self-certification signed by an officer of the company indicating compliance with these standards and identifying any areas of non-compliance. Failure to comply with these security standards will result in loss of direct access privileges to the electric market.
Malicious acts directed against the electric market, shall be prosecuted by FERC and law enforcement agencies to the full extent of the law, including the recovery of damages.
Participant senior management shall designate a management official to be
Participants shall define their security perimeter and identify the boundaries and defenses for physical and cyber security that delineate and protect the critical resources under their control. The security perimeter shall identify all entry and exit points and the requirements for access controls.
A Security Program and policy based on these security standards shall be developed to protect critical electric grid and market functions and resources within the security perimeter and at entry and exit points where personnel, supplies or communications may come and go. Additionally, related procedures shall be created that guide implementation and enforcement of the security standards. Policy and procedures shall be reviewed for appropriateness (due to changes in personnel, technology, equipment configuration, vulnerabilities and threats) as necessary, and at least annually.
Electric market assets within the security perimeter shall be classified as to their criticality in maintaining and protecting electric market functions. A classification system shall further define appropriate levels of protection for each level of criticality, and access rights that will be granted for each level of criticality. All critical assets within the perimeter (computers, networks, doorways, etc.) shall have a custodian who ensures that those assets are handled in accordance with their assigned classification scheme.
Any personnel who are authorized access within the security perimeter, or are authorized access to administer, operate or maintain assets within the security perimeter shall be trained on the Security Program and security standards related to their respective positions. This training shall start upon employment, be repeated annually and at career points where significant responsibilities change. Security awareness training shall be provided to all staff.
To the extent permitted by law, personnel required to administer or operate assets classified as critical (according to the participant's classification system) shall undergo background investigation conducted prior to employment, upon promotion to such positions (if not a new hire), and at periodic intervals (not to exceed five years). The participant shall review the results of the background checks and take appropriate action. Individuals shall be disqualified from administering, operating or accessing critical assets if the individual meets any disqualifying criteria specified by the Federal Bureau of Investigation, Office of Homeland Security, RCMP, or other federal agency.
A process such as transaction logs shall be in place to identify individual users of critical systems and their time of access. Procedures for critical electric grid and market resources within the security perimeter shall be developed that establish and monitor controls for:
(1) The assignment of both logical and physical access rights (as defined in the classification system);
(2) The prompt disabling of access rights when positions are terminated or job responsibilities no longer require access; and
(3) The annual re-evaluation of assigned access rights.
Such authorized personnel—including visitors and service vendors—shall only have access (whether logical or physical) to electric market resources within the security perimeter that they are authorized for. Any and all unauthorized personnel allowed temporary access within the security perimeter shall be escorted at all times.
Procedures for critical electric market resources within the security perimeter shall be developed to monitor and protect cyber assets, such as:
• Computers
• Software
• Data, as stored and transmitted
• Servers
• Routers
• Modems
• Communications channels, whether owned or leased
At a minimum, these procedures shall address:
(1) The use of effective password routines that periodically require changing of passwords, including the replacement of default passwords on newly installed equipment;
(2) Authorization and re-validation of computer accounts;
(3) Disabling of unauthorized (invalidated, expired) or unused computer accounts;
(4) Disabling of unused network services and ports;
(5) Secure dial-up modem connections;
(6) Firewall software (for routed Internet access);
(7) Intrusion Detection Systems (for networked routers and firewalls);
(8) Patch management;
(9) Installation and update of anti-virus software checkers.
For critical electric systems, operator logs and Intrusion Detection System logs shall be maintained for the purpose of checking system anomalies and for evidence of suspected unauthorized activity. Appropriate procedures for securing control systems that are critical to the grid or market shall be developed and employed. The procedures shall address:
(1) Remote access including modems and other means;
(2) Security patch management, as appropriate;
(3) Assurance that communication channels are adequate so as not to impact the performance of the control system and its critical functions; and
(4) Assurance that system procedures do not impact the performance of the control system and its critical functions.
Procedures for critical electric resources within the security perimeter shall be established to monitor and control physical features, such as:
• Doors,
• Windows,
• Floor space,
• Environmental systems,
• Backup power systems—whether owned or leased.
At a minimum, these procedures shall address:
(1) Appropriate security barriers and entry controls;
(2) Mechanical and electronic key and badge programs;
(3) Access locking of unattended assets; and,
(4) Protection from environmental threats and hazards (
Critical electric facilities shall restrict the distribution of maps, floor plans and equipment layouts pertaining to those facilities, and restrict the use of signage indicating critical facility locations.
Security requirements for critical electric systems within the security perimeter shall be identified, documented and agreed upon prior to development, procurement, enhancement to, installation of and acceptance testing for cyber resources or related physical features. For critical control systems, this means developing cyber security procedures to augment existing test and/or acceptance procedures.
Development and testing of critical electric market systems shall be conducted in system environments that are not interconnected with operational system environments.
Organizations with critical electric market resources shall have incident response procedures, which define roles, responsibilities and actions to rapidly detect and protect electric resources in the event of harmful or unusual incidents, whether accidental or malicious.
Organizations with critical electric market resources shall report incidents to the Electricity Sector—Information Sharing and Analysis Center (ES-ISAC) and use reporting criteria, thresholds and procedures contained in NERC's Indications, Analysis and Warning (IAW) Program.
Every participant operating a critical electric resource shall have contingency plans that define roles, responsibilities and actions for protecting the rest of the electric grid and market from the failure of its own critical resources. Those plans should further define the roles, responsibilities and actions needed to quickly recover or reestablish electric grid and market functions, processes and systems, in the event that a critical physical or cyber resource fails or suffers harm or attack. Such plans shall be tested or exercised regularly.
The North American Electric Reliability Council (NERC) has established and maintains Security Guidelines for the Electricity Sector. NERC also provides a list of additional sources for security best practices. These references shall be helpful in developing organization-specific security
I am writing separately on the Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD) to express some of my thoughts on certain of its provisions and design elements. We have been discussing the broad contours of the SMD NOPR with interested parties for months through the staff white paper, the options paper and technical conferences. Many of the NOPR's features have been welcomed and embraced by various entities, associations, company representatives and academics. Just as many participants have cautioned us to make sure that the procedures, protocols and standards that we wish to impose on the industry we regulate are practical in implementation, fair to consumers and respectful of state jurisdiction. They have also asked us to recognize that not all regions of the country are the same or have the same historical ways of providing electricity to retail and wholesale customers.
For example, the way the Northeast has evolved with their power pools is vastly different from how the Southeast and the Southwest has traded bulk power. The northwest has a heavy reliance on hydroelectric generated power. Even with these differences, all the regions have provided reliable and steady service especially in times of extreme weather conditions.
People will be pouring over this NOPR to see if it is practical and if it is doable. During the October SMD/RTO week we were advised to keep it simple. This is anything but simple. It is a comprehensive proposal and it's very complicated. Over time it will result in a sophisticated market. Parties are going to need time to understand its complexities and implement its many features. The Commission is going to need patience and flexibility. We have not assigned a cost to this proposal but we know that each FERC jurisdictional entity is required to hire an independent transmission provider (ITP) if they are not already in an RTO. The ITPs must set up locational marginal pricing (LMP), day-ahead and real time energy
In Order 2000 we paired a voluntary rule with very tight compliance deadlines, deadlines that I believe we all knew at the time would be difficult to meet. Today's proposed rule pairs many complicated and mandatory requirements with short implementation time lines. For example, the LMP system paired with energy and ancillary services markets has not been proven outside of the tight power pools in the Northeast. Also, allocation of initial Congestion Revenue Rights will be complicated, if not problematic for some areas of the country. But, I am pleased that today's order recognizes that not all areas of the country will be able to move ahead with all requirements of SMD at lightning speed. The Commission intends to be flexible in some compliance dates and while it is the objective to have SMD in place within two years of the effective date of the Final Rule, the Commission will consider requests to extend that date.
The fundamental goal of SMD requirements in conjunction with the standardized transmission service is to create “seamless” wholesale power markets that allow sellers to transact easily across transmission grid boundaries. Once the final rule is in place and implemented my hope is that the squabbling over which entities belong in what RTO will end. We should be able to put our magic markers away for good.
Today's NOPR puts forward a detailed vision of the roles that ITPs, this commission and states will play in planning for expansion of the transmission grid. I am pleased that the governors have requested a significant role in transmission planning through the formation of Multi State Entities (or MSEs). I am also pleased that we propose to give MSEs a role in both overseeing the plans developed by the ITPs and in developing a fair pricing methodology for these expansions. I feel very positive about the bottom up approach that is described in the planning section of this NOPR. This approach allows merchant transmission companies and utilities, as well as generators and demand resources, to bring economic solutions to the table to solve the problems of under-built infrastructure. These projects must be vetted by the ITP to determine their impact on the grid in terms of loop flows and other regional impacts, but the real tests will be the demand for the projects much as we see in gas pipeline certificates.
I do have concerns about the planning protocols that would be enacted by the ITP once it is determined that economic projects cannot fulfill all of the reliability requirements of the grid. My concern is that this “central planning” aspect may direct projects that are uneconomic with costs socialized to all users of the grid. It is hard to imagine gold plating of the transmission grid when we are in an era of under-built infrastructure, but I believe that once we get the incentives right for building needed infrastructure there will be no need for the ITP to direct the construction of possibly “uneconomic” projects.
Getting the incentives right in grid expansion has been on my top ten list through this NOPR process and in my tenure here at the Commission. To this end, I have continued to be a proponent of Independent Transmission Companies (ITCs) and continue to believe that ITCs show great promise to address grid problems through profit driven activities. I am pleased that the NOPR proposes to adopt a form of participant funding once independent transmission entities are in place. I am also pleased that the Commission is willing to consider proposals submitted by Regional State Advisory Committees for participant funding prior to nation-wide adoption. This order gives a push to state and regional entities that already have significant momentum and I hope to see the fruit of the Regional-State groups efforts in the form of actionable plans for cost allocation of expanded transmission. However, if these groups have difficulty getting organized and implemented, there is a default mechanism that would allocate the costs of expanded transmission locally if the facilities are below 138 kV and regionally if the facilities are above the 138 kV level. I urge the parties, especially the states, to carefully consider this section of the NOPR and comment on this. I still have some uncertainty whether we reached the right balance here.
Furthermore, the states have been asking for some time for certain responsibilities in RTOs, particularly in the area of reliability and planning. In SMD it is envisioned that they will play important roles in developing the resource adequacy standards and transmission expansion pricing methods. We will give deference to areas that are not as far along in standardizing markets, allowing states to manage the pace of the required changes. Additionally, the proposed rule, while it asserts jurisdiction over native load, does not abrogate either actual or implicit contracts. I am not so Pollyanna as to believe that everyone will be happy with our assertion of jurisdiction over native load, in fact this is likely to be a big bone of contention. But take a look at the rule, as I think states will find that it tries to be balanced and allows them significant say in determining outcomes.
Another area that I have focused on in this process is cost shifts. I agree that embedded costs charges for wheel through and export transactions should be eliminated or minimized while at the same time assuring recovery of the transmission owner's revenue requirement. My concern with respect to cost shifts resulting from this removal of inter-regional rates is two-fold.
First, I fear that areas with low-cost energy, such as my state of Kentucky, will see those resources flow to high-cost areas located several states or regions away. It is a mathematical fact that when costs are averaged that someone's costs will go up. This particular concern is in part alleviated by the ability for those in low-cost areas to lock up their low-cost power resources in long term contracts. I also note that these transactions which will flow over greater distances, now that they no longer face the fixed cost of the transmission system, will be subject to marginal losses and congestion charges. I believe that marginal losses in excess of actual losses should be credited back to the areas where the power originated.
My second concern with cost shifts relates to the determination of how these costs will be apportioned among different types of customers. Even if costs are allocated to import zones instead of to each ITP, one customer in the zone that relies solely on generation within the zone could subsidize a customer that imports all of its requirements. This is due to the fact that the embedded costs for imports would be spread across all load within the zone. My hope is that parties will comment on these and other costs shifts giving us concrete examples of the kind and level of shifts that may occur. I would also ask for recommendations on how best to address cost shifts, especially if they have a significant impact on retail customers.
In Order 888, Imbalance service was an ancillary service that could be provided by the transmission provider or it could be self-supplied. In staff's initial thinking on SMD as expressed in their concept paper, the markets for both real-time and day ahead energy would only require voluntary participation. As we worked through the details of SMD, this idea morphed a bit to now require imbalance service to be taken through the real-time energy market set up by the ITP. Participation in the day-ahead market is still left to the buyer's discretion and bilateral contracts are encouraged. But, the requirement for load to buy their imbalance service through the real-time market is a significant change. Loads will be subject to spot prices for that small portion of their load that varies from their load forecasts. I hope that parties will comment on this change to imbalance service.
I believe that one of the fundamental underpinnings of this rule is to give equal access to the transmission grid to all and I support that notion. However, I recognize that giving everyone equal access means that decisions will be made based on each party's willingness to pay. This means that the price certainty that we gave through Order 888 will disappear. But, this does not mean that all price certainty will disappear because SMD provides mechanisms for customers to use to hedge the volatility in transmission markets and in real-time markets. My concern is that both small players and less sophisticated players will have increased transaction costs and steep learning curves in finding their way through these markets and in hedging these price risks. I don't want this rule to result in two classes of SMD participants—those that know how to participate effectively and those that have difficulty and incur higher costs without competitive benefits.
Also, after consulting several economic textbooks, we have defined market power for the first time in an electric order as “the ability to raise price above the competitive level”. We caveat that definition by stating that the determination of when to intervene in a market,
The three prongs of mitigation proposed in this NOPR, local market mitigation, a safety-
With respect to governance, I do not agree with the level of prescription that we are imposing on certain governance proposals. I don't think the Commission should be dictating with such specificity so many rules concerning the explicit makeup of stakeholder committees, who can sit on which committees, and exactly how boards should be selected. This could have the effect of disbanding boards of RTOs that are in the formative stages and boards that might have met our Order 2000 independence requirements.
And last, but definitely not least, I am pleased that today's proposed rule keeps the same provisions for reciprocity as that of the OATT. Entities that already have waivers of the reciprocity provision will not have to come in again and request additional waiver from the SMD provisions. Today's proposed rule also would allow reciprocal OATTs to be grandfathered and require no further changes to those tariffs to meet the new SMD requirements. This provides necessary relief to small transmission owners, including municipalities and cooperatives.
I urge my colleagues to carefully consider the comments and not be shy about considering changes to the proposal. We are asking over seventy-five questions which indicates that we still need industry's and the public's advice on a number of issues. I will be anxiously awaiting the comments and look forward to what parties have to say on these and other issues.
Bureau of Industry and Security, Commerce.
Final rule.
The Bureau of Industry and Security (BIS) is amending the Export Administration Regulations (EAR) by revising certain entries on its control list that are controlled for nuclear nonproliferation (NP) reasons. This final rule revises these entries to make them conform more closely to the format used in the technical descriptions of items identified in the Annex to the “Guidelines for Transfers of Nuclear-Related Dual-Use Equipment, Material, and Related Technology” (the Annex), which is published by the International Atomic Energy Agency. Member countries of the Nuclear Suppliers Group (NSG), which includes the United States, have established export licensing procedures for the transfer of items identified in the Annex.
This final rule also revises the types of controls and the scope of the controls that apply to a number of entries on the Commerce Control List (CCL). In addition, this rule amends the “Related Controls” paragraphs in a number of entries by adding references to related items that are either controlled under other entries on the CCL or controlled by other U.S. Government agencies.
As a result of the admission of Belarus, Cyprus, Slovenia, and Turkey to the Nuclear Suppliers Group, this rule adds these four countries to Country Group A:4, which identifies the member countries of the Nuclear Suppliers Group. These four countries are also added to the definition of the term “Nuclear Suppliers Group” in the EAR. The addition of these four countries will lessen the administrative burden on U.S. exporters by decreasing the number of items that require an export license to these countries for nuclear nonproliferation (NP) reasons.
This rule is effective August 29, 2002.
Steven Clagett, Office of Nonproliferation Controls and Treaty Compliance, Bureau of Industry and Security, Telephone: (202) 482-4188.
The Bureau of Industry and Security (BIS) maintains the Commerce Control List (CCL), Supplement No. 1 to part 774 of the Export Administration Regulations (EAR), which contains a number of items that are controlled for nuclear nonproliferation (NP) reasons. The items on the CCL that are controlled for NP reasons are referred to as “The Nuclear Referral List” and are subject to the licensing requirements and policies described in § 742.3 of the EAR. Most of the items on the Nuclear Referral List are identified in the Annex to the “Guidelines for Transfers of Nuclear-Related Dual-Use Equipment, Material, and Related Technology” (the Annex), which is published by the International Atomic Energy Agency in INFCIRC/254/Revision 4/Part 2. The United States, together with other participating countries in the Nuclear Suppliers Group, agreed to establish export licensing procedures to regulate exports and reexports of items identified in the Annex in accordance with the Nuclear Suppliers Guidelines.
This final rule amends the following Export Control Classification Numbers (ECCNs) on the CCL, which contain items controlled for NP reasons, by reformatting the control language in these ECCNs to conform more closely with the format used to describe such items in the Annex: 1A202, 1A226, 1A227, 1B201, 1B229, 1B230, 1B232, 1C202, 1C225 to 1C230, 1C232 to 1C237, 1C239, 1C240, 2A225, 2A226, 2B204, 2B206, 2B207, 2B209, 2B225 to 2B228, 2B230 to 2B232, 3A201, 3A225 to 3A227, 3A229 to 3A231, 3A233, 6A202, 6A205, and 6A225. The following ECCNs are amended by revising the ECCN heading to conform more closely with the control language used in the Annex or with the scope of controls described in the Annex: 1B226, 1B231, 1B233, 1C216, 1C231, 1D101, 1D201, 1E101, 1E102, 1E201, 1E203, 2A291, 2B001, 2B004, 2B009, 2B290, 2B350, 2D101, 2E101, 2E201, 3E201, 6A005, and 6E201. ECCNs 2B201, 3A232, and 6A203 are amended by revising the List of Items Controlled for each ECCN to conform more closely with the control language used in the Annex.
This rule also revises the Related Controls paragraphs in a number of ECCNs containing items subject to NP controls by adding references to one or more of the following: (1) Related items controlled under other ECCNs on the CCL, (2) related items subject to the export licensing authority of the Nuclear Regulatory Commission (NRC), and (3) related items subject to the export licensing authority of the Office of Defense Trade Controls (DTC), U.S. Department of State. The Related Controls paragraphs in the following ECCNs are revised: 1A002, 1A202, 1A225 to 1A227, 1B001, 1B101, 1B201, 1B225 to 1B233, 1C002, 1C010, 1C116, 1C202, 1C210, 1C216, 1C225 to 1C240, 1D001, 1D101, 1D201, 1E001, 2A225, 2A226, 2A290 to 2A293, 2B001, 2B004, 2B006, 2B007, 2B009, 2B104, 2B109, 2B116, 2B201, 2B204, 2B206, 2B207, 2B209, 2B225 to 2B232, 2B290, 2B350, 2B991, 2D001, 2D002, 2D101, 2D201, 2D290, 3A201, 3A225 to 3A233, 3A292, 6A003, 6A005, 6A202, 6A203, 6A205, 6A225, 6A226, and 6D001.
In addition, this rule revises the Related Definitions paragraph in the following ECCNs: 1A227, 1B229, 1C202, 1C210, 1C216, 1C225, 1C233, 2A226, 2B204, 3A230, 3A225, and 3A229. The text has been removed from the Related Definitions paragraph for ECCN 2B206 and much of it has been included in a new ECCN Controls paragraph for this ECCN, while the text in the Related Definitions paragraphs for ECCNs 2B225 and 3A232 has been moved to new Technical Notes in these entries. The text in the Related Definitions paragraph for ECCN 6E201, which described the scope of controls for this ECCN, has been removed and the scope of controls for ECCN 6E201 is now described in a new ECCN Controls paragraph.
In order to clarify the kinds of items that are subject to the controls specified in the CCL (
This final rule also revises the types of controls and/or the scope of certain controls that apply to the following ECCNs: 0D001 (now contains only DTC and NRC items), 0E001 (now contains only DOE and DTC items), 1B101 (scope of NP controls clarified), 1C235 (NP/AT controls added to tritium that is not subject to NRC export licensing authority), 1D101 (NP controls added to “software” for 1B101.a), 1E001 (NP controls removed from “technology” for 1C001 and added to “technology” for 1C002, 1C235, 1C239, and 1C240), 1E101 (NP controls added to “technology” for 1C116, 1D001 and 1D101), 1E102 (NP controls added to “technology” for 1D001 and 1D101), 2A226 (CB controls added to valves that meet or exceed 2B350.g specifications), 2A292 (CB controls added to valves that
Eligibility for License Exception LVS is removed for items controlled for NP reasons in the following ECCNs: 1A002, 1C002, and 3A001. License Exception LVS authorizes shipments of limited value without a license to destinations in Country Group B (Supplement No. 1 to part 740 of the EAR), provided that the net value of the commodities included in the same order and controlled under the same ECCN on the CCL does not exceed the amount specified in the LVS paragraph for the applicable ECCN.
In ECCN 1C236, which controls certain alpha-emitting radionuclides, the unit of measure is changed from “millicuries” to “gigabecquerels”. The unit of measure is the standard applied by BIS to determine the amount of an item that will be authorized for export or reexport under a license.
This final rule also completely revises ECCN 0B003 by removing the original control language, which predated the adoption of the controls in the NSG Trigger List that apply to exports of nuclear material, equipment, and technology. ECCN 0B003 now contains plants for the conversion of uranium and equipment specially designed or prepared for such plants, all of which remain subject to the export licensing authority of the Nuclear Regulatory Commission. These plants were previously contained in ECCN 0B009, which is removed from the CCL. This change is part of BIS's effort to make the numbering of the CCL entries conform more closely with the List of Dual-Use Items and Technology implemented by the European Union (
To further conform the numbering system in the CCL with the EU dual-use list, this final rule revises ECCN 2B104 and adds new ECCNs 2B105 and 2B117. ECCN 2B104, which previously controlled equipment and process controls designed or modified for densification and pyrolysis of structural composite rocket nozzles and reentry vehicle nose tips, now controls only “isostatic presses” (other than those controlled by 2B004) that have all of the following characteristics: (1) A maximum working pressure of 69 MPa or greater, (2) designed to achieve and maintain a controlled thermal environment of 873 K (600° C) or greater, and (3) a chamber cavity with an inside diameter of 254 mm or greater. New ECCN 2B105 controls CVD furnaces (other than those controlled by 2B005.a) that are designed or modified for the densification of carbon-carbon composites. New ECCN 2B117 controls equipment and process controls (other than those controlled by 2B004, 2B005.a, 2B104, or 2B105) that are designed or modified for densification and pyrolysis of structural composite rocket nozzles and reentry vehicle nose tips. ECCN 2B104 is now controlled for NP, as well as MT (missile technology) and AT (anti-terrorism) reasons, while new ECCNs 2B105 and 2B117 are controlled for MT and AT reasons.
This rule also removes ECCN 0B008 and transfers the items previously controlled by this ECCN (
Finally, this rule amends the EAR to add Belarus, Cyprus, Slovenia, and Turkey as the four newest participating countries in the Nuclear Suppliers Group (which now includes a total of 39 countries) by revising Supplement No. 1 to part 740 (Country Groups) to add Belarus, Cyprus, Slovenia, and Turkey to Country Group A:4 (Nuclear Suppliers Group) and by revising Supplement No. 1 to Part 738 (Commerce Country Chart) to remove the licensing requirements for these four countries under NP Column 1 in conformance with the licensing policy that applies to other NSG member countries. Please note that exports of NP-controlled items to these countries may require a license for other reasons set forth in the CCL or elsewhere in the EAR. This rule also amends § 772.1, “Definitions of terms as used in the Export Administration Regulations (EAR)”, by adding these four countries to the definition of the term “Nuclear Suppliers Group (NSG)”.
Shipments of items removed from License Exception LVS eligibility or NLR authorization as a result of this regulatory action that were on dock for loading, on lighter, laden aboard an exporting carrier, or en route aboard a carrier to a port of export, on August 29, 2002, pursuant to actual orders for export to a foreign destination, may proceed to that destination under the previous License Exception LVS eligibility or NLR authorization provisions so long as they have been exported from the United States before September 30, 2002. Any such items not actually exported before midnight, on September 30, 2002, require a license in accordance with this regulation.
1. This rule has been determined to be not significant for purposes of Executive Order 12866.
2. Notwithstanding any other provision of law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with, a collection of information subject to the requirements of the Paperwork
3. This rule does not contain policies with Federalism implications as that term is defined in Executive Order 13132.
4. The provisions of the Administrative Procedure Act (5 U.S.C. 553) requiring notice of proposed rulemaking, the opportunity for public participation, and a delay in effective date, are inapplicable because this regulation involves a military and foreign affairs function of the United States (Sec. 5 U.S.C. 553(a)(1)). Further, no other law requires that a notice of proposed rulemaking and an opportunity for public comment be given for this final rule. Because a notice of proposed rulemaking and an opportunity for public comment are not required to be given for this rule under 5 U.S.C. 553 or by any other law, the analytical requirements of the Regulatory Flexibility Act (5 U.S.C. 601
Therefore, this regulation is issued in final form. Although there is no formal comment period, public comments on this regulation are welcome on a continuing basis. Comments should be submitted to Willard Fisher, Regulatory Policy Division, Bureau of Industry and Security, U.S. Department of Commerce, Room 2705, 14th Street and Pennsylvania Avenue, NW., Washington, DC 20230.
Administrative practice and procedure, Exports, Foreign trade.
Administrative practice and procedure, Exports, Foreign trade, Reporting and recordkeeping requirements.
Exports, Foreign trade.
Exports, Foreign trade, Reporting and recordkeeping requirements.
50 U.S.C. app. 2401
50 U.S.C. app. 2401
(a) * * *
(3) * * *
(iii) No parts may be exported to any destination, except the countries listed in Supplement No. 3 to Part 744 of the EAR (Countries Not Subject to Certain Nuclear End-Use Restrictions in § 744.2(a)) if the item is to be incorporated into or used in nuclear weapons, nuclear explosive devices, nuclear testing related to activities described in § 744.2(a) of the EAR, the chemical processing of irradiated special nuclear or source material, the production of heavy water, the separation of isotopes of source and special nuclear materials, or the fabrication of nuclear reactor fuel containing plutonium, as described in § 744.2(a) of the EAR.
50 U.S.C. app. 2401
(a) * * *
(3) * * *
(i) Equipment and materials identified in ECCNs 2B350 and 2B351 on the CCL (as well as valves controlled by ECCN 2A226 or ECCN 2A292 having the characteristics of those controlled by 2B350.g), which can be used in the production of chemical weapons precursors or chemical warfare agents, and equipment and materials identified in ECCN 2B352, which can be used in the production of biological agents; and
50 U.S.C. app. 2401
(c)
50 U.S.C. app. 2401
50 U.S.C. app. 2401
Items described in 0B003 are subject to the export licensing authority of the Nuclear Regulatory Commission (see 10 CFR part 110).
“Software” for items described in 0A001, 0B001, 0B002, 0B003, 0B004, 0B005, 0B006, 0C001, 0C002, 0C004, 0C005, 0C006, or 0C201 is subject to the export licensing authority of the Nuclear Regulatory Commission (
“Software” for items described in 0A002 is subject to the export licensing authority of the U.S. Department of State, Office of Defense Trade Controls (
“Technology” for items described in 0A001, 0B001, 0B002, 0B003, 0B004, 0B005, 0B006, 0C001, 0C002, 0C004, 0C005, 0C006, 0C201, or 0D001 (applies to “software” in 0D001 for all items except those described in 0A002) is subject to the export licensing authority of the Department of Energy (see 10 CFR part 810).
“Technology” for items described in 0A002 and 0D001 (applies to “software” in 0D001 for items described in 0A002 only) is subject to the export licensing authority of the U.S. Department of State, Office of Defense Trade Controls (see 22 CFR part 121).
MT, NP, AT
The list of items controlled is contained in the ECCN heading.
1C240.b refers to porous metal formed by compacting and sintering the materials in 1C240.a to form a metal material with fine pores interconnected throughout the structure.
See § 743.1 of the EAR for reporting requirements for exports under License Exceptions.
2. 2A291.e does not control general purpose radiation detection equipment, such as geiger counters and dosimeters. These items are controlled by ECCN 1A999.
2B006.b.1 does not control measuring interferometer systems, without closed or open loop feedback, containing a “laser” to measure slide movement errors of machine-tools, dimensional inspection machines or similar equipment.
2B006.b.2 does not control optical instruments, such as autocollimators, using collimated light to detect angular displacement of a mirror.
2B201.a does not control milling machines having the following characteristics:
a. X-axis travel greater than 2 m;
b. Overall positioning accuracy on the x-axis more (worse) than 30 μm.
2B201.b does not control the following grinding machines:
a. Cylindrical external, internal, and external-internal grinding machines having all of the following characteristics:
1. Limited to cylindrical grinding;
2. A maximum workpiece outside diameter or length of 150 mm;
3. Not more than two axes that can be coordinated simultaneously for “contouring control”;
4. No contouring c-axis.
b. Jig grinders with axes limited to x, y, c and a where c axis is used to maintain the grinding wheel normal to the work surface, and the a axis is configured to grind barrel cams;
c. Tool or cutter grinding machines with “software” specially designed for the production of tools or cutters;
d. Crankshaft or camshaft grinding machines.
2B209.a includes machines that have only a single roller designed to deform metal, plus two auxiliary rollers that support the mandrel, but do not participate directly in the deformation process.
2B228.a includes precision mandrels, clamps, and shrink fit machines.
1. Inside diameter between 75 mm and 400 mm;
2. Length equal to or greater than 12.7 mm;
3. Single convolution depth greater than 2 mm;
4. Made of high-strength aluminum alloys, maraging steel or high strength “fibrous or filamentary materials”.
101. In Supplement No. 1 to Part 774 (the Commerce Control List), Category 2—Materials Processing, ECCN 2E001 is amended by revising the License Requirements section to read as follows:
See § 743.1 of the EAR for reporting requirements for exports under License Exceptions.
See § 743.1 of the EAR for reporting requirements for exports under License Exceptions.
3A201.b does not control magnets specially designed for and exported “as parts of” medical nuclear magnetic resonance (NMR) imaging systems. The phrase “as part of” does not necessarily mean physical part in the same shipment; separate shipments from different sources are allowed, provided the related export documents clearly specify that the shipments are dispatched “as part of” the imaging systems.
3A201.c does not control accelerators that are component parts of devices designed for purposes other than electron beam or X-ray radiation (electron microscopy, for example) nor those designed for medical purposes.
(2) “Peak power” = (peak potential in volts) × (peak beam current in amperes).
(3) In machines based on microwave accelerating cavities, the time duration of the beam pulse is the lesser of 1 μs or the duration of the bunched beam packet resulting from one microwave modulator pulse.
(4) In machines based on microwave accelerating cavities, the peak beam current is the average current in the time duration of a bunched beam packet.
(a) Pulsed excimer “lasers” controlled by 6A005.a.1.c having all of the following characteristics:
(1) Operating at wavelengths between 240 and 360 nm;
(2) A repetition rate > 250 Hz;
(3) An average output power > 500 W;
(b) Copper vapor “lasers” controlled by 6A005.a.2.a having all of the following characteristics:
(1) Operating at wavelengths between 500 and 600 nm;
(2) An average output power ≥ 40 W;
(c) Pulsed carbon dioxide “lasers” controlled by 6A005.a.4.c (except industrial CO
(1) Operating at wavelengths between 9,000 and 11,000 nm;
(2) A repetition rate > 250 Hz;
(3) An average output power > 500 W;
(4) A pulse width < 200 ns;
(d) Argon ion “lasers” controlled by 6A005.a.6 having all of the following characteristics:
(1) Operating at wavelengths between 400 and 515 nm;
(2) An average output power > 40 W;
(e) Alexandrite “lasers” controlled by 6A005.c.1.b having all of the following characteristics:
(1) Operating at wavelengths between 720 and 800 nm;
(2) A bandwidth ≤ 0.005 nm;
(3) A repetition rate > 125 Hz;
(4) Average output power > 30 W;
(f) Single-transverse mode output neodymium-doped (other than glass) “lasers” controlled by 6A005.c.2.b.2.a with an average output power > 40 W;
(g) Multiple-transverse mode output neodymium-doped (other than glass) “lasers” controlled by 6A005.c.2.b.2.b with an average output power > 50 W;
(h) Neodymium-doped (other than glass) “lasers” controlled by 6A005.c.2.c.2 having all of the following characteristics:
(1) Incorporating frequency doubling for output wavelength between 500 and 550 nm;
(2) Average output power > 40 W;
(i) Tunable pulsed single-mode dye “lasers” controlled by 6A005.d.2.c operating at wavelengths between 300 and 800 nm.
Components of cameras controlled by 6A203.a include their synchronizing electronics units and rotor assemblies consisting of turbines, mirrors and bearings.
6A205.c does not control single mode oscillators.
Fish and Wildlife Service, Interior.
Final rule.
This rule prescribes the hunting seasons, hours, areas, and daily bag and possession limits of mourning, white-winged, and white-tipped doves; band-tailed pigeons; rails; moorhens and gallinules; woodcock; common snipe; sandhill cranes; sea ducks; early (September) waterfowl seasons; migratory game birds in Alaska, Hawaii, Puerto Rico, and the Virgin Islands; and some extended falconry seasons. Taking of migratory birds is prohibited unless specifically provided for by annual regulations. This rule permits taking of designated species during the 2002-03 season.
This rule is effective on September 1, 2002.
Robert J. Blohm, Acting Chief, or Ron W. Kokel, Division of Migratory Bird Management, U.S. Fish and Wildlife Service, (703) 358-1714.
On March 19, 2002, we published in the
On June 19-20, we held open meetings with the Flyway Council Consultants at which the participants reviewed information on the current status of migratory shore and upland game birds and developed recommendations for the 2002-03 regulations for these species plus regulations for migratory game birds in Alaska, Puerto Rico, and the Virgin Islands, special September waterfowl seasons in designated States, special sea duck seasons in the Atlantic Flyway, and extended falconry seasons. In addition, we reviewed and discussed preliminary information on the status of waterfowl as it relates to the development and selection of the regulatory packages for the 2002-03 regular waterfowl seasons. On July 17, we published in the
On July 31 and August 1, 2002, we held open meetings with the Flyway Council Consultants at which the participants reviewed the status of waterfowl and developed recommendations for the 2002-03 regulations for these species. Proposed hunting regulations were discussed for late seasons. We published proposed frameworks for the 2002-03 late-season migratory bird hunting regulations on August 16, 2002, in the
The final rule described here is the sixth in the series of proposed, supplemental, and final rulemaking documents for migratory game bird hunting regulations and deals specifically with amending subpart K of 50 CFR part 20. It sets hunting seasons, hours, areas, and limits for mourning, white-winged, and white-tipped doves; band-tailed pigeons; rails; moorhens and gallinules; woodcock; common snipe; sandhill cranes; sea ducks; early (September) waterfowl seasons; mourning doves in Hawaii; migratory game birds in Alaska, Puerto Rico, and the Virgin Islands; youth waterfowl hunting day; and some extended falconry seasons.
NEPA considerations are covered by the programmatic document, “Final Supplemental Environmental Impact Statement: Issuance of Annual Regulations Permitting the Sport Hunting of Migratory Birds (FSES 88-14),” filed with the Environmental Protection Agency on June 9, 1988. We published a Notice of Availability in the
Section 7 of the Endangered Species Act, as amended (16 U.S.C. 1531-1543; 87 Stat. 884), provides that, “The Secretary shall review other programs administered by him and utilize such programs in furtherance of the purposes of this Act” (and) shall “insure that any action authorized, funded or carried out * * * is not likely to jeopardize the continued existence of any endangered species or threatened species or result in the destruction or adverse modification of [critical] habitat * * *” Consequently, we conducted formal consultations to ensure that actions resulting from these regulations would not likely jeopardize the continued existence of endangered or threatened species or result in the destruction or adverse modification of their critical habitat. Findings from these consultations are included in a biological opinion and concluded that the regulations are not likely to adversely affect any endangered or threatened species. Additionally, these findings may have caused modification of some regulatory measures previously proposed and the final frameworks reflect any such modifications. Our biological opinions resulting from this Section 7 consultation are public documents available for public inspection at the address indicated under the caption
This rule was reviewed by the Office of Management and Budget (OMB). The migratory bird hunting regulations are economically significant and are annually reviewed by OMB under Executive Order 12866. As such, a cost/benefit analysis was prepared in 1998 and is further discussed below under the heading Regulatory Flexibility Act. Copies of the cost/benefit analysis are available upon request from the address indicated under the caption
These regulations have a significant economic impact on substantial numbers of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
This rule is a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. For the reasons outlined above, this rule has an annual effect on the economy of $100 million or more. However, because this rule establishes hunting seasons, we do not plan to defer the effective date under the exemption contained in 5 U.S.C. 808(1).
We examined these regulations under the Paperwork Reduction Act of 1995. We utilize the various recordkeeping and reporting requirements imposed under regulations established in 50 CFR part 20, Subpart K, in the formulation of migratory game bird hunting regulations. Specifically, OMB has approved the information collection requirements of the Migratory Bird Harvest Information Program and assigned control number 1018-0015 (expires 10/31/2004). This information is used to provide a sampling frame for voluntary national surveys to improve our harvest estimates for all migratory game birds in order to better manage these populations. OMB has also approved the information collection requirements of the Sandhill Crane Harvest Questionnaire and assigned control number 1018-0023 (expires 7/31/2003). The information from this survey is used to estimate the magnitude and the geographical and temporal distribution of harvest, and the portion it constitutes of the total population. A Federal agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
We have determined and certify, in compliance with the requirements of the Unfunded Mandates Reform Act, 2 U.S.C. 1502
The Department, in promulgating this rule, has determined that this rule will not unduly burden the judicial system and meets the requirements of sections 3(a) and 3(b)(2) of Executive Order 12988.
In accordance with Executive Order 12630, this rule, authorized by the Migratory Bird Treaty Act, does not have significant takings implications and does not affect any constitutionally protected property rights. This rule will not result in the physical occupancy of property, the physical invasion of property, or the regulatory taking of any property. In fact, this rule will allow hunters to exercise otherwise unavailable privileges, and, therefore, reduces restrictions on the use of private and public property.
Due to the migratory nature of certain species of birds, the Federal Government has been given responsibility over these species by the Migratory Bird Treaty Act. We annually prescribe frameworks from which the States make selections and employ guidelines to establish special regulations on Federal Indian reservations and ceded lands. This process preserves the ability of the States and Tribes to determine which seasons meet their individual needs. Any State or Tribe may be more restrictive than the Federal frameworks at any time. The frameworks are developed in a cooperative process with the States and the Flyway Councils. This allows States to participate in the development of frameworks from which they will make selections, thereby having an influence on their own regulations. These rules do not have a substantial direct effect on fiscal capacity, change the roles or responsibilities of Federal or State governments, or intrude on State policy or administration. Therefore, in accordance with Executive Order 13132, these regulations do not have significant federalism effects and do not have sufficient federalism implications to warrant the preparation of a Federalism Assessment.
In accordance with the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951), Executive Order 13175, and 512 DM 2, we have evaluated possible effects on Federally recognized Indian tribes and have determined that there are no effects.
On May 18, 2001, the President issued Executive Order 13211 on regulations that significantly affect energy supply, distribution, and use. Executive Order 13211 requires agencies to prepare Statements of Energy Effects when undertaking certain actions. While this rule is a significant regulatory action under Executive Order 12866, it is not expected to adversely affect energy supplies, distribution, or use. Therefore, this action is not a significant energy action and no Statement of Energy Effects is required.
The rulemaking process for migratory game bird hunting must, by its nature, operate under severe time constraints. However, we intend that the public be given the greatest possible opportunity to comment on the regulations. Thus, when the preliminary proposed rulemaking was published, we established what we believed were the longest periods possible for public comment. In doing this, we recognized that when the comment period closed, time would be of the essence. That is, if there were a delay in the effective date of these regulations after this final rulemaking, the States would have insufficient time to implement their selected season dates and limits and start their seasons in a timely manner.
We therefore find that “good cause” exists, within the terms of 5 U.S.C. 553(d)(3) of the Administrative Procedure Act, and these regulations will, therefore, take effect immediately upon publication. Accordingly, with
Exports, Hunting, Imports, Reporting and recordkeeping requirements, Transportation, Wildlife.
16 U.S.C. 703-712 and 16 U.S.C. 742 a-j, Pub. L. 106-108.
Fish and Wildlife Service, Interior.
Final rule.
This rule prescribes special early season migratory bird hunting regulations for certain tribes on Federal Indian reservations, off-reservation trust lands, and ceded lands. This responds to tribal requests for U.S. Fish and Wildlife Service (hereinafter Service or we) recognition of their authority to regulate hunting under established guidelines. This rule allows the establishment of season bag limits and, thus, harvest at levels compatible with populations and habitat conditions.
This rule takes effect on September 1, 2002.
You may inspect comments received on the proposed special hunting regulations and tribal proposals during normal business hours in Room 634, Arlington Square Building, 4401 N. Fairfax Drive, Arlington, Virginia.
Tina Chouinard, Division of Migratory Bird Management, U.S. Fish and Wildlife Service (703/358-1714).
The Migratory Bird Treaty Act of July 3, 1918 (40 Stat. 755; 16 U.S.C. 703
In the July 29, 2002,
(1) On-reservation hunting by both tribal members and nonmembers, with hunting by non-tribal members on some reservations to take place within Federal frameworks but on dates different from those selected by the surrounding State(s);
(2) On-reservation hunting by tribal members only, outside of usual Federal frameworks for season dates and length, and for daily bag and possession limits; and
(3) Off-reservation hunting by tribal members on ceded lands, outside of usual framework dates and season length, with some added flexibility in daily bag and possession limits.
In all cases, the regulations established under the guidelines must be consistent with the March 10-September 1 closed season mandated by the 1916 Migratory Bird Treaty with Canada.
In the March 19, 2002,
(a) Harvest anticipated under the requested regulations;
(b) Methods that would be employed to measure or monitor harvest (such as bag checks, mail questionnaires, etc.);
(c) Steps that would be taken to limit level of harvest, where it could be shown that failure to limit such harvest would adversely impact the migratory bird resource; and
(d) Tribal capabilities to establish and enforce migratory bird hunting regulations.
No action is required if a tribe wishes to observe the hunting regulations established by the State(s) in which an Indian reservation is located. We have successfully used the guidelines since the 1985-86 hunting season. We finalized the guidelines beginning with the 1988-89 hunting season (August 18, 1988,
Although the proposed rule included generalized regulations for both early- and late-season hunting, this rulemaking addresses only the early-season proposals. Late-season hunting will be addressed in late-September. As a general rule, early seasons begin during September each year and have a primary emphasis on such species as mourning and white-winged dove. Late seasons begin about October 1 or later each year and have a primary emphasis on waterfowl.
The following paragraphs provide a brief summary of information on the status and harvest of waterfowl excerpted from various reports. For more detailed information on methodologies and results, complete copies of the various reports are available at the address indicated under the caption
Federal, provincial, and State agencies conduct surveys each spring to estimate the size of breeding populations and to evaluate the conditions of the habitats. These surveys are conducted using fixed-wing aircraft and encompass principal breeding areas of North America, and cover over 2.0 million square miles. The Traditional survey area is comprised of Alaska, Canada, and the northcentral United States, and includes approximately 1.3 million square miles. The Eastern survey area includes parts of Ontario, Quebec, Labrador, Newfoundland, Nova Scotia, Prince Edward Island, New Brunswick, New York, and Maine, an area of approximately 0.7 million square miles.
In summary, below-average winter and spring precipitation in the prairies and parklands and cold spring temperatures in eastern North America resulted in generally poorer habitat conditions for breeding waterfowl this year than in 2001. Dry conditions were reflected in the number of ponds counted this year. Total May ponds (United States prairies and Canadian prairies and parkland combined) were 2.7 ± 0.1 million, which is the second lowest count recorded since this estimate was first calculated in 1974, when this estimate was first recorded, 41% below last year's estimate of 4.6 ± 0.1 million, and 45% below the long-term average. This value was 41% below last year's estimate of 4.6 ± 0.1 million, and 45% below the long-term average (4.9 ± 0.1 million). May ponds in Canada (1.4 ± 0.1 million) and the U.S. (1.3 ± 0.1 million) were below 2001 estimates (−48% in Canada and −32% in the United States) and their long-term averages (−58% in Canada and −16% in the United States). Canadian ponds in May were the lowest recorded since surveys began in 1961.
In both the traditional (north-central United States, western Ontario, prairie Provinces and States, Yukon, Northwest Territories, and Alaska) and eastern survey areas (the northeastern United
The only region where habitat conditions for breeding waterfowl improved over last year was Alaska, due to warmer post-thaw temperatures than last year. However, rapid ice melt may have caused flooding of nests in parts of Alaska as well as Labrador.
Weather and habitat conditions during the summer months can influence waterfowl production. Good wetland conditions increase renesting and brood survival. During late May and early June, many parts of the prairies, including Montana, the western Dakotas, and southern Saskatchewan and Alberta received substantial precipitation. Though this late rain and snow may have encouraged good reproductive effort by late-nesting species such as gadwall, many of the earlier nesting ducks likely bypassed the prairies altogether. For those ducks that did nest, this late water should improve brood-rearing conditions, as brood and duckling survival tends to increase with higher wetland densities. Results of the July Production Survey indicate that the number of ponds in Prairie Canada and the north-central United States combined was 1.8 ± 0.1 million ponds. This was 36% below last year's estimate of 2.9 ± 0.1 million ponds, and 33% below the long-term average. July ponds in Prairie Canada were at 1.0 ± 0.1 million. This was 46% below last year's estimate of 1.8 ± 0.07 million and 43% below the long-term average. July ponds in the north-central United States were estimated at 0.84 ± 0.04 million. This was 19% below last year's estimate of 1.0 ± 0.06 million, but similar to the long-term average.
Breeding waterfowl habitat conditions in the eastern survey area were highly variable, but all areas experienced a warm, dry winter. In the New York, Eastern Ontario, and Southern Quebec survey area, the winter of 2001-02 was warm and dry, and drought conditions persisted throughout much of this region. Waterfowl returned early to this region, but early spring habitat conditions were poor. However, several weeks before and during surveys, cooler temperatures and increased precipitation were the rule, and wetland habitat conditions greatly improved. A similar weather pattern was reported for western Ontario. Maine and the southern Maritimes experienced a warm, dry winter, and above-normal temperatures and precipitation in early spring that produced good to excellent conditions for breeding ducks. By contrast, Newfoundland and Labrador experienced a late, cool spring. In Newfoundland, temperatures moderated and good waterfowl production was expected, but extended cold, stormy weather in Labrador made for poor nesting conditions.
In the traditional survey area, total duck abundance was 31.2 ± 0.5 million birds. This was 14% below last year's estimate of 36.1 ± 0.6 million birds, and 6% below the long-term (1955-2001) average. Mallard abundance was 7.5 ± 0.2 million, similar to the 2001 estimate of 7.9 ± 0.2 million, and essentially identical to the long-term average. Blue-winged teal abundance was 4.2 ± 0.2 million, which was 27% below last year's estimate of 5.8 ± 0.3 million, but similar to the long-term average. Gadwall (2.2 ± 0.1 million, −17%), shovelers (2.3 ± 0.1 million, −30%), and pintails (1.8 ± 0.1 million, −46%) were below 2001 estimates. Wigeon (2.3 ± 0.1 million), green-winged teal (2.3 ± 0.1 million), redheads (0.6 ± 0.1 million), canvasbacks (0.5 ± 0.1 million), and scaup (3.5 ± 0.2 million) were unchanged from 2001 estimates. Gadwall (+37%), green-winged teal (+28%), and shovelers (+10%) all remained above their long-term averages, whereas wigeon (−12%), pintail (−58%), canvasback (−14%), and scaup numbers (−34%) were below long-term averages. Northern pintails and scaup were the lowest and second lowest counts on record, respectively. The redhead estimate was similar to the long-term average.
In the eastern survey area, the 2002 total duck population estimate for this area was 4.4 ± 0.3 million birds, 32% higher than last year's (3.3 ± 0.3 million), and 41% higher than the 1996-2001 average. Numbers of most individual species were similar to those of last year, with the exception of mergansers (0.8 ± 0.1 million, +90%) and green-winged teal (0.7 ± 0.1 million, +174%), which increased compared to last year. Mergansers (+68%) and green-winged teal (+102%) were also above their 1996-2001 averages, as were scoters (0.3 ± 0.1 million, +178%). Estimates for all other species were similar to last year's estimates and to long-term averages.
The number of broods in the north-central United States and prairie Canada combined was 352,600, 35% lower than last year's estimate, and 25% below the long-term average. The number of broods in prairie Canada and the north-central United States were 54% and 37% below last year's estimates, respectively. Brood indices in prairie Canada were 69% below the long-term average, while brood counts were 12% above the long-term average in the north-central United States. The brood index in the Canadian boreal forest was 21% higher than last year's, but 16% below the long-term average. The late-nesting index, the number of pairs and lone drakes without broods seen during July surveys, was 9% higher than last year, but 43% lower than the long-term average, for all areas combined. The late-nesting index was down 12% and 33% relative to last year in boreal Canada and the north-central U.S., respectively, but up 32% in prairie Canada, perhaps reflecting late rains there. However, the late nesting index was below the long-term average by more than 60% in boreal Canada and the north-central United States, and by 24% in prairie Canada.
The size of the mid-continent mallard population, which comprises mallards from the traditional survey area, plus Michigan, Minnesota, and Wisconsin, was 8.5 million birds. This is similar to that of 2001 (8.7 million). The 2002 mid-continent mallard fall-flight
For further discussion on the implications of this information for this year's selection of the appropriate hunting regulations in the United States, see the August 16, 2002,
We annually assess the population status and productivity of 30 populations of North American Canada geese (
For the 2002-03 migratory bird hunting season, we proposed regulations for 29 tribes and/or Indian groups that followed the 1985 guidelines and were considered appropriate for final rulemaking. Some of the proposals submitted by the tribes had both early- and late-season elements. However, as noted earlier, only those with early-season proposals are included in this final rulemaking; 19 tribes have proposals with early seasons and 1 tribe has decided not to have a special migratory bird hunting season. Comments and revised proposals received to date are addressed in the following section. The comment period for the proposed rule, published on July 29, 2002, closed on August 8, 2002. Because of the necessary brief comment period, we will respond to any comments received on the proposed rule and/or these late-season regulations not responded to herein in the September late-season final rule.
We received one comment regarding the notice of intent published on March 19, 2002, which announced rulemaking on regulations for migratory bird hunting by American Indian tribal members. The Michigan Department of Natural Resources commented on the establishment of tribal regulations on 1836 Treaty areas. Michigan believed it was premature of the Service to establish waterfowl regulations in areas covered by the 1836 Treaty until such time as the issue of 1836 Treaty hunting rights are affirmed by a court of competent jurisdiction.
Pursuant to the requirements of section 102(2)(C) of the National Environmental Policy Act of 1969 (42 U.S.C. 4332(C)), the “Final Environmental Statement for the Issuance of Annual Regulations Permitting the Sport Hunting of Migratory Birds (FES-75-74)” was filed with the Council on Environmental Quality on June 6, 1975, and notice of availability was published in the
Section 7 of the Endangered Species Act, as amended (16 U.S.C. 1531-1543; 87 Stat. 884), provides that, “The Secretary shall review other programs administered by him and utilize such programs in furtherance of the purposes of this Act” (and) shall “insure that any action authorized, funded or carried out * * * is not likely to jeopardize the continued existence of any endangered species or threatened species or result in the destruction or adverse modification of [critical] habitat * * *” Consequently, we conducted consultations to ensure that actions resulting from these regulations would not likely jeopardize the continued existence of endangered or threatened species or result in the destruction or adverse modification of their critical habitat. Findings from these consultations are included in a biological opinion and may have caused modification of some regulatory measures previously proposed. The final frameworks reflect any modifications. Our biological opinions resulting from its Section 7 consultation are public documents available for public inspection in the Service's Division of Endangered Species and MBM, at the address indicated under the caption
These regulations have a significant economic impact on substantial numbers of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
Collectively, the rules covering the overall frameworks for migratory bird hunting are economically significant and have been reviewed by the Office of Management and Budget (OMB) under Executive Order 12866. This rule is a small portion of the overall migratory bird hunting frameworks and was not individually submitted and reviewed by OMB under Executive Order 12866.
On May 18, 2001, the President issued Executive Order 13211 on regulations that significantly affect energy supply, distribution, and use. Executive Order 13211 requires agencies to prepare Statements of Energy Effects when undertaking certain actions. While this rule is a significant regulatory action under Executive Order 12866, it is not expected to adversely affect energy supplies, distribution, or use. Therefore, this action is not a significant energy action and no Statement of Energy Effects is required.
This rule is a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. For the reasons outlined above, this rule has an annual effect on the economy of $100 million or more. However, because this rule establishes hunting seasons, we do not plan to defer the effective date under the exemption contained in 5 U.S.C. 808 (1) and this rule will be effective immediately.
We examined these regulations under the Paperwork Reduction Act of 1995. We utilize the various recordkeeping and reporting requirements imposed under regulations established in 50 CFR part 20, subpart K, in the formulation of migratory game bird hunting regulations. Specifically, OMB has approved the information collection requirements of the Migratory Bird Harvest Information Program and assigned clearance number 1018-0015 (expires 10/31/2004). This information is used to provide a sampling frame for voluntary national surveys to improve our harvest estimates for all migratory game birds in order to better manage these populations. OMB has also approved the information collection requirements of the Sandhill Crane Harvest Questionnaire and assigned control number 1018-0023 (expires 07/31/2003). The information from this survey is used to estimate the magnitude and the geographical and temporal distribution of harvest, and the portion it constitutes of the total population. A Federal agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
We have determined and certify, in compliance with the requirements of the Unfunded Mandates Reform Act, 2 U.S.C. 1502
The Department, in promulgating this proposed rule, has determined that this rule will not unduly burden the judicial system and meets the requirements of sections 3(a) and 3(b)(2) of Executice Order 12988.
In accordance with Executive Order 12630, these rules, authorized by the Migratory Bird Treaty Act, do not have significant takings implications and do not affect any constitutionally protected property rights. These rules will not result in the physical occupancy of property, the physical invasion of property, or the regulatory taking of any property. In fact, these rules allow hunters to exercise privileges that would be otherwise unavailable; and, therefore, reduce restrictions on the use of private and public property.
Due to the migratory nature of certain species of birds, the Federal government has been given responsibility over these species by the Migratory Bird Treaty Act. We annually prescribe frameworks from which the States make selections and employ guidelines to establish special regulations on Federal Indian reservations and ceded lands. This process preserves the ability of the States and Tribes to determine which seasons meet their individual needs. Any State or Tribe may be more restrictive than the Federal frameworks at any time. The frameworks are developed in a cooperative process with the States and the Flyway Councils. This allows States to participate in the development of frameworks from which they will make selections, thereby having an influence on their own regulations. These rules do not have a substantial direct effect on fiscal capacity, change the roles or responsibilities of Federal or State governments, or intrude on State policy or administration. Therefore, in accordance with Executive Order 13132, these regulations do not have significant federalism effects and do not have sufficient federalism implications to warrant the preparation of a Federalism Assessment.
Due to the migratory nature of certain species of birds, the Federal government has been given responsibility over these species by the Migratory Bird Treaty Act. Thus, in accordance with the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951) Executive Order 13175 and 512 DM 2, we have evaluated possible effects on Federally recognized Indian tribes and have determined that there are no effects on Indian trust resources. However, by virtue of the tribal proposals received in response to the April 30, 2001, request for proposals and the August 14, 2001, proposed rule, we have consulted with all the tribes affected by this rule.
The rulemaking process for migratory game bird hunting must, by its nature, operate under severe time constraints. However, we intend that the public be given the greatest possible opportunity to comment on the regulations. Thus, when the preliminary proposed rulemaking was published, we established what we believed were the longest periods possible for public comment. In doing this, we recognized that when the comment period closed, time would be of the essence. That is, if there were a delay in the effective date of these regulations after this final rulemaking, the tribes would have
We, therefore, find that “good cause” exists, within the terms of 5 U.S.C. 553(d)(3) of the Administrative Procedure Act, and these regulations will take effect immediately upon publication.
Therefore, under the authority of the Migratory Bird Treaty Act of July 3, 1918, as amended (40 Stat. 755; 16 U.S.C. 703
Exports, Hunting, Imports, Reporting and recordkeeping requirements, Transportation, Wildlife.
16 U.S.C. 703-712 and 16 U.S.C. 742 a-j, Pub L. 106-108.
All seasons in Minnesota, 1854 Treaty Zone:
1. While hunting waterfowl, a tribal member must carry on his/her person a valid tribal waterfowl hunting permit.
2. Except as otherwise noted, tribal members will be required to comply with tribal codes that will be no less restrictive than the provisions of Chapter 10 of the Model Off-Reservation Code. Except as modified by the Service rules adopted in response to this proposal, these amended regulations parallel Federal requirements in 50 CFR part 20 as to hunting methods, transportation, sale, exportation, and other conditions generally applicable to migratory bird hunting.
3. Band members in each zone will comply with State regulations providing for closed and restricted waterfowl hunting areas.
4. There are no possession limits on any species, unless otherwise noted above. For purposes of enforcing bag and possession limits, all migratory birds in the possession or custody of band members on ceded lands will be considered to have been taken on those lands unless tagged by a tribal or State conservation warden as having been taken on-reservation. All migratory birds that fall on reservation lands will not count as part of any off-reservation bag or possession limit.
All seasons in Michigan, 1836 Treaty Zone:
A. Wisconsin and Minnesota 1837 and 1842 Zones:
B. Michigan 1836 and 1842 Treaty Zones:
Other Migratory Birds: All Ceded Areas except where noted below.
1. While hunting waterfowl, a tribal member must carry on his/her person a valid tribal waterfowl hunting permit.
2. Except as otherwise noted, tribal members will be required to comply with tribal codes that will be no less restrictive than the model ceded territory conservation codes approved by Federal courts in the Lac Courte Oreilles v. State of Wisconsin (Voigt) and Mille Lacs Band v. State of Minnesota cases. The respective Chapter 10 of these Model Codes regulate territory migratory bird hunting. Except as modified by the Service rules adopted in response to this proposal, these amended regulations parallel Federal requirements in 50 CFR part 20 as to hunting methods, transportation, sale, exportation, and other conditions generally applicable to migratory bird hunting.
3. Particular regulations of note include:
A. Nontoxic shot will be required for all waterfowl hunting.
B. Tribal members in each zone will comply with tribal regulations providing for closed and restricted waterfowl hunting areas. These regulations generally incorporate the same restrictions contained in parallel State regulations.
C. Possession limits for each species are double the daily bag limit, except on the opening day of the season, when the possession limit equals the daily bag limit, unless otherwise noted above. Possession limits are applicable only to transportation and do not include birds that are cleaned, dressed, and at a member's primary residence. For purposes of enforcing bag and possession limits, all migratory birds in the possession or custody of tribal members on ceded lands will be considered to have been taken on those lands unless tagged by a tribal or State conservation warden as having been taken on-reservation. All migratory birds that fall on reservation lands will not count as part of any off-reservation bag or possession limit.
D. The Tribe proposes that the baiting restrictions included in the respective sections 10.05(2)(h) of the model ceded territory conservation codes be amended to include language which parallels that in place for non-tribal members as published in 64 FR 29804, June 3, 1999.
E. They also propose to remove the shell limit restrictions included in the respective sections 10.05(2)(b) of the model ceded territory conservation codes.
5. Michigan—Duck Blinds and Decoys. Tribal members hunting in Michigan will comply with tribal codes that contain provisions that parallel applicable Michigan laws concerning duck blinds and/or decoys.
A. All tribal members will be required to obtain a valid tribal resource card and 2002-03 hunting license.
B. Except as modified by the Service rules adopted in response to this proposal, these amended regulations parallel all Federal regulations contained in 50 CFR part 20.
C. Particular regulations of note include:
(1) Nontoxic shot will be required for all waterfowl hunting by tribal members.
(2) Tribal members in each zone will comply with tribal regulations providing for closed and restricted waterfowl hunting areas. These regulations generally incorporate the same restrictions contained in parallel State regulations.
(3) Possession limits for each species are double the daily bag limit, except on the opening day of the season, when the possession limit equals the daily bag limit, unless otherwise noted above.
D. Tribal members hunting in Michigan will comply with tribal codes that contain provisions parallel to Michigan law regarding duck blinds and decoys.
All other Federal regulations contained in 50 CFR part 20 would apply. The following restrictions are also proposed by the Tribe: (1) As per Makah Ordinance 44, only shotguns may be used to hunt any species of waterfowl. Additionally, shotguns must not be discharged within 0.25 miles of an occupied area; (2) Hunters must be eligible, enrolled Makah tribal members and must carry their Indian Treaty Fishing and Hunting Identification Card while hunting. No tags or permits are required to hunt waterfowl; (3) The Cape Flattery area is open to waterfowl hunting, except in designated wilderness areas, or within one mile of Cape Flattery Trail, or in any area that is closed to hunting by another ordinance or regulation; (4) The use of live decoys and/or baiting to pursue any species of waterfowl is prohibited; (5) Steel or bismuth shot only for waterfowl is allowed; the use of lead shot is prohibited; (6) The use of dogs is permitted to hunt waterfowl.
Tribal members must have the tribal identification and harvest report card on their person to hunt. Tribal members hunting on the Reservation will observe all basic Federal migratory bird hunting regulations found in 50 CFR.
Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Proposed rule.
The Civilian Agency Acquisition Council and the Defense Acquisition Regulations Council (Councils) are proposing to amend the Federal Acquisition Regulation (FAR) to implement Executive Order 13148 of April 21, 2000, Greening the Government through Leadership in Environmental Management.
Interested parties should submit comments in writing on or before October 28, 2002 to be considered in the formulation of a final rule.
Submit written comments to: General Services Administration, FAR Secretariat (MVA), 1800 F Street, NW., Room 4035, ATTN: Laurie Duarte, Washington, DC 20405.
Submit electronic comments via the Internet to:
The FAR Secretariat, Room 4035, GS Building, Washington, DC, 20405, at (202) 501-4755 for information pertaining to status or publication schedules. For clarification of content, contact Laura Smith, Procurement Analyst, at (202) 501-7279. Please cite FAR case 2000-005.
On April 21, 2000, the President signed Executive Order (E.O.) 13148, Greening the Government Through Leadership in Environmental Management. The E.O.—
1. Provides requirements and goals for agencies related to—
a. Environmental management and compliance;
b. Right-to-know and pollution prevention;
c. Release reduction of toxic chemicals;
d. Use reduction of toxic chemicals, hazardous substances, and other pollutants; and
e. Reduction in ozone-depleting substances;
2. Revokes E.O.s 12843 of April 21, 1993, Procurement Requirements and Policies for Federal Agencies for Ozone-Depleting Substances; 12856 of August 3, 1993, Federal Compliance with Right-To-Know Laws and Pollution Prevention Requirements; and 12969 of August 8, 1995, Federal Acquisition and Community Right-To-Know;
3. Requires agencies to continue to follow the policies and procedures in FAR Subparts 23.8, Ozone-Depleting Substances; 23.9, Toxic Chemical Release Reporting; and 23.10 Federal Compliance with Right-To-Know Laws and Pollution Prevention Requirements, that were in effect as of the date of E.O. 13148; and
4. Requires agencies to implement environmental management systems (EMSs) and conduct facility compliance audits (FCAs) at certain Federal facilities.
This proposed rule amends the FAR to implement E.O. 13148 by—
1. Removing references to E.O.s 12843, 12856, and 12969;
2. Replacing references for the revoked E.O.s with that of E.O. 13148;
3. Adding the requirement at FAR 52.223-5, Pollution Prevention and Right-To-Know Information, for contractors to provide information necessary so that agencies can implement EMSs and complete FCAs at certain Federal facilities; and
4. Making editorial changes.
North American Industry Classification System (NAICS) codes will replace Standard Industrial Classification (SIC) codes in FAR Subpart 23.9 and FAR 52.223-13 and 52.223-14 once the NAICS conversion for the Toxics Release Inventory program is complete.
This is not a significant regulatory action and, therefore, was not subject to review under Section 6(b) of Executive Order 12866, Regulatory Planning and Review, dated September 30, 1993. This rule is not a major rule under 5 U.S.C. 804.
The Councils do not expect this proposed rule to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
An Initial Regulatory Flexibility Analysis has, therefore, not been performed. We invite comments from small businesses and other interested parties. The Councils will consider comments from small entities concerning the affected FAR Parts 23 and 52 in accordance with 5 U.S.C. 610. Interested parties must submit such comments separately and should cite 5 U.S.C. 601,
The Paperwork Reduction Act (Pub. L. 104-13) applies because the proposed rule contains information collection requirements. The proposed changes to the FAR will increase the information collection requirement currently approved under Office of Management and Budget control number 9000-0147, since the rule requires contractors to provide information needed by a Federal facility to implement an EMS (Alternate I of 52.223-5) and to complete a FCA (Alternate II of 52.223-5). Accordingly, the FAR Secretariat has submitted a request for approval of a revised information collection requirement concerning leadership in environmental management as it relates to E.O. 13148 to the Office of Management and Budget under 44 U.S.C. 3501,
The annual reporting burden is estimated as follows:
Submit comments, including suggestions for reducing this burden, not later than October 28, 2002 to: FAR Desk Officer, OMB, Room 10102, NEOB, Washington, DC 20503, and a copy to the General Services Administration, FAR Secretariat (MVA), 1800 F Street, NW., Room 4035, Washington, DC 20405.
Public comments are particularly invited on: whether this collection of information is necessary for the proper performance of functions of the FAR, and will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of appropriate technological collection techniques or other forms of information technology.
Requester may obtain a copy of the justification from the General Services Administration, FAR Secretariat (MVA), Room 4035, Washington, DC 20405, telephone (202) 208-7312. Please cite OMB Control Number 9000-0147, Leadership in Environmental Management (E.O. 13148), in all correspondence.
Government procurement.
Therefore, DoD, GSA, and NASA propose amending 48 CFR parts 23 and 52 as set forth below:
1. The authority citation for 48 CFR parts 23 and 52 continues to read as follows:
40 U.S.C. 486(c); 10 U.S.C. chapter 137; and 42 U.S.C. 2473(c).
2. Add section 23.001 to read as follows:
3. Amend section 23.702 by revising paragraph (d) to read as follows:
(d) Executive Order 13148 of April 21, 2000, Greening the Government through Leadership in Environmental Management.
4. Amend section 23.801 by revising paragraph (b) to read as follows:
(b) Executive Order 13148 of April 21, 2000, Greening the Government through Leadership in Environmental Management.
5. Amend section 23.803 by revising the introductory text of paragraph (b); and in paragraph (b)(1) by removing “12843” and adding “13148” in its place.
(b) In preparing specifications and purchase descriptions, and in the acquisition of supplies and services, agencies shall—
6. Amend Subpart 23.9 as follows:
a. Revise the Subpart heading;
b. Revise section 23.901;
c. In section 23.902, add a sentence to the end of paragraph (b);
d. In section 23.903, amend paragraph (a) by removing “(including all options)” and revise paragraph (b)(2);
e. Remove section 23.904 and redesignate sections 23.905, 23.906, and 23.907 as 23.904, 23.905, and 23.906, respectively;
f. In the newly designated section 23.905 revise paragraphs (a) introductory text, (a)(2)(iv), and (a)(2)(v), and amend paragraph (d) by removing “12969” and adding “13148” in its place; and
g. In the newly designated section 23.906 revise paragraph (a), and amend paragraph (b) by removing “(including all options)”.
The revised and added text reads as follows:
This subpart implements the requirements of Executive Order (E.O.) 13148 of April 21, 2000, Greening the Government through Leadership in Environmental Management.
(b) * * *
(b) * * *
(2) Contractor facilities located outside the United States, Puerto Rico, Guam, American Samoa, the United States Virgin Islands, the Northern Mariana Islands, and any other territory or possession over which the United States has jurisdiction.
(a) E.O. 13148 requires that solicitations for competitive contracts expected to exceed $100,000 include, to the maximum extent practicable, as an award eligibility criterion, a certification by an offeror that, if awarded a contract, either—
(2) * * *
(iv) Do not fall within the following Standard Industrial Classification (SIC) codes or their corresponding North American Industry Classification System sectors:
(A) Major group code 10 (except 1011, 1081, and 1094.
(B) Major group code 12 (except 1241).
(C) Major group codes 20 through 39 or their corresponding North American Industry Classification System (NAICS) sectors 31 through 33.
(D) Industry codes 4911, 4931, or 4939 (limited to facilities that combust coal and/or oil for generating power).
(E) Industry codes 4953 (limited to facilities regulated under the Resource Conservation and Recovery Act (42 U.S.C. 6921,
(v) Are not located within the United States, Puerto Rico, Guam, American Samoa, the United States Virgin Islands, the Northern Mariana Islands, or any other territory or possession over which the United States has jurisdiction.
(a) Insert the provision at 52.223-13, Certification of Toxic Chemical Release Reporting, in all solicitations for competitive contracts expected to exceed $100,000 and competitive 8(a) contracts, unless it has been determined in accordance with 23.905(b) that to do so is not practicable; and
7. Revise subpart 23.10, consisting of sections 23.1000 through 23.1005, to read as follows:
This subpart prescribes policies and procedures for obtaining information needed for Government—
(a) Compliance with right-to-know laws and pollution prevention requirements;
(b) Implementation of an environmental management system (EMS) at a Federal facility; and
(c) Completion of facility compliance audits (FCAs) at a Federal facility.
(a) Emergency Planning and Community Right-to-Know Act of 1986, 42 U.S.C. 11001-11050 (EPCRA).
(b) Pollution Prevention Act of 1990, 42 U.S.C. 13101-13109 (PPA).
(c) Executive Order 13148 of April 21, 2000, Greening the Government through Leadership in Environmental Management.
The requirements of this subpart apply to facilities owned or operated by a Federal agency except those facilities located outside the United States, Puerto Rico, Guam, American Samoa, the United States Virgin Islands, the Northern Mariana Islands, and any other territory or possession over which the United States has jurisdiction.
As used in this subpart—
(a) E.O. 13148 requires Federal facilities to comply with the provisions of (EPCRA) and (PPA).
(b) Pursuant to E.O. 13148 and any agency implementing procedures, every new contract that provides for performance on a Federal facility shall require the contractor to provide information necessary for the Federal agency to comply with the—
(1) Emergency planning and toxic release reporting requirements in EPCRA, PPA, and E.O. 13148;
(2) Toxic chemical, priority chemical, and hazardous substance release and use reduction goals of Sections 502 and 503 of Executive Order 13148; and
(3) Requirements for EMSs and FCAs if the place of performance is at a Federal facility designated by the agency.
(a) Insert the clause at 52.223-5, Pollution Prevention and Right-to-Know Information, in solicitations and contracts that provide for performance, in whole or in part, on a Federal facility.
(b) Use the clause with its Alternate I if the contract provides for contractor—
(1) Operation or maintenance of a Federal facility at which the agency has implemented an EMS; or
(2) Activities and operations—
(i) To be performed at a Government-operated Federal facility that has implemented an EMS; and
(ii) That the agency has determined are covered within the EMS.
(c) Use the clause with its Alternate II if—
(1) The contract provides for contractors to conduct activities on a Federal facility; and
(2) The agency has determined that the contractor activities should be included within the FCA.
8. Section 52.213-4 is amended by revising the date of the clause and paragraph (b)(1)(vii) to read as follows:
(b) * * *
(1) * * *
(vii) 52.223-5, Pollution Prevention and Right-to-Know Information (DATE)(E.O. 13148). (Applies to services performed on Federal facilities.)
9. Revise section 52.223-5 to read as follows:
As prescribed in 23.1005, insert the following clause:
(a)
(b) Executive Order 13148 requires Federal facilities to comply with the provisions of the Emergency Planning and Community Right-to-Know Act of 1986 (EPCRA)(42 U.S.C. 11001-11050) and the Pollution Prevention Act of 1990 (PPA)(42 U.S.C. 13101-13109).
(c) The Contractor, upon request of the Government, shall provide all information needed by the Federal facility to comply with the following:
(1) The emergency planning reporting requirements of Section 302 of EPCRA.
(2) The emergency notice requirements of Section 304 of EPCRA.
(3) The list of Material Safety Data Sheets, required by Section 311 of EPCRA.
(4) The emergency and hazardous chemical inventory forms of Section 312 of EPCRA.
(5) The toxic chemical release inventory of Section 313 of EPCRA, which includes the reduction and recycling information required by Section 6607 of PPA.
(6) The toxic chemical, priority chemical, and hazardous substance release and use reduction goals of Sections 502 and 503 of Executive Order 13148.
(c)(7) The environmental management system as described in Section 401 of E.O. 13148.
(c)(7) The facility compliance audits as described in Section 402 of E.O. 13148.
10. Amend section 52.223-13 by revising the introductory text, the date of the provision, and paragraphs (a),
As prescribed in 23.906(a), insert the following provision:
(a) Executive Order 13148, of April 21, 2000, Greening the Government through Leadership in Environmental Management, requires submission of this certification as a prerequisite for contract award.
(b) * * *
(2) * * *
[ ] (i) The facility does not manufacture, process, or otherwise use any toxic chemicals listed in 40 CFR 372.65;
[ ] (iv) The facility does not fall within the following Standard Industrial Classification (SIC) codes or their corresponding North American Industry Classification System sectors:
(1) Major group code 10 (except 1011, 1081, and 1094.
(2) Major group code 12 (except 1241).
(3) Major group codes 20 through 39 or their corresponding North American Industry Classification System (NAICS) sectors 31 through 33.
(4) Industry codes 4911, 4931, or 4939 (limited to facilities that combust coal and/or oil for generating power).
(5) Industry codes 4953 (limited to facilities regulated under the Resource Conservation and Recovery Act (42 U.S.C. 6921,
[ ] (v) The facility is not located within the United States, Puerto Rico, Guam, American Samoa, the United States Virgin Islands, the Northern Mariana Islands, or any other territory or possession over which the United States has jurisdiction.
(End of provision)
11. Amend section 52.223-14 by revising the introductory text, the date of the clause, and paragraphs (b)(1), (b)(4), and (b)(5) to read as follows:
As prescribed in 23.906(b), insert the following clause:
(b) * * *
(1) The facility does not manufacture, process, or otherwise use any toxic chemicals listed in 40 CFR 372.65;
(4) The facility does not fall within the following Standard Industrial Classification (SIC) codes or their corresponding North American Industry Classification System sectors:
(i) Major group code 10 (except 1011, 1081, and 1094).
(ii) Major group code 12 (except 1241).
(iii) Major group codes 20 through 39 or their corresponding North American Industry Classification System sectors 31 through 33.
(iv) Industry codes 4911, 4931, or 4939 (limited to facilities that combust coal and/or oil for generating power).
(v) Industry codes 4953 (limited to facilities regulated under the Resource Conservation and Recovery Act (42 U.S.C. 6921,
(5) The facility is not located within the United States, Puerto Rico, Guam, American Samoa, the United States Virgin Islands, the Northern Mariana Islands, or any other territory or possession over which the United States has jurisdiction.
Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Proposed rule.
The Civilian Agency Acquisition Council and the Defense Acquisition Regulations Council (Councils) are proposing to amend the Federal Acquisition Regulation (FAR) to require the contractor to notify the contracting officer if the Government overpays the contractor when making an invoice payment or a contract financing payment under both commercial item and non-commercial item contracts.
Interested parties should submit comments in writing on or before October 28, 2002 to be considered in the formulation of a final rule.
Submit written comments to: General Services Administration, FAR Secretariat (MVA), 1800 F Street, NW., Room 4035, ATTN: Laurie Duarte, Washington, DC 20405. Submit electronic comments via the Internet to:
The FAR Secretariat, Room 4035, GS Building, Washington, DC, 20405, at (202) 501-4755 for information pertaining to status or publication schedules. For clarification of content, contact Mr. Jeremy Olson, at (202) 501-3221. Please cite FAR case 2001-005.
In July 1999, the General Accounting Office (GAO) published a report (GAO/NSIAD-99-131) entitled Greater Attention Needed to Identify and Recover Overpayments. After examining the process for identifying and collecting overpayments, GAO concluded in their report that “Under current law, there is no requirement for contractors who have been overpaid to notify the Government of overpayments or to return overpayments prior to the Government issuing a demand letter” (
DoD, GSA, and NASA published a proposed FAR rule 1999-023, in the
One of the respondents that submitted public comments in response to the proposed rule recommended that overpayments on financing payments should be provided similar treatment as overpayments on invoice payments,
This is not a significant regulatory action and, therefore, was not subject to review under Section 6(b) of Executive Order 12866, Regulatory Planning and Review, dated September 30, 1993. This rule is not a major rule under 5 U.S.C. 804.
The Councils do not expect this proposed rule to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
The Paperwork Reduction Act (Pub. L. 104-13) applies because the proposed rule contains information collection requirements. The rule requires the contractor to notify the contracting officer if the contractor becomes aware that the Government has overpaid on a financing payment under a contract for noncommercial items, and on financing and invoice payments under a contract for commercial items. Although this estimated burden requires approval under the Act, it is so small that it does not impact the estimated total burden under OMB Control Number 9000-0070.
The annual reporting burden is estimated as follows:
Submit comments, including suggestions for reducing this burden, not later than October 28, 2002 to: FAR Desk Officer, OMB, Room 10102, NEOB, Washington, DC 20503, and a copy to the General Services Administration, FAR Secretariat (MVA), 1800 F Street, NW, Room 4035, Washington, DC 20405.
Public comments are particularly invited on: whether this collection of information is necessary for the proper performance of functions of the FAR, and will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected; and ways in which we can minimize the burden of the collection of information on those who are to respond, through the use of
Requester may obtain a copy of the justification from the General Services Administration, FAR Secretariat (MVA), Room 4035, Washington, DC 20405, telephone (202) 501-4755. Please cite OMB Control Number 9000-0070, FAR Case 2001-005, Notification of Overpayment, Contract Financing Payments, in all correspondence.
Government procurement.
Therefore, DoD, GSA, and NASA propose amending 48 CFR parts 12, 32, and 52 as set forth below:
1. The authority citation for 48 CFR parts 12, 32, and 52 continues to read as follows:
40 U.S.C. 486(c); 10 U.S.C. chapter 137; and 42 U.S.C. 2473(c).
2. Add section 12.215 to read as follows:
If the Contractor notifies the contracting officer of a duplicate contract financing or invoice payment or that the Government has otherwise overpaid on a contract financing or invoice payment, the contracting officer must provide instructions to the contractor, in coordination with the cognizant payment office, regarding disposition of the overpayment.
3. Add section 32.008 to read as follows:
If the Contractor notifies the contracting officer of a duplicate contract financing or invoice payment or that the Government has otherwise overpaid on a contract financing or invoice payment, the contracting officer must provide instructions to the contractor, in coordination with the cognizant payment office, regarding disposition of the overpayment.
4. Amend section 52.212-4 by revising the date of the clause and paragraph (i) to read as follows:
(i)
(2)
(3)
(4)
(5)
5. Amend section 52.213-4 by revising the date of the clause and paragraph (a)(2)(iv) to read as follows:
(a) * * *
(2) * * *
(iv) 52.232-25, Prompt Payment (Date).
6. Amend section 52.232-25 by revising the date of the clause and paragraph (d) to read as follows:
(d)
7. Amend section 52.232-26 by revising the date of the clause and paragraph (c) to read as follows:
(c)
8. Amend section 52.232-27 by revising the date of the clause and paragraph (l) to read as follows:
(l)
Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Proposed rule.
The Civilian Agency Acquisition Council and the Defense Acquisition Regulations Council (Councils) are proposing to amend the Federal Acquisition Regulation (FAR) to remove the prohibition on evaluating Federal Prison Industries (FPI) contract performance.
Interested parties should submit comments in writing on or before October 28, 2002 to be considered in the formulation of a final rule.
Submit written comments to—General Services Administration, FAR Secretariat (MVA), 1800 F Street, NW., Room 4035, ATTN: Laurie Duarte, Washington, DC 20405.
Submit electronic comments via the Internet to—
Please submit comments only and cite FAR case 2001-035 in all correspondence related to this case.
The FAR Secretariat, Room 4035, GS Building, Washington, DC, 20405, at (202) 501-4755 for information pertaining to status or publication schedules. For clarification of content, contact Laura Smith, Procurement Analyst, at (202) 208-7279. Please cite FAR case 2001-035.
This proposed rule amends FAR Subparts 8.6 and 42.15 to remove the prohibition on evaluating Federal Prison Industries (FPI) contract performance. Past performance information is collected for use in future source selections regarding a contractor's actions under previously awarded contracts. This change will permit Federal customers to rate FPI performance, compare FPI to private sector providers, and give FPI important feedback on previously awarded contracts. It is expected that this change will give FPI the same opportunity that we give private sector providers, to improve their customer satisfaction, in general, and their performance on delivery, prices, and quality, specifically.
This is not a significant regulatory action and, therefore, was not subject to review under Section 6(b) of Executive Order 12866, Regulatory Planning and Review, dated September 30, 1993. This rule is not a major rule under 5 U.S.C. 804.
The Councils do not expect this proposed rule to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
The Paperwork Reduction Act does not apply because the proposed changes to the FAR do not impose information collection requirements that require the approval of the Office of Management and Budget under 44 U.S.C. 3501,
Government procurement.
Therefore, DoD, GSA, and NASA propose amending 48 CFR parts 8 and 42 as set forth below:
1. The authority citation for 48 CFR parts 8 and 42 continues to read as follows:
40 U.S.C. 486(c); 10 U.S.C. chapter 137; and 42 U.S.C. 2473(c).
2. Add section 8.607 to read as follows:
Agencies shall evaluate FPI contract performance in accordance with subpart 42.15.
3. Amend section 42.1502 in paragraph (b) by removing “Subparts 8.6 and” and adding “subpart” in its place.
Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Proposed rule.
The Civilian Agency Acquisition Council and the Defense Acquisition Regulations Council (Councils) are proposing to amend the Federal Acquisition Regulation (FAR) to revise the “selling costs” cost principle to increase clarity and to remove excessive wording and details.
Interested parties should submit comments in writing on or before October 28, 2002 to be considered in the formulation of a final rule.
Submit written comments to—General Services Administration, FAR Secretariat (MVA), 1800 F Street, NW., Room 4035, ATTN: Laurie Duarte, Washington, DC 20405.
Submit electronic comments via the Internet to:
The FAR Secretariat, Room 4035, GS Building, Washington, DC, 20405, at (202) 501-4755 for information pertaining to status or publication schedules. For clarification of content, contact Mr. Jeremy Olson, at (202) 501-3221. Please cite FAR case 2001-024.
The proposed rule revises FAR 31.205-38, Selling costs, to increase clarity and to remove excessive wording and details. Among the changes are the following:
1. In a revised FAR 31.205-38(b), combining the list of selling activities from existing FAR 31.205-38(a) with the more detailed guidance about the allowability of these costs in existing FAR 31.205-38(b) and (c)(1).
2. Eliminating references to reasonableness currently found in FAR 31.205-38(b) and (c)(1) because this general allowability standard is already addressed at FAR 31.201-2, Determining allowability, and FAR 31.201-3, Determining reasonableness.
3. Removing as unnecessary existing FAR 31.205-38(c)(2) and the cross-reference in existing FAR 31.205-38(b) to FAR 31.205-14, Entertainment costs. The Councils believe there is no longer a reason to distinguish between the allowability of foreign and domestic selling costs involving direct selling and other market planning efforts. This would eliminate the current requirement that in order to be allowable, these export sales costs must be related to products normally sold to the U.S. Government. However, the public policy reasons for distinguishing between foreign and domestic broadly targeted sales efforts are still valid. The allowability of these costs is adequately covered at FAR 31.205-1 and does not need to be restated in FAR 31.205-38.
4. Removing existing FAR 31.205-38(e) as it is duplicative of the guidance at FAR 31.201-6, Accounting for unallowable costs, and paragraph (c) of FAR 31.204, Application of principles and procedures.
5. Making related editorial changes.
This is not a significant regulatory action and, therefore, was not subject to review under Section 6(b) of Executive Order 12866, Regulatory Planning and Review, dated September 30, 1993. This rule is not a major rule under 5 U.S.C. 804.
The Councils do not expect this proposed rule to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
The Paperwork Reduction Act does not apply because the proposed changes to the FAR do not impose information collection requirements that require the approval of the Office of Management and Budget under 44 U.S.C. 3501,
Government procurement.
Therefore, DoD, GSA, and NASA propose amending 48 CFR part 31 as set forth below:
1. The authority citation for 48 CFR part 31 continues to read as follows:
40 U.S.C. 486(c); 10 U.S.C. chapter 137; and 42 U.S.C. 2473(c).
2. Amend section 31.205-1 in paragraph (f)(1) by removing from the parenthetical “31.205-38(c)” and adding “31.205-38(b)(5)” in its place.
3. Amend section 31.205-12 in paragraph (a) by removing the word “generalized” and adding “general” in its place.
4. Amend section 31.205-33 by revising the first sentence of the introductory text of paragraph (f); and removing the parenthetical sentence. The revised text reads as follows:
(f) Fees for services rendered are allowable only when supported by evidence of the nature and scope of the service furnished (see also 31.205-38(c)). * * *
5. Revise section 31.205-38 to read as follows:
(a) “Selling” is a generic term encompassing all efforts to market the contractor's products or services, some of which are covered specifically in other subsections of 31.205. The costs of any selling efforts other than those addressed in this cost principle are unallowable. Costs of activities that are correctly classified and disallowed under cost principles referenced in paragraph (b) are not to be reconsidered for reimbursement under any other provision of this subsection.
(b) Selling includes the following broad categories:
(1)
(2)
(3)
(4)
(5)
(c) Notwithstanding any other provision of this subsection, sellers' or agents' compensation, fees, commissions, percentages, retainer or brokerage fees, whether or not contingent upon the award of contracts, are allowable only when paid to bona fide employees or established commercial or selling agencies maintained by the contractor for the purpose of securing business.
Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).
Proposed rule.
The Civilian Agency Acquisition Council and the Defense Acquisition Regulations Council (Councils) are proposing to amend the Federal Acquisition Regulation (FAR) by revising three cost principles: (1) Economic planning costs; (2) Employee morale, health, welfare, food service, and dormitory costs and credits; and (3) Travel costs. The changes are to increase clarity and readability.
Interested parties should submit comments in writing on or before October 28, 2002 to be considered in the formulation of a final rule.
Submit written comments to—General Services Administration, FAR Secretariat (MVA), 1800 F Street, NW., Room 4035, ATTN: Laurie Duarte, Washington, DC 20405.
Submit electronic comments via the Internet to—
Please submit comments only and cite FAR case 2002-001 in all correspondence related to this case.
The FAR Secretariat, Room 4035, GS Building, Washington, DC, 20405, at (202) 501-4755 for information pertaining to status or publication schedules. For clarification of content, contact Jeremy Olson at (202) 501-3221. Please cite FAR case 2002-001.
The proposed rule amends FAR 31.205-12 by eliminating paragraphs (b) and (c). Paragraph (b) states that economic planning costs are allowable as “indirect costs to be properly allocated.” In the Councils' opinion, it duplicates coverage already at 31.202, Direct costs; 31.203, Indirect costs; and 31.201-4, Determining allocability. Paragraph (c) provides that Independent Research and Development (IR&D) costs are not allowable economic planning costs. We believe 31.205-18, Independent research and development and bid and proposal costs, clearly applies to IR&D costs, and that it is not necessary to state that economic planning costs do not include IR&D costs. The intent of the elimination of paragraphs (b) and (c) is to eliminate duplication and not to change the meaning of the current cost principle.
This is not a significant regulatory action and, therefore, was not subject to review under Section 6(b) of Executive Order 12866, Regulatory Planning and Review, dated September 30, 1993. This rule is not a major rule under 5 U.S.C. 804.
The Councils do not expect this proposed rule to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
The Paperwork Reduction Act does not apply because the proposed changes to the FAR do not impose information collection requirements that require the approval of the Office of Management and Budget under 44 U.S.C. 3501,
Government procurement.
Therefore, DoD, GSA, and NASA propose amending 48 CFR part 31 as set forth below:
1. The authority citation for 48 CFR part 31 continues to read as follows:
40 U.S.C. 486(c); 10 U.S.C. chapter 137; and 42 U.S.C. 2473(c).
2. Amend section 31.205-6 in paragraph (m)(2) by removing “(see 31.205-46(f))” and adding “(see 31.205-46(d))” in its place.
3. Revise section 31.205-12 to read as follows:
Economic planning costs are allowable. Economic planning costs are the costs of general long-range management planning concerned with the future overall development of the contractor's business. Economic planning costs do not include organization or reorganization costs covered by 31.205-27. See 31.205-38 for determining the allowability of market planning costs other than economic planning costs.
4. Amend section 31.205-13 by revising paragraphs (a), (d), and (f) to read as follows:
(a) Aggregate costs incurred on activities designed to improve working conditions, employer-employee relations, employee morale, and employee performance (less income generated by these activities) are allowable, subject to the limitations contained in this subsection. Some examples of allowable activities are—
(1) House publications;
(2) Health clinics;
(3) Wellness/fitness centers;
(4) Employee counseling services; and
(5) Food and dormitory services for the contractor's employees at or near the contractor's facilities. These services include—
(i) Operating or furnishing facilities for cafeterias, dining rooms, canteens, lunch wagons, vending machines, living accommodations; and
(ii) Similar types of services.
(d)(1) The allowability of food and dormitory losses are determined by the following factors:
(i) Losses from operating food and dormitory services are allowable only if the contractor's objective is to operate such services on a break-even basis.
(ii) Losses sustained because food services or lodging accommodations are furnished without charge or at prices or rates which obviously would not be conducive to the accomplishment of the objective in paragraph (d)(1)(i) of this subsection are not allowable, except as
(iii) A loss may be allowed to the extent that the contractor can demonstrate that unusual circumstances exist such that even with efficient management, operating the services on a break-even basis would require charging inordinately high prices, or prices or rates higher than those charged by commercial establishments offering the same services in the same geographical areas. The following are examples of unusual circumstances:
(A) The contractor must provide food or dormitory services at remote locations where adequate commercial facilities are not reasonably available.
(B) The contractor's charged (but unproductive) labor costs would be excessive if the services were not available.
(C) If cessation or reduction of food or dormitory operations will not otherwise yield net cost savings.
(2) Costs of food and dormitory services shall include an allocable share of indirect expenses pertaining to these activities.
(f) Contributions by the contractor to an employee organization, including funds from vending machine receipts or similar sources, are allowable only to the extent that the contractor demonstrates that an equivalent amount of the costs incurred by the employee organization would be allowable if directly incurred by the contractor.
5. Amend section 31.205-46 as follows:
a. Remove paragraphs (b) and (c), and redesignate paragraphs (d), (e), and (f) as (b), (c), and (d), respectively; and
b. In the introductory text of newly designated paragraph (c)(2), remove “paragraph (d)” each time it appears (twice) and add “paragraph (b)” in their place; and remove “paragraph (e)(3)” and add “paragraph (c)(3)” in its place.