Statutes and Regulations

Statutes and Regulations

Title 16 U.S.C.

§ 824d. Rates and charges; schedules; suspension of new rates; automatic adjustment clauses

(a) Just and reasonable rates

All rates and charges made, demanded, or received by any public utility for or in connection with the transmission or sale of electric energy subject to the jurisdiction of the Commission, and all rules and regulations affecting or pertaining to such rates or charges shall be just and reasonable, and any such rate or charge that is not just and reasonable is hereby declared to be unlawful.

(b) Preference or advantage unlawful

No public utility shall, with respect to any transmission or sale subject to the jurisdiction of the Commission,

(1) make or grant any undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage, or

(2) maintain any unreasonable difference in rates, charges, service, facilities, or in any other respect, either as between localities or as between classes of service.

(c) Schedules

Under such rules and regulations as the Commission may prescribe, every public utility shall file with the Commission, within such time and in such form as the Commission may designate, and shall keep open in convenient form and place for public inspection schedules showing all rates and charges for any transmission or sale subject to the jurisdiction of the Commission, and the classifications, practices, and regulations affecting such rates and charges, together with all contracts which in any manner affect or relate to such rates, charges, classifications, and services.

(d) Notice required for rate changes

Unless the Commission otherwise orders, no change shall be made by any public utility in any such rate, charge, classification, or service, or in any rule, regulation, or contract relating thereto, except after sixty days’ notice to the Commission and to the public. Such notice shall be given by filing with the Commission and keeping open for public inspection new schedules stating plainly the change or changes to be made in the schedule or schedules then in force and the time when the change or changes will go into effect. The Commission, for good cause shown, may allow changes to take effect without requiring the sixty days’ notice herein provided for by an order specifying the changes so to be made and the time when they shall take effect and the manner in which they shall be filed and published.

(e) Suspension of new rates; hearings; five-month period

Whenever any such new schedule is filed the Commission shall have authority, either upon complaint or upon its own initiative without complaint, at once, and, if it so orders, without answer or formal pleading by the public utility, but upon reasonable notice, to enter upon a hearing concerning the lawfulness of such rate, charge, classification, or service; and, pending such hearing and the decision thereon, the Commission, upon filing with such schedules and delivering to the public utility affected thereby a statement in writing of its reasons for such suspension, may suspend the operation of such schedule and defer the use of such rate, charge, classification, or service, but not for a longer period than five months beyond the time when it would otherwise go into effect; and after full hearings, either completed before or after the rate, charge, classification, or service goes into effect, the Commission may make such orders with reference thereto as would be proper in a proceeding initiated after it had become effective. If the proceeding has not been concluded and an order made at the expiration of such five months, the proposed change of rate, charge, classification, or service shall go into effect at the end of such period, but in case of a proposed increased rate or charge, the Commission may by order require the interested public utility or public utilities to keep accurate account in detail of all amounts received by reason of such increase, specifying by whom and in whose behalf such amounts are paid, and upon completion of the hearing and decision may by further order require such public utility or public utilities to refund, with interest, to the persons in whose behalf such amounts were paid, such portion of such increased rates or charges as by its decision shall be found not justified. At any hearing involving a rate or charge sought to be increased, the burden of proof to show that the increased rate or charge is just and reasonable shall be upon the public utility, and the Commission shall give to the hearing and decision of such questions preference over other questions pending before it and decide the same as speedily as possible.

(f) Review of automatic adjustment clauses and public utility practices; action by Commission; “automatic adjustment clause” defined

(1) Not later than 2 years after November 9, 1978, and not less often than every 4 years thereafter, the Commission shall make a thorough review of automatic adjustment clauses in public utility rate schedules to examine—

(A) whether or not each such clause effectively provides incentives for efficient use of resources (including economical purchase and use of fuel and electric energy), and

(B) whether any such clause reflects any costs other than costs which are—

(i) subject to periodic fluctuations and

(ii) not susceptible to precise determinations in rate cases prior to the time such costs are incurred.

Such review may take place in individual rate proceedings or in generic or other separate proceedings applicable to one or more utilities.

(2) Not less frequently than every 2 years, in rate proceedings or in generic or other separate proceedings, the Commission shall review, with respect to each public utility, practices under any automatic adjustment clauses of such utility to insure efficient use of resources (including economical purchase and use of fuel and electric energy) under such clauses.

(3) The Commission may, on its own motion or upon complaint, after an opportunity for an evidentiary hearing, order a public utility to—

(A) modify the terms and provisions of any automatic adjustment clause, or

(B) cease any practice in connection with the clause,

if such clause or practice does not result in the economical purchase and use of fuel, electric energy, or other items, the cost of which is included in any rate schedule under an automatic adjustment clause.

(4) As used in this subsection, the term “automatic adjustment clause” means a provision of a rate schedule which provides for increases or decreases (or both), without prior hearing, in rates reflecting increases or decreases (or both) in costs incurred by an electric utility. Such term does not include any rate which takes effect subject to refund and subject to a later determination of the appropriate amount of such rate.

§ 824e. Power of Commission to fix rates and charges; determination of cost of production or transmission

(a) Unjust or preferential rates, etc.; statement of reasons for changes; hearing; specification of issues

Whenever the Commission, after a hearing held upon its own motion or upon complaint, shall find that any rate, charge, or classification, demanded, observed, charged, or collected by any public utility for any transmission or sale subject to the jurisdiction of the Commission, or that any rule, regulation, practice, or contract affecting such rate, charge, or classification is unjust, unreasonable, unduly discriminatory or preferential, the Commission shall determine the just and reasonable rate, charge, classification, rule, regulation, practice, or contract to be thereafter observed and in force, and shall fix the same by order. Any complaint or motion of the Commission to initiate a proceeding under this section shall state the change or changes to be made in the rate, charge, classification, rule, regulation, practice, or contract then in force, and the reasons for any proposed change or changes therein. If, after review of any motion or complaint and answer, the Commission shall decide to hold a hearing, it shall fix by order the time and place of such hearing and shall specify the issues to be adjudicated.

(b) Refund effective date; preferential proceedings; statement of reasons for delay; burden of proof; scope of refund order; refund orders in cases of dilatory behavior; interest

Whenever the Commission institutes a proceeding under this section, the Commission shall establish a refund effective date. In the case of a proceeding instituted on complaint, the refund effective date shall not be earlier than the date of the filing of such complaint nor later than 5 months after the filing of such complaint. In the case of a proceeding instituted by the Commission on its own motion, the refund effective date shall not be earlier than the date of the publication by the Commission of notice of its intention to initiate such proceeding nor later than 5 months after the publication date. Upon institution of a proceeding under this section, the Commission shall give to the decision of such proceeding the same preference as provided under section 824d of this title and otherwise act as speedily as possible. If no final decision is rendered by the conclusion of the 180-day period commencing upon initiation of a proceeding pursuant to this section, the Commission shall state the reasons why it has failed to do so and shall state its best estimate as to when it reasonably expects to make such decision. In any proceeding under this section, the burden of proof to show that any rate, charge, classification, rule, regulation, practice, or contract is unjust, unreasonable, unduly discriminatory, or preferential shall be upon the Commission or the complainant. At the conclusion of any proceeding under this section, the Commission may order refunds of any amounts paid, for the period subsequent to the refund effective date through a date fifteen months after such refund effective date, in excess of those which would have been paid under the just and reasonable rate, charge, classification, rule, regulation, practice, or contract which the Commission orders to be thereafter observed and in force: Provided, That if the proceeding is not concluded within fifteen months after the refund effective date and if the Commission determines at the conclusion of the proceeding that the proceeding was not resolved within the fifteen-month period primarily because of dilatory behavior by the public utility, the Commission may order refunds of any or all amounts paid for the period subsequent to the refund effective date and prior to the conclusion of the proceeding. The refunds shall be made, with interest, to those persons who have paid those rates or charges which are the subject of the proceeding.

(c) Refund considerations; shifting costs; reduction in revenues; “electric utility companies” and “registered holding company” defined

Notwithstanding subsection (b) of this section, in a proceeding commenced under this section involving two or more electric utility companies of a registered holding company, refunds which might otherwise be payable under subsection (b) of this section shall not be ordered to the extent that such refunds would result from any portion of a Commission order that

(1) requires a decrease in system production or transmission costs to be paid by one or more of such electric companies; and

(2) is based upon a determination that the amount of such decrease should be paid through an increase in the costs to be paid by other electric utility companies of such registered holding company: Provided, That refunds, in whole or in part, may be ordered by the Commission if it determines that the registered holding company would not experience any reduction in revenues which results from an inability of an electric utility company of the holding company to recover such increase in costs for the period between the refund effective date and the effective date of the Commission’s order. For purposes of this subsection, the terms “electric utility companies” and “registered holding company” shall have the same meanings as provided in the Public Utility Holding Company Act of 1935, as amended.^[1]

(d) Investigation of costs

The Commission upon its own motion, or upon the request of any State commission whenever it can do so without prejudice to the efficient and proper conduct of its affairs, may investigate and determine the cost of the production or transmission of electric energy by means of facilities under the jurisdiction of the Commission in cases where the Commission has no authority to establish a rate governing the sale of such energy.

(e) Short-term sales

(1) In this subsection:

(A) The term “short-term sale” means an agreement for the sale of electric energy at wholesale in interstate commerce that is for a period of 31 days or less (excluding monthly contracts subject to automatic renewal).

(B) The term “applicable Commission rule” means a Commission rule applicable to sales at wholesale by public utilities that the Commission determines after notice and comment should also be applicable to entities subject to this subsection.

(2) If an entity described in section 824 (f) of this title voluntarily makes a short-term sale of electric energy through an organized market in which the rates for the sale are established by Commission-approved tariff (rather than by contract) and the sale violates the terms of the tariff or applicable Commission rules in effect at the time of the sale, the entity shall be subject to the refund authority of the Commission under this section with respect to the violation.

(3) This section shall not apply to—

(A) any entity that sells in total (including affiliates of the entity) less than 8,000,000 megawatt hours of electricity per year; or

(B) an electric cooperative.

(4)

(A) The Commission shall have refund authority under paragraph (2) with respect to a voluntary short term sale of electric energy by the Bonneville Power Administration only if the sale is at an unjust and unreasonable rate.

(B) The Commission may order a refund under subparagraph (A) only for short-term sales made by the Bonneville Power Administration at rates that are higher than the highest just and reasonable rate charged by any other entity for a short-term sale of electric energy in the same geographic market for the same, or most nearly comparable, period as the sale by the Bonneville Power Administration.

(C) In the case of any Federal power marketing agency or the Tennessee Valley Authority, the Commission shall not assert or exercise any regulatory authority or power under paragraph (2) other than the ordering of refunds to achieve a just and reasonable rate.

18 CFR 35 Subpart H

Subpart H—Wholesale Sales of Electric Energy, Capacity and Ancillary Services at Market-Based Rates

Source:   Order 697, 72 FR 40038, July 20, 2007, unless otherwise noted.

§ 35.36   Generally.

(a) For purposes of this subpart:

(1) Seller means any person that has authorization to or seeks authorization to engage in sales for resale of electric energy, capacity or ancillary services at market-based rates under section 205 of the Federal Power Act.

(2) Category 1 Sellers means wholesale power marketers and wholesale power producers that own or control 500 MW or less of generation in aggregate per region; that do not own, operate or control transmission facilities other than limited equipment necessary to connect individual generating facilities to the transmission grid (or have been granted waiver of the requirements of Order No. 888, FERC Stats. & Regs. ¶ 31,036); that are not affiliated with anyone that owns, operates or controls transmission facilities in the same region as the seller's generation assets; that are not affiliated with a franchised public utility in the same region as the seller's generation assets; and that do not raise other vertical market power issues.

(3) Category 2 Sellers means any Sellers not in Category 1.

(4) Inputs to electric power production means intrastate natural gas transportation, intrastate natural gas storage or distribution facilities; sites for generation capacity development; physical coal supply sources and ownership of or control over who may access transportation of coal supplies.

(5) Franchised public utility means a public utility with a franchised service obligation under State law.

(6) Captive customers means any wholesale or retail electric energy customers served by a franchised public utility under cost-based regulation.

(7) Market-regulated power sales affiliate means any power seller affiliate other than a franchised public utility, including a power marketer, exempt wholesale generator, qualifying facility or other power seller affiliate, whose power sales are regulated in whole or in part on a market-rate basis.

(8) Market information means non-public information related to the electric energy and power business including, but not limited to, information regarding sales, cost of production, generator outages, generator heat rates, unconsummated transactions, or historical generator volumes. Market information includes information from either affiliates or non-affiliates.

(9) Affiliate of a specified company means:

(i) Any person that directly or indirectly owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of the specified company;

(ii) Any company 10 percent or more of whose outstanding voting securities are owned, controlled, or held with power to vote, directly or indirectly, by the specified company;

(iii) Any person or class of persons that the Commission determines, after appropriate notice and opportunity for hearing, to stand in such relation to the specified company that there is liable to be an absence of arm's-length bargaining in transactions between them as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that the person be treated as an affiliate; and

(iv) Any person that is under common control with the specified company.

(v) For purposes of paragraph (a)(9), owning, controlling or holding with power to vote, less than 10 percent of the outstanding voting securities of a specified company creates a rebuttable presumption of lack of control.

(b) The provisions of this subpart apply to all Sellers authorized, or seeking authorization, to make sales for resale of electric energy, capacity or ancillary services at market-based rates unless otherwise ordered by the Commission.

[Order 697, 72 FR 40038, July 20, 2007, as amended by Order 697–A, 73 FR 25912, May 7, 2008; Order 697–B, 73 FR 79627, Dec. 30, 2008]

§ 35.37   Market power analysis required.

(a) (1) In addition to other requirements in subparts A and B, a Seller must submit a market power analysis in the following circumstances: when seeking market-based rate authority; for Category 2 Sellers, every three years, according to the schedule contained in Order No. 697, FERC Stats. & Regs. ¶ 31,252; or any other time the Commission directs a Seller to submit one. Failure to timely file an updated market power analysis will constitute a violation of Seller's market-based rate tariff.

(2) When submitting a market power analysis, whether as part of an initial application or an update, a Seller must include an appendix of assets in the form provided in Appendix B of this subpart.

(b) A market power analysis must address whether a Seller has horizontal and vertical market power.

(c) (1) There will be a rebuttable presumption that a Seller lacks horizontal market power if it passes two indicative market power screens: a pivotal supplier analysis based on the annual peak demand of the relevant market, and a market share analysis applied on a seasonal basis. There will be a rebuttable presumption that a Seller possesses horizontal market power if it fails either screen.

(2) Sellers and intervenors may also file alternative evidence to support or rebut the results of the indicative screens. Sellers may file such evidence at the time they file their indicative screens. Intervenors may file such evidence in response to a Seller's submissions.

(3) If a Seller does not pass one or both screens, the Seller may rebut a presumption of horizontal market power by submitting a Delivered Price Test analysis. A Seller that does not rebut a presumption of horizontal market power or that concedes market power, is subject to mitigation, as described in §35.38.

(4) When submitting a horizontal market power analysis, a Seller must use the form provided in Appendix A of this subpart and include all supporting materials referenced in the form.

(d) To demonstrate a lack of vertical market power, a Seller that owns, operates or controls transmission facilities, or whose affiliates own, operate or control transmission facilities, must have on file with the Commission an Open Access Transmission Tariff, as described in §35.28; provided, however, that a Seller whose foreign affiliate(s) own, operate or control transmission facilities outside of the United States that can be used by competitors of the Seller to reach United States markets must demonstrate that such affiliate either has adopted and is implementing an Open Access Transmission Tariff as described in §35.28, or otherwise offers comparable, non-discriminatory access to such transmission facilities.

(e) To demonstrate a lack of vertical market power in wholesale energy markets through the affiliation, ownership or control of inputs to electric power production, such as the transportation or distribution of the inputs to electric power production, a Seller must provide the following information:

(1) A description of its ownership or control of, or affiliation with an entity that owns or controls, intrastate natural gas transportation, intrastate natural gas storage or distribution facilities;

(2) Sites for generation capacity development; and

(3) Physical coal supply sources and ownership or control over who may access transportation of coal supplies.

(4) A Seller must ensure that this information is included in the record of each new application for market-based rates and each updated market power analysis. In addition, a Seller is required to make an affirmative statement that it has not erected barriers to entry into the relevant market and will not erect barriers to entry into the relevant market.

(f) If the seller seeks to protect any portion of the application, or any attachment thereto, from public disclosure pursuant to §388.112 of this chapter, the seller must include with its request for privileged treatment a proposed protective order under which the parties to the proceeding will be able to review any of the data, information, analysis or other documentation relied upon by the seller for which privileged treatment is sought. A seller must grant access to privileged data to any party that signs a protective order within 5 days from the date that the party executes the protective order.

[Order 697, 72 FR 40038, July 20, 2007, as amended by Order 697–B, 73 FR 79627, Dec. 30, 2008]

§ 35.38   Mitigation.

(a) A Seller that has been found to have market power in generation or that is presumed to have horizontal market power by virtue of failing or foregoing the horizontal market power screens, as described in §35.37(c), may adopt the default mitigation detailed in paragraph (b) of this section or may propose mitigation tailored to its own particular circumstances to eliminate its ability to exercise market power. Mitigation will apply only to the market(s) in which the Seller is found, or presumed, to have market power.

(b) Default mitigation consists of three distinct products:

(1) Sales of power of one week or less priced at the Seller's incremental cost plus a 10 percent adder;

(2) Sales of power of more than one week but less than one year priced at no higher than a cost-based ceiling reflecting the costs of the unit(s) expected to provide the service; and

(3) New contracts filed for review under section 205 of the Federal Power Act for sales of power for one year or more priced at a rate not to exceed embedded cost of service.

§ 35.39   Affiliate restrictions.

(a) General affiliate provisions. As a condition of obtaining and retaining market-based rate authority, the conditions provided in this section, including the restriction on affiliate sales of electric energy and all other affiliate provisions, must be satisfied on an ongoing basis, unless otherwise authorized by Commission rule or order. Failure to satisfy these conditions will constitute a violation of the Seller's market-based rate tariff.

(b) Restriction on affiliate sales of electric energy or capacity . As a condition of obtaining and retaining market-based rate authority, no wholesale sale of electric energy or capacity may be made between a franchised public utility with captive customers and a market-regulated power sales affiliate without first receiving Commission authorization for the transaction under section 205 of the Federal Power Act. All authorizations to engage in affiliate wholesale sales of electric energy or capacity must be listed in a Seller's market-based rate tariff.

(c) Separation of functions. (1) For the purpose of this paragraph, entities acting on behalf of and for the benefit of a franchised public utility with captive customers (such as entities controlling or marketing power from the electrical generation assets of the franchised public utility) are considered part of the franchised public utility. Entities acting on behalf of and for the benefit of the market-regulated power sales affiliates of a franchised public utility with captive customers are considered part of the market-regulated power sales affiliates.

(2) (i) To the maximum extent practical, the employees of a market-regulated power sales affiliate must operate separately from the employees of any affiliated franchised public utility with captive customers.

(ii) Franchised public utilities with captive customers are permitted to share support employees, and field and maintenance employees with their market-regulated power sales affiliates. Franchised public utilities with captive customers are also permitted to share senior officers and boards of directors with their market-regulated power sales affiliates; provided, however, that the shared officers and boards of directors must not participate in directing, organizing or executing generation or market functions.

(iii) Notwithstanding any other restrictions in this section, in emergency circumstances affecting system reliability, a market-regulated power sales affiliate and a franchised public utility with captive customers may take steps necessary to keep the bulk power system in operation. A franchised public utility with captive customers or the market-regulated power sales affiliate must report to the Commission and disclose to the public on its Web site, each emergency that resulted in any deviation from the restrictions of section 35.39, within 24 hours of such deviation.

(d) Information sharing. (1) A franchised public utility with captive customers may not share market information with a market-regulated power sales affiliate if the sharing could be used to the detriment of captive customers, unless simultaneously disclosed to the public.

(2) Permissibly shared support employees, field and maintenance employees and senior officers and board of directors under §§35.39(c)(2)(ii) may have access to information covered by the prohibition of §35.39(d)(1), subject to the no-conduit provision in §35.39(g).

(e) Non-power goods or services. (1) Unless otherwise permitted by Commission rule or order, sales of any non-power goods or services by a franchised public utility with captive customers, to a market-regulated power sales affiliate must be at the higher of cost or market price.

(2) Unless otherwise permitted by Commission rule or order, sales of any non-power goods or services by a market-regulated power sales affiliate to an affiliated franchised public utility with captive customers may not be at a price above market.

(f) Brokering of power. (1) Unless otherwise permitted by Commission rule or order, to the extent a market-regulated power sales affiliate seeks to broker power for an affiliated franchised public utility with captive customers:

(i) The market-regulated power sales affiliate must offer the franchised public utility's power first;

(ii) The arrangement between the market-regulated power sales affiliate and the franchised public utility must be non-exclusive; and

(iii) The market-regulated power sales affiliate may not accept any fees in conjunction with any brokering services it performs for an affiliated franchised public utility.

(2) Unless otherwise permitted by Commission rule or order, to the extent a franchised public utility with captive customers seeks to broker power for a market-regulated power sales affiliate:

(i) The franchised public utility must charge the higher of its costs for the service or the market price for such services;

(ii) The franchised public utility must market its own power first, and simultaneously make public (on the Internet) any market information shared with its affiliate during the brokering; and

(iii) The franchised public utility must post on the Internet the actual brokering charges imposed.

(g) No conduit provision. A franchised public utility with captive customers and a market-regulated power sales affiliate are prohibited from using anyone, including asset managers, as a conduit to circumvent the affiliate restrictions in §§35.39(a) through (g).

(h) Franchised utilities without captive customers. If necessary, any affiliate restrictions regarding separation of functions, power sales or non-power goods and services transactions, or brokering involving two or more franchised public utilities, one or more of whom has captive customers and one or more of whom does not have captive customers, will be imposed on a case-by-case basis.

[Order 697, 72 FR 40038, July 20, 2007, as amended by Order 697–A, 73 FR 25912, May 7, 2008]

§ 35.40   Ancillary services.

A Seller may make sales of ancillary services at market-based rates only if it has been authorized by the Commission and only in specific geographic markets as the Commission has authorized.

§ 35.41   Market behavior rules.

(a) Unit operation. Where a Seller participates in a Commission-approved organized market, Seller must operate and schedule generating facilities, undertake maintenance, declare outages, and commit or otherwise bid supply in a manner that complies with the Commission-approved rules and regulations of the applicable market. A Seller is not required to bid or supply electric energy or other electricity products unless such requirement is a part of a separate Commission-approved tariff or is a requirement applicable to Seller through Seller's participation in a Commission-approved organized market.

(b) Communications. A Seller must provide accurate and factual information and not submit false or misleading information, or omit material information, in any communication with the Commission, Commission-approved market monitors, Commission-approved regional transmission organizations, Commission-approved independent system operators, or jurisdictional transmission providers, unless Seller exercises due diligence to prevent such occurrences.

(c) Price reporting. To the extent a Seller engages in reporting of transactions to publishers of electric or natural gas price indices, Seller must provide accurate and factual information, and not knowingly submit false or misleading information or omit material information to any such publisher, by reporting its transactions in a manner consistent with the procedures set forth in the Policy Statement issued by the Commission in Docket No. PL03–3–000 and any clarifications thereto. Unless Seller has previously provided the Commission with a notification of its price reporting status, Seller must notify the Commission within 15 days of the effective date of this regulation or within 15 days of the date it begins making wholesale sales, whichever is earlier, whether it engages in such reporting of its transactions. Seller must update the notification within 15 days of any subsequent change in its transaction reporting status. In addition, Seller must adhere to such other standards and requirements for price reporting as the Commission may order.

(d) Records retention. A Seller must retain, for a period of five years, all data and information upon which it billed the prices it charged for the electric energy or electric energy products it sold pursuant to Seller's market-based rate tariff, and the prices it reported for use in price indices.

§ 35.42   Change in status reporting requirement.

(a) As a condition of obtaining and retaining market-based rate authority, a Seller must timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority. A change in status includes, but is not limited to, the following:

(1) Ownership or control of generation capacity that results in net increases of 100 MW or more, or of inputs to electric power production, or ownership, operation or control of transmission facilities, or

(2) Affiliation with any entity not disclosed in the application for market-based rate authority that owns or controls generation facilities or inputs to electric power production, affiliation with any entity not disclosed in the application for market-based rate authority that owns, operates or controls transmission facilities, or affiliation with any entity that has a franchised service area.

(b) Any change in status subject to paragraph (a) of this section, other than a change in status submitted to report the acquisition of control of a site or sites for new generation capacity development, must be filed no later than 30 days after the change in status occurs. Power sales contracts with future delivery are reportable 30 days after the physical delivery has begun. Failure to timely file a change in status report constitutes a tariff violation.

(c) When submitting a change in status notification regarding a change that impacts the pertinent assets held by a Seller or its affiliates with market-based rate authorization, a Seller must include an appendix of assets in the form provided in Appendix B of this subpart.

(d) A Seller must report on a quarterly basis the acquisition of control of a site or sites for new generation capacity development for which site control has been demonstrated in the interconnection process and for which the potential number of megawatts that are reasonably commercially feasible on the site or sites for new generation capacity development is equal to 100 megawatts or more. If a Seller elects to make a monetary deposit so that it may demonstrate site control at a later time in the interconnection process, the monetary deposit will trigger the quarterly reporting requirement instead of the demonstration of site control. A notification of change in status that is submitted to report the acquisition of control of a site or sites for new generation capacity development must include:

(1) The number of sites acquired;

(2) The relevant geographic market in which the sites are located; and

(3) The maximum potential number of megawatts (MW) that are reasonably commercially feasible on the sites reported.

(e) For the purposes of paragraph (d) of this section, “control” shall mean “site control” as it is defined in the Standard Large Generator Interconnection Procedures (LGIP).

[Order 697–D, 75 FR 14351, Mar. 25, 2010]

Appendix A to Subpart H of Part 35

Appendix A

Standard Screen Format

(Data provided for Illustrative Purposes only)

Part I—Pivotal Supplier Analysis

Row	Generation	MW	Reference
Seller and Affiliate Capacity
A	Installed Capacity	19,500	Workpaper.
B	Long-Term Firm Purchases	500	Workpaper.
C	Long-Term Firm Sales	−1,000	Workpaper.
D	Imported Power	0	Workpaper.
Non-Affiliate Capacity
E	Installed Capacity	8,000	Workpaper.
F	Long-Term Firm Purchases	500	Workpaper.
G	Long-Term Firm Sales	−2,500	Workpaper.
H	Imported Power	3,500	Workpaper.
I	Balancing Authority Area Reserve Requirement	−2,160	Workpaper.
J	Amount of Line I Attributable to Seller, if any	−2,160	Workpaper.
K	Total Uncommitted Supply (SUM A,B,C,D,E,F,G,H,I,M)	9,840
Load
L	Balancing Authority Area Annual Peak Load	18,000	Workpaper.
M	Average Daily Peak Native Load in Peak Month	−16,500	Workpaper.
N	Amount of Line M Attributable to Seller, if any	−16,500	Workpaper.
O	Wholesale Load (SUM L,M)	1,500
P	Net Uncommitted Supply (K–O)	8,340
Q	Seller's Uncommitted Capacity (SUM A,B,C,D,J,N)	340
	Result of Pivotal Supplier Screen (Pass if Line Q < Line P), (Fail if Line Q > Line P)		PASS.

[Order 697, 72 FR 40038, July 20, 2007, as amended by Order 697–A, 73 FR 25913, May 7, 2008]

Appendix B to Subpart H of Part 35

This is an example of the required appendix listing the filing entity and all its energy affiliates and their associated assets which should be submitted with all market-based rate filings.

Market-Based Rate Authority and Generation Assets

Filing entity and its energy affiliates	Docket No. where MBR authority was granted	Generation name	Owned by	Controlled by	Date control transferred	Location		In-service date	Nameplate and/or seasonal rating
						Balancing authority area	Geographic region (per Appendix D)
ABC Corp.	ER05–23X–000	ABC falls plant #1	ABC Corp	ABC Corp	NA*	ABC balancing authority area	Central	8/12/1981	153.5 MW (seasonal).
xyz Inc.	ER94–79XX–000	NA	NA	NA	NA	NA	NA	NA	NA.
RST LLC	ER01–2XX5–000	Green CoGen	WWW Corp	RST LLC	5/23/2005	New York ISO	Northeast	12/20/2003	2000 MW (nameplate).
Sample Co.	ER03–XX45–000	Sample Co. 3	Sample Co	YYY Corp	2/1/1982	Sample Co. balancing authority	Southwest	5/13/1973	10 MW (seasonal).

*If an entity has no assets or the field is not applicable please indicate so by inputting (NA).

Electric Transmission Assets and/or Natural Gas Intrastate Pipelines and/or Gas Storage Facilities

Filing entity and its energy affiliates	Asset name and use	Owned by	Controlled by	Date control transferred	Location		Size
					Balancing authority area	Geographic region (per Appendix D)
ABC Corp	CBA Line, used to interconnect Green Cogen to New York ISO transmission system	ABC Corp	ABC Corp	NA*	New York ISO	Northeast	approximately five-mile, 500 kV line.
Etc. LP	Nowhere Pipeline, used to connect Storage LLC's—Longway Pipeline to ABC falls plant #1	Etc. LP	Etc. LP	NA	ABC balancing authority area	Central	approximately 14 miles of natural gas pipeline and related equipment with 50 MMcf/d capacity.

*If the field is not applicable please indicate so by inputting (NA).