Title 18—Conservation of Power and Water Resources--Volume 1
PART 33—APPLICATIONS UNDER FEDERAL POWER ACT SECTION 203
§ 33.1   Applicability, definitions, and blanket authorizations.
(a) Applicability. (1) The requirements of this part will apply to any public utility seeking authorization under section 203 of the Federal Power Act to:
(i) Sell, lease, or otherwise dispose of the whole of its facilities subject to the jurisdiction of the Commission, or any part thereof of a value in excess of $10 million;
(ii) Merge or consolidate, directly or indirectly, its facilities subject to the jurisdiction of the Commission, or any part thereof, with the facilities of any other person, or any part thereof, that are subject to the jurisdiction of the Commission and have a value in excess of $10 million, by any means whatsoever;
(iii) Purchase, acquire, or take any security with a value in excess of $10 million of any other public utility; or
(iv) Purchase, lease, or otherwise acquire an existing generation facility:
(A) That has a value in excess of $10 million; and
(B) That is used in whole or in part for wholesale sales in interstate commerce by a public utility.
(2) The requirements of this part shall also apply to any holding company in a holding company system that includes a transmitting utility or an electric utility if such holding company seeks to purchase, acquire, or take any security with a value in excess of $10 million of, or, by any means whatsoever, directly or indirectly, merge or consolidate with, a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility, or an electric utility company, with a value in excess of $10 million.
(b) Definitions. For the purposes of this part, as used in section 203 of the Federal Power Act (16 U.S.C. 824b).
(1) Existing generation facility means a generation facility that is operational at or before the time the section 203 transaction is consummated. “The time the transaction is consummated” means the point in time when the transaction actually closes and control of the facility changes hands. “Operational” means a generation facility for which construction is complete ( i.e. , it is capable of producing power). The Commission will rebuttably presume that section 203(a) applies to the transfer of any existing generation facility unless the utility can demonstrate with substantial evidence that the generator is used exclusively for retail sales.
(2) Non-utility associate company means any associate company in a holding company system other than a public utility or electric utility company that has wholesale or retail customers served under cost-based regulation.
(3) Value when applied to:
(i) Transmission facilities, generation facilities, transmitting utilities, electric utility companies, and holding companies, means the market value of the facilities or companies for transactions between non-affiliated companies; the Commission will rebuttably presume that the market value is the transaction price. For transactions between affiliated companies, value means original cost undepreciated, as defined in the Commission's Uniform System of Accounts prescribed for public utilities and licensees in part 101 of this chapter, or original book cost, as applicable;
(ii) Wholesale contracts, means the market value for transactions between non-affiliated companies; the Commission will rebuttably presume that the market value is the transaction price. For transactions between affiliated companies, value means total expected nominal contract revenues over the remaining life of the contract; and
(iii) Securities, means market value for transactions between non-affiliated companies; the Commission will rebuttably presume that the market value is the agreed-upon transaction price. For transactions between affiliated companies, value means market value if the securities are widely traded, in which case the Commission will rebuttably presume that market value is the market price at which the securities are being traded at the time the transaction occurs; if the securities are not widely traded, market value is determined by:
(A) Determining the value of the company that is the issuer of the equity securities based on the total undepreciated book value of the company's assets;
(B) Determining the fraction of the securities at issue by dividing the number of equity securities involved in the transaction by the total number of outstanding equity securities for the company; and
(C) Multiplying the value determined in paragraph (b)(3)(iii)(A) of this section by the value determined in paragraph (b)(3)(iii)(B) of this section ( i.e. , the value of the company multiplied by the fraction of the equity securities at issue).
(4) The terms associate company, electric utility company, foreign utility company, holding company, and holding company system have the meaning given those terms in the Public Utility Holding Company Act of 2005. The term holding company does not include: A State, any political subdivision of a State, or any agency, authority or instrumentality of a State or political subdivision of a State; or an electric power cooperative.
(5) For purposes of this part, the term captive customers means any wholesale or retail electric energy customers served by a franchised public utility under cost-based regulation.
(c) Blanket Authorizations. (1) Any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to purchase, acquire, or take any security of:
(i) A transmitting utility or company that owns, operates, or controls only facilities used solely for transmission in intrastate commerce and/or sales of electric energy in intrastate commerce, provided that if any public utility within the holding company system has captive customers, or owns or provides transmission service over jurisdictional transmission facilities, the holding company must report the acquisition to the Commission, including any state actions or conditions related to the transaction, and shall provide an explanation of why the transaction does not result in cross-subsidization;
(ii) A transmitting utility or company that owns, operates, or controls only facilities used solely for local distribution and/or sales of electric energy at retail regulated by a state commission, provided that if any public utility within the holding company system has captive customers, or owns or provides transmission service over jurisdictional transmission facilities, the holding company must report the acquisition to the Commission, including any state actions or conditions related to the transaction, and shall provide an explanation of why the transaction does not result in cross-subsidization; or
(iii) An electric utility company that owns generating facilities that total 100 MW or less and are fundamentally used for its own individual load or for sales to affiliated end-users.
(2) Any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to purchase, acquire, or take:
(i) Any non-voting security (that does not convey sufficient veto rights over management actions so as to convey control) in a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility or an electric utility company; or
(ii) Any voting security in a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility or an electric utility company if, after the acquisition, the holding company will own less than 10 percent of the outstanding voting securities; or
(iii) Any security of a subsidiary company within the holding company system.
(3) The blanket authorizations granted under paragraph (c)(2) of this section are subject to the conditions that the holding company shall not:
(i) Borrow from any electric utility company subsidiary in connection with such acquisition; or
(ii) Pledge or encumber the assets of any electric utility company subsidiary in connection with such acquisition.
(4) A holding company granted blanket authorizations in paragraph (c)(2) of this section shall provide the Commission copies of any Schedule 13D, Schedule 13G and Form 13F, at the same time and on the same basis, as filed with the Securities and Exchange Commission in connection with any securities purchased, acquired or taken pursuant to this section.
(5) Any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to acquire a foreign utility company. However, if such holding company or any of its affiliates, its subsidiaries, or associate companies within the holding company system has captive customers in the United States, or owns or provides transmission service over jurisdictional transmission facilities in the United States, the authorization is conditioned on the holding company, consistent with 18 CFR 385.2005(b), verifying by a duly authorized corporate official of the holding company that the proposed transaction:
(i) Will not have any adverse effect on competition, rates, or regulation; and
(ii) Will not result in, at the time of the transaction or in the future:
(A) Any transfer of facilities between a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, and an associate company;
(B) Any new issuance of securities by a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, for the benefit of an associate company;
(C) Any new pledge or encumbrance of assets of a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, for the benefit of an associate company; or
(D) Any new affiliate contracts between a non-utility associate company and a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, other than non-power goods and services agreements subject to review under sections 205 and 206 of the Federal Power Act.
(iii) A transaction by a holding company subject to the conditions in paragraphs (c)(5)(i) and (ii) of this section will be deemed approved only upon filing the information required in paragraphs (c)(5)(i) and (ii) of this section.
(6) Any public utility or any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under sections 203(a)(1) or 203(a)(2) of the Federal Power Act, as relevant, for internal corporate reorganizations that do not result in the reorganization of a traditional public utility that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, and that do not present cross-subsidization issues.
(7) Any public utility in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to purchase, acquire, or take any security of a public utility in connection with an intra-system cash management program, subject to safeguards to prevent cross-subsidization or pledges or encumbrances of utility assets.
(8) A person that is a holding company solely with respect to one or more exempt wholesale generators (EWGs), foreign utility companies (FUCOs), or qualifying facilities (QFs) is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to acquire the securities of additional EWGs, FUCOs, or QFs.
(9) A holding company, or a subsidiary of that company, that is regulated by the Board of Governors of the Federal Reserve Bank or by the Office of the Comptroller of the Currency, under the Bank Holding Company Act of 1956 as amended by the Gramm-Leach-Bliley Act of 1999, is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to acquire and hold an unlimited amount of the securities of holding companies that include a transmitting utility or an electric utility company if such acquisitions and holdings are in the normal course of its business and the securities are held:
(i) As a fiduciary;
(ii) As principal for derivatives hedging purposes incidental to the business of banking and it commits not to vote such securities to the extent they exceed 10 percent of the outstanding shares;
(iii) As collateral for a loan; or
(iv) Solely for purposes of liquidation and in connection with a loan previously contracted for and owned beneficially for a period of not more than two years, with the following conditions and reporting requirement: The holding does not confer a right to control, positively or negatively, through debt covenants or any other means, the operation or management of the public utility or public utility holding company, except as to customary creditors' rights or as provided under the United States Bankruptcy Code; and the parent holding company files with the Commission on a public basis and within 45 days of the close of each calendar quarter, both its total holdings and its holdings as principal, each by class, unless the holdings within a class are less than one percent of outstanding shares, irrespective of the capacity in which they were held.
(10) Any holding company, or a subsidiary of that company, is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to acquire any security of a public utility or a holding company that includes a public utility:
(i) For purposes of conducting underwriting activities, subject to the condition that holdings that the holding company or its subsidiary are unable to sell or otherwise dispose of within 45 days are to be treated as holdings as principal and thus subject to a limitation of 10 percent of the stock of any class unless the holding company or its subsidiary has within that period filed an application under section 203 of the Federal Power Act to retain the securities and has undertaken not to vote the securities during the pendency of such application; and the parent holding company files with the Commission on a public basis and within 45 days of the close of each calendar quarter, both its total holdings and its holdings as principal, each by class, unless the holdings within a class are less than one percent of outstanding shares, irrespective of the capacity in which they were held;
(ii) For purposes of engaging in hedging transactions, subject to the condition that if such holdings are 10 percent or more of the voting securities of a given class, the holding company or its subsidiary shall not vote such holdings to the extent that they are 10 percent or more.
(11) Any public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer a wholesale market-based rate contract to any other public utility affiliate that has the same ultimate upstream ownership, provided that neither affiliate is affiliated with a traditional public utility with captive customers.
(12) A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to:
(i) Any holding company granted blanket authorizations in paragraph (c)(2)(ii) of this section if, after the transfer, the holding company and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of such public utility; or
(ii) Any person other than a holding company if, after the transfer, such person and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of such public utility, and within 30 days after the end of the calendar quarter in which such transfer has occurred the public utility notifies the Commission in accordance with paragraph (c)(17) of this section.
(13) A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to any holding company granted blanket authorization in paragraph (c)(8) of this section if, after the transfer, the holding company and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of such public utility.
(14) A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to any holding company granted blanket authorization in paragraph (c)(9) of this section.
(15) A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to any holding company granted blanket authorization in paragraph (c)(10) of this section.
(16) A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act for the acquisition or disposition of a jurisdictional contract where neither the acquirer nor transferor has captive customers or owns or provides transmission service over jurisdictional transmission facilities, the contract does not convey control over the operation of a generation or transmission facility, and the acquirer is a public utility.
(17) A public utility granted blanket authorization under paragraph (c)(12)(ii) of this section to transfer its outstanding voting securities shall, within 30 days after the end of the calendar quarter in which such transfer has occurred, file with the Commission a report containing the following information:
(i) The names of all parties to the transaction;
(ii) Identification of the pre- and post-transaction voting security holdings (and percentage ownership) in the public utility held by the acquirer and its associate or affiliate companies;
(iii) The date the transaction was consummated;
(iv) Identification of any public utility or holding company affiliates of the parties to the transaction; and
(v) A statement indicating that the proposed transaction will not result in, at the time of the transaction or in the future, cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company as required in § 33.2(j)(1).
§ 33.2   Contents of application—general information requirements.
Each applicant must include in its application, in the manner and form and in the order indicated, the following general information with respect to the applicant and each entity whose jurisdictional facilities or securities are involved:
(a) The exact name of the applicant and its principal business address.
(b) The name and address of the person authorized to receive notices and communications regarding the application, including phone and fax numbers, and E-mail addresses.
(c) A description of the applicant, including:
(1) All business activities of the applicant, including authorizations by charter or regulatory approval (to be identified as Exhibit A to the application);
(2) A list of all energy subsidiaries and energy affiliates, percentage ownership interest in such subsidiaries and affiliates, and a description of the primary business in which each energy subsidiary and affiliate is engaged (to be identified as Exhibit B to the application);
(3) Organizational charts depicting the applicant's current and proposed post-transaction corporate structures (including any pending authorized but not implemented changes) indicating all parent companies, energy subsidiaries and energy affiliates unless the applicant demonstrates that the proposed transaction does not affect the corporate structure of any party to the transaction (to be identified as Exhibit C to the application);
(4) A description of all joint ventures, strategic alliances, tolling arrangements or other business arrangements, including transfers of operational control of transmission facilities to Commission approved Regional Transmission Organizations, both current, and planned to occur within a year from the date of filing, to which the applicant or its parent companies, energy subsidiaries, and energy affiliates is a party, unless the applicant demonstrates that the proposed transaction does not affect any of its business interests (to be identified as Exhibit D to the application);
(5) The identity of common officers or directors of parties to the proposed transaction (to be identified as Exhibit E to the application); and
(6) A description and location of wholesale power sales customers and unbundled transmission services customers served by the applicant or its parent companies, subsidiaries, affiliates and associate companies (to be identified as Exhibit F to the application).
(d) A description of jurisdictional facilities owned, operated, or controlled by the applicant or its parent companies, subsidiaries, affiliates, and associate companies (to be identified as Exhibit G to the application).
(e) A narrative description of the proposed transaction for which Commission authorization is requested, including:
(1) The identity of all parties involved in the transaction;
(2) All jurisdictional facilities and securities associated with or affected by the transaction (to be identified as Exhibit H to the application);
(3) The consideration for the transaction; and
(4) The effect of the transaction on such jurisdictional facilities and securities.
(f) All contracts related to the proposed transaction together with copies of all other written instruments entered into or proposed to be entered into by the parties to the transaction (to be identified as Exhibit I to the application).
(g) A statement explaining the facts relied upon to demonstrate that the proposed transaction is consistent with the public interest. The applicant must include a general explanation of the effect of the transaction on competition, rates and regulation of the applicant by the Commission and state commissions with jurisdiction over any party to the transaction. The applicant should also file any other information it believes relevant to the Commission's consideration of the transaction. The applicant must supplement its application promptly to reflect in its analysis material changes that occur after the date a filing is made with the Commission, but before final Commission action. Such changes must be described and their effect on the analysis explained (to be identified as Exhibit J to the application).
(h) If the proposed transaction involves physical property of any party, the applicant must provide a general or key map showing in different colors the properties of each party to the transaction (to be identified as Exhibit K to the application).
(i) If the applicant is required to obtain licenses, orders, or other approvals from other regulatory bodies in connection with the proposed transaction, the applicant must identify the regulatory bodies and indicate the status of other regulatory actions, and provide a copy of each order of those regulatory bodies that relates to the proposed transaction (to be identified as Exhibit L to the application). If the regulatory bodies issue orders pertaining to the proposed transaction after the date of filing with the Commission, and before the date of final Commission action, the applicant must supplement its Commission application promptly with a copy of these orders.
(j) An explanation, with appropriate evidentiary support for such explanation (to be identified as Exhibit M to this application):
(1) Of how applicants are providing assurance, based on facts and circumstances known to them or that are reasonably foreseeable , that the proposed transaction will not result in , at the time of the transaction or in the future, cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company, including:
(i) Disclosure of existing pledges and/or encumbrances of utility assets; and
(ii) A detailed showing that the transaction will not result in:
(A) Any transfer of facilities between a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, and an associate company;
(B) Any new issuance of securities by a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, for the benefit of an associate company;
(C) Any new pledge or encumbrance of assets of a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, for the benefit of an associate company; or
(D) Any new affiliate contract between a non-utility associate company and a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, other than non-power goods and services agreements subject to review under sections 205 and 206 of the Federal Power Act; or
(2) If no such assurance can be provided, an explanation of how such cross-subsidization, pledge, or encumbrance will be consistent with the public interest.
§ 33.3   Additional information requirements for applications involving horizontal competitive impacts.
(a)(1) The applicant must file the horizontal Competitive Analysis Screen described in paragraphs (b) through (f) of this section if, as a result of the proposed transaction, a single corporate entity obtains ownership or control over the generating facilities of previously unaffiliated merging entities (for purposes of this section, merging entities means any party to the proposed transaction or its parent companies, energy subsidiaries or energy affiliates).
(2) A horizontal Competitive Analysis Screen need not be filed if the applicant:
(i) Affirmatively demonstrates that the merging entities do not currently conduct business in the same geographic markets or that the extent of the business transactions in the same geographic markets is de minimis; and
(ii) No intervenor has alleged that one of the merging entities is a perceived potential competitor in the same geographic market as the other.
(b) All data, assumptions, techniques and conclusions in the horizontal Competitive Analysis Screen must be accompanied by appropriate documentation and support.
(1) If the applicant is unable to provide any specific data required in this section, it must identify and explain how the data requirement was satisfied and the suitability of the substitute data.
(2) The applicant may provide other analyses for defining relevant markets ( e.g. the Hypothetical Monopolist Test with or without the assumption of price discrimination) in addition to the delivered price test under the horizontal Competitive Analysis Screen.
(3) The applicant may use a computer model to complete one or more steps in the horizontal Competitive Analysis Screen. The applicant must fully explain, justify and document any model used and provide descriptions of model formulation, mathematical specifications, solution algorithms, as well as the annotated model code in executable form, and specify the software needed to execute the model. The applicant must explain and document how inputs were developed, the assumptions underlying such inputs and any adjustments made to published data that are used as inputs. The applicant must also explain how it tested the predictive value of the model, for example, using historical data.
(c) The horizontal Competitive Analysis Screen must be completed using the following steps:
(1) Define relevant products. Identify and define all wholesale electricity products sold by the merging entities during the two years prior to the date of the application, including, but not limited to, non-firm energy, short-term capacity (or firm energy), long-term capacity (a contractual commitment of more than one year), and ancillary services (specifically spinning reserves, non-spinning reserves, and imbalance energy, identified and defined separately). Because demand and supply conditions for a product can vary substantially over the year, periods corresponding to those distinct conditions must be identified by load level, and analyzed as separate products.
(2) Identify destination markets. Identify each wholesale power sales customer or set of customers (destination market) affected by the proposed transaction. Affected customers are, at a minimum, those entities directly interconnected to any of the merging entities and entities that have purchased electricity at wholesale from any of the merging entities during the two years prior to the date of the application. If the applicant does not identify an entity to whom the merging entities have sold electricity during the last two years as an affected customer, the applicant must provide a full explanation for each exclusion.
(3) Identify potential suppliers. The applicant must identify potential suppliers to each destination market using the delivered price test described in paragraph (c)(4) of this section. A seller may be included in a geographic market to the extent that it can economically and physically deliver generation services to the destination market.
(4) Perform delivered price test. For each destination market, the applicant must calculate the amount of relevant product a potential supplier could deliver to the destination market from owned or controlled capacity at a price, including applicable transmission prices, loss factors and ancillary services costs, that is no more than five (5) percent above the pre-transaction market clearing price in the destination market.
(i) Supplier's presence. The applicant must measure each potential supplier's presence in the destination market in terms of generating capacity, using economic capacity and available economic capacity measures. Additional adjustments to supplier presence may be presented; applicants must support any such adjustment.
(A) Economic capacity means the amount of generating capacity owned or controlled by a potential supplier with variable costs low enough that energy from such capacity could be economically delivered to the destination market. Prior to applying the delivered price test, the generating capacity meeting this definition must be adjusted by subtracting capacity committed under long-term firm sales contracts and adding capacity acquired under long-term firm purchase contracts ( i.e., contracts with a remaining commitment of more than one year). The capacity associated with any such adjustments must be attributed to the party that has authority to decide when generating resources are available for operation. Other generating capacity may also be attributed to another supplier based on operational control criteria as deemed necessary, but the applicant must explain the reasons for doing so.
(B) Available economic capacity means the amount of generating capacity meeting the definition of economic capacity less the amount of generating capacity needed to serve the potential supplier's native load commitments, as described in paragraph (d)(4)(i) of this section.
(C) Available transmission capacity. Each potential supplier's economic capacity and available economic capacity (and any other measure used to determine the amount of relevant product that could be delivered to a destination market) must be adjusted to reflect available transmission capability to deliver each relevant product. The allocation to a potential supplier of limited capability of constrained transmission paths internal to the merging entities' systems or interconnecting the systems with other control areas must recognize both the transmission capability not subject to firm reservations by others and any firm transmission rights held by the potential supplier that are not committed to long-term transactions. For each such instance where limited transmission capability must be allocated among potential suppliers, the applicant must explain the method used and show the results of such allocation.
(D) Internal interface. If the proposed transaction would cause an interface that interconnects the transmission systems of the merging entities to become transmission facilities for which the merging entities would have a “native load” priority under their open access transmission tariff ( i.e., where the merging entities may reserve existing transmission capacity needed for native load growth and network transmission customer load growth reasonable forecasted within the utility's current planning horizon), all of the unreserved capability of the interface must be allocated to the merging entities for purposes of the horizontal Competitive Analysis Screen, unless the applicant demonstrates one of the following:
( 1 ) The merging entities would not have adequate economic capacity to fully use such unreserved transmission capability;
( 2 ) The merging entities have committed a portion of the interface capability to third parties; or
( 3 ) Suppliers other than the merging entities have purchased a portion of the interface capability.
(ii) [Reserved]
(5) Calculate market concentration. The applicant must calculate the market share, both pre- and post-merger, for each potential supplier, the Herfindahl-Hirschman Index (HHI) statistic for the market, and the change in the HHI statistic. (The HHI statistic is a measure of market concentration and is a function of the number of firms in a market and their respective market shares. The HHI statistic is calculated by summing the squares of the individual market shares, expressed as percentages, of all potential suppliers to the destination market.) To make these calculations, the applicant must use the amounts of generating capacity ( i.e., economic capacity and available economic capacity, and any other relevant measure) determined in paragraph (c)(4)(i) of this section, for each product in each destination market.
(6) Provide historical transaction data. The applicant must provide historical trade data and historical transmission data to corroborate the results of the horizontal Competitive Analysis Screen. The data must cover the two-year period preceding the filing of the application. The applicant may adjust the results of the horizontal Competitive Analysis Screen, if supported by historical trade data or historical transmission service data. Any adjusted results must be shown separately, along with an explanation of all adjustments to the results of the horizontal Competitive Analysis Screen. The applicant must also provide an explanation of any significant differences between results obtained by the horizontal Competitive Analysis Screen and trade patterns in the last two years.
(d) In support of the delivered price test required by paragraph (c)(4) of this section, the applicant must provide the following data and information used in calculating the economic capacity and available economic capacity that a potential supplier could deliver to a destination market. The transmission data required by paragraphs (d)(7) through (d)(9) of this section must be supplied for the merging entities' systems. The transmission data must also be supplied for other relevant systems, to the extent data are publicly available.
(1) Generation capacity. For each generating plant or unit owned or controlled by each potential supplier, the applicant must provide:
(i) Supplier name;
(ii) Name of the plant or unit;
(iii) Primary and secondary fuel-types;
(iv) Nameplate capacity;
(v) Summer and winter total capacity; and
(vi) Summer and winter capacity adjusted to reflect planned and forced outages and other factors, such as fuel supply and environmental restrictions.
(2) Variable cost. For each generating plant or unit owned or controlled by each potential supplier, the applicant must also provide variable cost components.
(i) These cost components must include at a minimum:
(A) Variable operation and maintenance, including both fuel and non-fuel operation and maintenance; and
(B) Environmental compliance.
(ii) To the extent costs described in paragraph (d)(2)(i) of this section are allocated among units at the same plant, allocation methods must be fully described.
(3) Long-term purchase and sales data. For each sale and purchase of capacity, the applicant must provide the following information:
(i) Purchasing entity name;
(ii) Selling entity name;
(iii) Duration of the contract;
(iv) Remaining contract term and any evergreen provisions;
(v) Provisions regarding renewal of the contract;
(vi) Priority or degree of interruptibility;
(vii) FERC rate schedule number, if applicable;
(viii) Quantity and price of capacity and/or energy purchased or sold under the contract; and
(ix) Information on provisions of contracts which confer operational control over generation resources to the purchaser.
(4) Native load commitments. (i) Native load commitments are commitments to serve wholesale and retail power customers on whose behalf the potential supplier, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate its system to meet their reliable electricity needs.
(ii) The applicant must provide supplier name and hourly native load commitments for the most recent two years. In addition, the applicant must provide this information for each load level, if load-differentiated relevant products are analyzed.
(iii) If data on native load commitments are not available, the applicant must fully explain and justify any estimates of these commitments.
(5) Transmission and ancillary service prices, and loss factors. (i) The applicant must use in the horizontal Competitive Analysis Screen the maximum rates stated in the transmission providers' tariffs. If necessary, those rates should be converted to a dollars-per-megawatt hour basis and the conversion method explained.
(ii) If a regional transmission pricing regime is in effect that departs from system-specific transmission rates, the horizontal Competitive Analysis Screen must reflect the regional pricing regime.
(iii) The following data must be provided for each transmission system that would be used to deliver energy from each potential supplier to a destination market:
(A) Supplier name;
(B) Name of transmission system;
(C) Firm point-to-point rate;
(D) Non-firm point-to-point rate;
(E) Scheduling, system control and dispatch rate;
(F) Reactive power/voltage control rate;
(G) Transmission loss factor; and
(H) Estimated cost of supplying energy losses.
(iv) The applicant may present additional alternative analysis using discount prices if the applicant can support it with evidence that discounting is and will be available.
(6) Destination market price. The applicant must provide, for each relevant product and destination market, market prices for the most recent two years. The applicant may provide suitable proxies for market prices if actual market prices are unavailable. Estimated prices or price ranges must be supported and the data and approach used to estimate the prices must be included with the application. If the applicant relies on price ranges in the analysis, such ranges must be reconciled with any actual market prices that are supplied in the application. Applicants must demonstrate that the results of the analysis do not vary significantly in response to small variations in actual and/or estimated prices.
(7) Transmission capability. (i) The applicant must provide simultaneous transfer capability data, if available, for each of the transmission paths, interfaces, or other facilities used by suppliers to deliver to the destination markets on an hourly basis for the most recent two years.
(ii) Transmission capability data must include the following information:
(A) Transmission path, interface, or facility name;
(B) Total transfer capability (TTC); and
(C) Firm available transmission capability (ATC).
(iii) Any estimated transmission capability must be supported and the data and approach used to make the estimates must be included with the application.
(8) Transmission constraints. (i) For each existing transmission facility that affects supplies to the destination markets and that has been constrained during the most recent two years or is expected to be constrained within the planning horizon, the applicant must provide the following information:
(A) Name of all paths, interfaces, or facilities affected by the constraint;
(B) Locations of the constraint and all paths, interfaces, or facilities affected by the constraint;
(C) Hours of the year when the transmission constraint is binding; and
(D) The system conditions under which the constraint is binding.
(ii) The applicant must include information regarding expected changes in loadings on transmission facilities due to the proposed transaction and the consequent effect on transfer capability.
(iii) To the extent possible, the applicant must provide system maps showing the location of transmission facilities where binding constraints have been known or are expected to occur.
(9) Firm transmission rights (Physical and Financial). For each potential supplier to a destination market that holds firm transmission rights necessary to directly or indirectly deliver energy to that market, or that holds transmission congestion contracts, the applicant must provide the following information:
(i) Supplier name;
(ii) Name of transmission path interface, or facility;
(iii) The FERC rate schedule number, if applicable, under which transmission service is provided; and
(iv) A description of the firm transmission rights held (including, at a minimum, quantity and remaining time the rights will be held, and any relevant time restrictions on transmission use, such as peak or off-peak rights).
(10) Summary table of potential suppliers' presence. (i) The applicant must provide a summary table with the following information for each potential supplier for each destination market:
(A) Potential supplier name;
(B) The potential supplier's total amount of economic capacity (not subject to transmission constraints); and
(C) The potential supplier's amount of economic capacity from which energy can be delivered to the destination market (after adjusting for transmission availability).
(ii) A similar table must be provided for available economic capacity, and for any other generating capacity measure used by the applicant.
(11) Historical trade data. (i) The applicant must provide data identifying all of the merging entities' wholesale sales and purchases of electric energy for the most recent two years.
(ii) The applicant must include the following information for each transition:
(A) Type of transaction (such as non-firm, short-term firm, long-term firm, peak, off-peak, etc.);
(B) Name of purchaser;
(C) Name of seller;
(D) Date, duration and time period of the transaction;
(E) Quantity of energy purchased or sold;
(F) Energy charge per unit;
(G) Megawatt hours purchased or sold;
(H) Price; and
(I) The delivery points used to effect the sale or purchase.
(12) Historical transmission data. The applicant must provide information concerning any transmission service denials, interruptions and curtailments on the merging entities' systems, for the most recent two years, to the extent the information is available from OASIS data, including the following information:
(i) Name of the customer denied, interrupted or curtailed;
(ii) Type, quantity and duration of service at issue;
(iii) The date and period of time involved;
(iv) Reason given for the denial, interruption or curtailment;
(v) The transmission path; and
(vi) The reservations or other use anticipated on the affected transmission path at the time of the service denial, curtailment or interruption.
(e) Mitigation. Any mitigation measures proposed by the applicant (including, for example, divestiture or participation in a regional transmission organization) which are intended to mitigate the adverse effect of the proposed transaction must, to the extent possible, be factored into the horizontal Competitive Analysis Screen as an additional post-transaction analysis. Any mitigation commitments that involve facilities ( e.g., in connection with divestiture of generation) must identify the facilities affected by the commitment, along with a timetable for implementing the commitments.
(f) Additional factors. If the applicant does not propose mitigation, the applicant must address:
(1) The potential adverse competitive effects of the transaction.
(2) The potential for entry in the market and the role that entry could play in mitigating adverse competitive effects of the transaction;
(3) The efficiency gains that reasonably could not be achieved by other means; and
(4) Whether, but for the transaction, one or more of the merging entities would be likely to fail, causing its assets to exit the market.
§ 33.4   Additional information requirements for applications involving vertical competitive impacts.
(a)(1) The applicant must file the vertical Competitive Analysis described in paragraphs (b) through (e) of this section if, as a result of the proposed transaction, a single corporate entity has ownership or control over one or more merging entities that provides inputs to electricity products and one or more merging entities that provides electric generation products (for purposes of this section, merging entities means any party to the proposed transaction or its parent companies, energy subsidiaries or energy affiliates).
(2) A vertical Competitive Analysis need not be filed if the applicant can affirmatively demonstrate that:
(i) The merging entities currently do not provide inputs to electricity products ( i.e., upstream relevant products) and electricity products ( i.e., downstream relevant products) in the same geographic markets or that the extent of the business transactions in the same geographic market is de minimis ; and no intervenor has alleged that one of the merging entities is a perceived potential competitor in the same geographic market as the other.
(ii) The extent of the upstream relevant products currently provided by the merging entities is used to produce a de minimis amount of the relevant downstream products in the relevant destination markets, as defined in paragraph (c)(2) of § 33.3.
(b) All data, assumptions, techniques and conclusions in the vertical Competitive Analysis must be accompanied by appropriate documentation and support.
(c) The vertical Competitive Analysis must be completed using the following steps:
(1) Define relevant products —(i) Downstream relevant products. The applicant must identify and define as downstream relevant products all products sold by merging entities in relevant downstream geographic markets, as outlined in paragraph (c)(1) of § 33.3.
(ii) Upstream relevant products. The applicant must identify and define as upstream relevant products all inputs to electricity products provided by upstream merging entities in the most recent two years.
(2) Define geographic markets —(i) Downstream geographic markets. The applicant must identify all geographic markets in which it or any merging entities sell the downstream relevant products, as outlined in paragraphs (c)(2) and (c)(3) of § 33.3.
(ii) Upstream geographic markets The applicant must identify all geographic markets in which it or any merging entities provide the upstream relevant products.
(3) Analyze competitive conditions —(i) Downstream geographic market. (A) The applicant must compute market share for each supplier in each relevant downstream geographic market and the HHI statistic for the downstream market. The applicant must provide a summary table with the following information for each relevant downstream geographic market:
( 1 ) The economic capacity of each downstream supplier (specify the amount of such capacity served by each upstream supplier);
( 2 ) The total amount of economic capacity in the downstream market served by each upstream supplier;
( 3 ) The market share of economic capacity served by each upstream supplier; and
( 4 ) The HHI statistic for the downstream market.
(B) A similar table must be provided for available economic capacity and for any other measure used by the applicant.
(ii) Upstream geographic market. The applicant must provide a summary table with the following information for each upstream relevant product in each relevant upstream geographic market:
(A) The amount of relevant product provided by each upstream supplier;
(B) The total amount of relevant product in the market;
(C) The market share of each upstream supplier; and
(D) The HHI statistic for the upstream market.
(d) Mitigation. Any mitigation measures proposed by the applicant (including, for example, divestiture or participation in an Regional Transmission Organization) which are intended to mitigate the adverse effect of the proposed transaction must, to the extent possible, be factored into the vertical competitive analysis as an additional post-transaction analysis. Any mitigation measures that involve facilities must identify the facilities affected by the commitment.
(e) Additional factors. (1) If the applicant does not propose mitigation measures, the applicant must address:
(i) The potential adverse competitive effects of the transaction.
(ii) The potential for entry in the market and the role that entry could play in mitigating adverse competitive effects of the transaction;
(iii) The efficiency gains that reasonably could not be achieved by other means; and
(iv) Whether, but for the proposed transaction, one or more of the parties to the transaction would be likely to fail, causing its assets to exit the market.
(2) The applicant must address each of the additional factors in the context of whether the proposed transaction is likely to present concerns about raising rivals' costs or anticompetitive coordination.
§ 33.5   Proposed accounting entries.
If the applicant is required to maintain its books of account in accordance with the Commission's Uniform System of Accounts in part 101 of this chapter, the applicant must present proposed accounting entries showing the effect of the transaction with sufficient detail to indicate the effects on all account balances (including amounts transferred on an interim basis), the effect on the income statement, and the effects on other relevant financial statements. The applicant must also explain how the amount of each entry was determined.
§ 33.7   Verification.
The original application must be signed by a person or persons having authority with respect thereto and having knowledge of the matters therein set forth, and must be verified under oath.
§ 33.8   Requirements for filing applications.
The applicant must submit the application or petition to the Secretary of the Commission in accordance with filing procedures posted on the Commission's Web site at http://www.ferc.gov.
(a) If the applicant seeks to protect any portion of the application, or any attachment thereto, from public disclosure, the applicant must make its filing in accordance with the Commission's instructions for submission of privileged materials and Critical Energy Infrastructure Information in § 388.112 of this chapter.
(b) If required, the applicant must submit information specified in paragraphs (b), (c), (d), (e) and (f) of § 33.3 or paragraphs (b), (c), (d) and (e) of § 33.4 on electronic recorded media (i.e., CD/DVD) in accordance with § 385.2011 of this chapter, along with a printed description and summary. The printed portion of the applicant's submission must include documentation for the electronic information, including all file names and a summary of the data contained in each file. Each column (or data item) in each separate data table or chart must be clearly labeled in accordance with the requirements of §§ 33.3 and 33.4. Any units of measurement associated with numeric entries must also be included.
§ 33.9   [Reserved]
§ 33.10   Additional information.
The Director of the Office of Energy Market Regulation, or his designee, may, by letter, require the applicant to submit additional information as is needed for analysis of an application filed under this part.
§ 33.11   Commission procedures for the consideration of applications under section 203 of the FPA.
(a) The Commission will act on a completed application for approval of a transaction ( i.e., one that is consistent with the requirements of this part) not later than 180 days after the completed application is filed. If the Commission does not act within 180 days, such application shall be deemed granted unless the Commission finds, based on good cause, that further consideration is required to determine whether the proposed transaction meets the standards of section 203(a)(4) of the FPA and issues, by the 180th day, an order tolling the time for acting on the application for not more than 180 days, at the end of which additional period the Commission shall grant or deny the application.
(b) The Commission will provide for the expeditious consideration of completed applications for the approval of transactions that are not contested, do not involve mergers, and are consistent with Commission precedent.
(c) Transactions, provided that they are not contested, do not involve mergers and are consistent with Commission precedent, that will generally be subject to expedited review include:
(1) A disposition of only transmission facilities, including, but not limited to, those that both before and after the transaction remain under the functional control of a Commission-approved regional transmission organization or independent system operator; and
(2) Transactions that do not require an Appendix A analysis; 1 and
1 Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act; Policy Statement, Order No. 592, 61 FR 68,595 (Dec. 30, 1996), FERC Stats. & Regs. ¶ 31,044 (1996), reconsideration denied, Order No. 592-A, 62 FR 33,340 (June 19, 1977), 79 FERC ¶ 61,321 (1997) (Merger Policy Statement).
(3) Internal corporate reorganizations that result in the reorganization of a traditional public utility that has captive customers or owns or provides transmission service over jurisdictional transmission facilities, but do not present cross-subsidization issues.
§ 33.12   Notification requirement for certain transactions.
(a) Any public utility that is seeking to merge or consolidate, directly or indirectly, its facilities subject to the jurisdiction of the Commission, or any part thereof, with those of any other person, shall notify the Commission of such transaction not later than 30 days after the date on which the transaction is consummated if:
(1) The facilities, or any part thereof, to be acquired are of a value in excess of $1 million; and
(2) Such public utility is not required to secure an order of the Commission under section 203(a)(1)(B) of the Federal Power Act.
(b) Such notification shall consist of the following information:
(1) The exact name of the public utility and its principal business address; and
(2) A narrative description of the transaction, including:
(i) The identity of all parties involved in the transaction, whether such parties are affiliates, and all jurisdictional facilities associated with or affected by the transaction;
(ii) The location of such jurisdictional facilities involved in the transaction;
(iii) The date on which the transaction was consummated;
(iv) The consideration for the transaction; and
(v) The effect of the transaction on the ownership and control of such jurisdictional facilities.