Conference on Supply Margin Assessment (Docket No. PL02-8-000); AEP Power Marketing, Inc., AEP Service Corporation, CSW Power Marketing, Inc., CSW Energy Services, Inc., and Central and South West Services, Inc. (Docket Nos. ER96-2495-016, ER97-4143-004, ER97-1238-011, ER98-2075-010, and ER98-542-006 (Not consolidated)); Entergy Services, Inc. (Docket No. ER91-569-018); Southern Company Energy Marketing L.P. (Docket No. ER97-4166-010).
1. Take notice that a technical conference will be held on January 13 and 14, 2004, from 9:30 a.m. to 4 p.m. in the Commission Meeting Room at the Federal Energy Regulatory Commission, 888 First Street, NW., Washington, DC. As discussed below, the goal of the technical conference is to discuss modifications or alternatives to the Supply Margin Assessment (SMA) interim generation market power screen and related mitigation measures announced in AEP Power Marketing, Inc., et al., 97 FERC ¶ 61,219 at 61,969 (2001), reh'g pending (SMA Order). One or more of the Commissioners may participate in the conference. Additional details about the conference and a conference agenda will be provided in a subsequent notice.
2. In the SMA Order, the Commission announced a new market power screen for generation, the SMA, to be applied to market-based rate applications on an interim basis pending a generic review of new methods for analyzing market power and established mitigation measures applicable to entities that fail the SMA screen. In a Notice Delaying Effective Date of Mitigation and Announcing Technical Conference, issued on December 20, 2001, the Commission deferred the date by which the companies in the above-captioned proceedings or any other public utilities failing the SMA screen must implement the mitigation for spot market energy sales set forth in the SMA Order, and announced its intention to hold a technical conference open to all interested persons, not only parties to the dockets captioned in the SMA Order.
3. On August 23, 2002, the Commission issued a notice establishing Docket No. PL02-8-000, Conference on Supply Margin Assessment, to provide an opportunity for all interested persons to comment. In preparation for the technical conference, the Commission invited all interested persons to submit written comments regarding the SMA screen and related mitigation measures. Those comments were filed on October 22, 2002.
4. In an effort to address concerns raised by commenters regarding the SMA screen and the price mitigation measures contained in the SMA Order, the Commission asked staff to prepare a staff paper identifying possible modifications or alternatives to both the SMA screen and price mitigation measures (such staff paper is set forth in the Attachment to this notice) and to hold a technical conference on these issues. In preparation for the technical conference, the Commission invites all interested persons to submit written comments on the staff paper no later than January 6, 2004. All comments should include an executive summary; the summary shall not exceed five pages. To conserve time and avoid unnecessary expense, persons with common interests or views are encouraged to submit joint comments.
5. Persons interested in participating in the technical conference should be prepared to discuss the proposals in the staff paper. In addition, we encourage interested persons to propose alternative approaches and demonstrate why any such alternatives are improvements to the SMA screen/mitigation measures and the proposals contained in the staff paper. Those proposing alternative approaches, either in their comments or at the conference, should address how their proposal meets data accessibility issues as well as the timing constraints the Commission faces in having to act upon many market-based rate filings within a 60-day statutory period. Finally, persons interested in participating in the technical conference should indicate what principles the Commission should apply in modifying Start Printed Page 75230the SMA, such as what the generation dominance screen should measure, how rigorous the screen should be (e.g., should it examine annual peak or monthly peak), how to factor in internal or external transmission constraints, and whether to look at installed capacity or uncommitted capacity.
6. As noted above, the SMA screen and related mitigation measures were designed as an interim measure for analyzing generation market power pending a generic review of new methods for analyzing markets and market power. The Commission has stated that it intends to launch a generic rulemaking proceeding to address other aspects of its market-based rate program. The purpose of the technical conference will be to pursue what changes, if any, should be made to the SMA screen and to the mitigation measures applicable to entities failing the screen so that the interim screen for generation market power can be finalized and implemented (with mitigation measures where appropriate). Thus, the upcoming conference will be limited to a discussion of the alternative interim screens and mitigation measures.
7. Transcripts of the conference will be immediately available from Ace Reporting Company (202-347-3700 or 1-800-336-6646), for a fee. They will be available for the public on the Commission's e-Library two weeks after the conference. Additionally, Capitol Connection offers the opportunity for remote listening of the conference for a fee. Persons interested in this service should contact David Reininger or Julia Morelli at the Capitol Connection (703-993-3100) as soon as possible or visit the Capitol Connection Web site at http://www.capitolconnection.gmu.edu and click on “FERC.”
8. For more information about the conference, please contact Kermit Banks at 202-502-8217 or Kermit.Banks@ferc.gov.
Filing Requirements for Paper and Electronic Filings
9. Comments, papers, or other documents related to this proceeding may be filed in paper format or electronically. However, the Commission strongly encourages electronic filings. Those filing electronically do not need to make a paper filing.
10. For paper filings, the original and 14 copies of the comments should be submitted to the Office of the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426 and should refer to the above-referenced Docket Nos.
11. Documents filed electronically via the Internet must be prepared in MS Word, Portable Document Format, or ASCII format. To file the document, access the Commission's Web site at www.ferc.gov, click on “E-Filing” and then follow the instructions for each screen. First time users will have to establish a user name and password. The Commission will send an automatic acknowledgement to the sender's e-mail address upon receipt of comments. User assistance for electronic filing is available at 202-502-8258 or by e-mail to firstname.lastname@example.org. Comments should not be submitted to the e-mail address.
12. All written comments will be placed in the Commission's public files and will be available for inspection at the Commission's Public Reference Room, 888 First Street, NE., Washington, DC 20426, during regular business hours.Start Signature
Magalie R. Salas,
Attachment—Staff Paper Technical Conference on Supply Margin Assessment Screen and Alternatives
This paper sets forth Staff options for the Supply Margin Assessment (SMA) or alternative interim generation market power screen in electricity markets, and the appropriate mitigation to impose on those that fail the adopted screen. This paper is intended to serve as a focus for discussion at an upcoming technical conference that will be held on these matters. Staff stresses that the focus of this paper, and of the upcoming technical conference, is the appropriate interim generation market power screen, which is only one prong of the Commission's four-part test in reviewing applications for market-based rates, which examines: (1) Generation (horizontal) market power; (2) transmission (vertical) market power; (3) other barriers to entry; and (4) affiliate abuse. As the Commission has previously stated, it intends to initiate a generic rulemaking proceeding on potential new analytical methods for assessing markets and market power. Thus, the Commission would be positioned to address all aspects of its market-based rate program as part of the generic rulemaking proceeding, while the focus of this paper and technical conference is on just one aspect of that market-based rate program.
In the SMA Order, the Commission announced a new generation market power screen, the Supply Margin Assessment (SMA), to be applied to market-based rate applications on an interim basis pending a generic rulemaking proceeding. Since the markets were evolving, the Commission felt its test for generation market power should also evolve. The SMA screen was to be applied to all sales other than those in independent system operator (ISO) or regional transmission organization (RTO) markets with Commission-approved market monitoring and mitigation.
In a Notice Delaying Effective Date of Mitigation and Announcing Technical Conference, issued on December 20, 2001, the Commission deferred the date by which the companies in the above-captioned proceedings or any other public utilities failing the SMA screen must implement the mitigation for spot market energy sales set forth in the SMA Order, and announced its intention to hold a technical conference open to all interested persons, not only parties to the dockets captioned in the SMA Order.
On August 23, 2002, the Commission issued a notice establishing Docket No. PL02-8-000, Conference on Supply Margin Assessment, to provide an opportunity for all interested persons to comment. In preparation for the technical conference, the Commission invited all interested persons to submit written comments regarding the SMA screen and related mitigation measures. Those comments were filed on October 22, 2002. Concerns expressed in the comments regarding the SMA screen included the conditions and factors that impact available supply when implementing the SMA screen ( e.g., the generation capacity of an applicant that is used to meet native load, pre-existing wholesale contractual obligations, and operating reserves). Commenters also expressed concern about the mitigation measures and their implementation, such as spot market energy sales mitigation. They objected to the split-the-savings requirement and argued that requiring the posting of incremental/decremental cost information would be ineffective and harmful to the competitive market.
In an effort to address concerns raised by commenters regarding the SMA screen and the price mitigation measures contained in the SMA Order, and to provide a framework for the technical conference, the Commission asked Staff to prepare a paper identifying possible modifications or alternatives to both the SMA screen and price mitigation measures.
The purpose of this paper is to outline Staff's current thinking on potential interim generation market power screens and methods for mitigation. While Staff is not recommending one screen over another or a mitigation method over any other, Staff is seeking comments and welcomes suggestions from commenters and technical conference participants.
Persons interested in participating in the technical conference should be prepared to discuss the proposals in this staff paper, and to propose alternative approaches and why any such alternatives are improvements to the SMA screen/mitigation measures and the proposals contained herein.
I. SMA Screen and Mitigation
The SMA screen as adopted by the Commission in the SMA Order assesses whether an applicant has generation market power. In determining the geographic market, the SMA considers transmission constraints into the applicant's respective control area(s). Start Printed Page 75231In determining the size that triggers generation market power concerns, the SMA establishes a threshold based on whether an applicant is pivotal in the market, i.e., whether at least some of the applicant's capacity must be used to meet the market's peak demand. An applicant will be pivotal if its capacity exceeds the market's surplus of capacity above peak demand—that is, the market's supply margin. Thus, an applicant will fail the SMA screen if the amount of its capacity exceeds the market's supply margin.
In applying the SMA screen, the control area market where the applicant is located is first considered. Next, the markets directly interconnected to the applicant's control area market are considered. An applicant will pass the screen if it or its affiliates own or control an amount of generation located in a control area which is less than the supply margin (generation in excess of load) in the control area. The margin will include the amount of generation that can be imported into the control area limited by the total transfer capability (TTC) of the transmission system (i.e., the lesser of uncommitted generation capacity or TTC). Under the Commission's current policy, market-based rate applicants are allowed to sell at market-based rates into any control area where they pass the screen.
All sales, including bilateral sales, into an ISO or RTO with Commission-approved market monitoring and mitigation (PJM, ISO-NE, NYISO, and CAISO) are currently exempt from the SMA and, instead, are governed by the specific thresholds and mitigation provisions approved for the particular markets. At the technical conference, Staff invites comments on whether this exemption should be continued.
Mitigation for Those Failing the SMA Screen
In the SMA Order, the Commission stated that the primary tools for exercising generation market power are physical and economic withholding. To prevent physical withholding, the Commission required that an applicant who fails the SMA screen offer uncommitted capacity (i.e., generation in excess of each hourly projected peak load and minimum required operating reserves) for spot market sales in the relevant market. To prevent economic withholding, this uncommitted capacity would be priced using a split-the-savings formula. The Commission required that an applicant implement split-the-savings pricing for spot market sales and purchases.
The Commission reasoned that applying mitigation to spot market transactions will also result in mitigation of generation market power in longer term (forward) markets by creating a kind of competitive “standard offer” service for customers. If sellers attempt to charge excessive, non-competitive prices in forward markets, customers can avoid them by waiting to purchase in the real-time market. This puts market pressure on sellers to offer competitive prices in the forward markets. And when sellers offer competitive forward prices, many buyers will prefer to purchase in the forward markets in order to gain price certainty. Staff invites comments on the reasonableness of this assumption at the conference.
In the SMA Order, the Commission also imposed additional mitigation on applicants failing the screen. The Commission established mitigation for the size of a pivotal supplier (the Commission required that when a transmission provider performs a study pursuant to a request for interconnection, an unaffiliated entity may request that the output of its proposed project be modeled for study purposes to serve load within the control area in which it is located, without having to formally designate a particular load or without having to be selected as a designated network resource at the time of interconnection). In addition, to address concerns regarding residual transmission market power, the Commission required that the parties to the SMA Order employ an independent third party to operate and administer their OASIS sites. (See 97 FERC at 61,973).
II. Possible Revisions to the SMA Screen
Many commenters were critical of the SMA screen. In particular, some commenters claimed that the SMA screen overstates the amount of an applicant's capacity that is available to the wholesale market by including capacity committed to serve native load and pre-existing contract obligations as well as operating reserves set aside to meet regional reliability requirements. Other commenters raised concerns on the use of TTCs to determine import capability, since they claimed that TTCs may overstate transmission availability, thereby overstating the size of the geographic market to the benefit of market-based rate applicants. Some commenters objected that the SMA passes/fails applicants by using a bright-line standard which is overly narrow because it evaluates one hour's supply and demand, thereby neglecting to recognize non-peak generation market power or the lack thereof.
In response to these comments, Staff has identified for purposes of discussion at the technical conference two general methodologies for assessing generation market power that would constitute modifications to the interim SMA screen as announced in the SMA Order: Pivotal Supplier and Market Share. Among the improvements Staff recommends are that the interim screen should recognize planned generation outages when calculating capacity under the pivotal supplier and market share models discussed below. In addition, Staff recommends that State and Regional Reliability Council operating requirements for reliability (i.e., operating reserves) should be used when calculating capacity in both the pivotal supply and market share screens discussed below.
Staff continues to propose the use of TTCs in applying the interim SMA screen. However, Staff seeks comment on viable alternatives (i.e., flexibility to consider historical firm transactions, losses, and transmission reserve margins affecting available transfer capability). In particular, Staff seeks comment on how much transmission capacity should be included in the analysis where transmission providers (whose control over transmission has not been transferred to an RTO or ISO) calculate the capacity and also participate in generation markets. There are also transmission and other operating constraints inside the control area being evaluated, such that some generators are not able to run to their maximum rated capacity. What percent of these generators' capacity should be included as participating in the market?
Also, to address the commenters' concerns as to the SMA's over reliance on system peak data, options discussed below propose to measure generation market power on a monthly basis. However, Staff solicits the input of technical conference participants as to how the Commission can obtain the data to make such monthly measurements practicable. Migrating to a monthly measurement using the proposed models will require collecting applicant and relevant control area supply and demand monthly information. Monthly data for the supply and the demand for control areas and applicants cannot presently be gathered from a single source. Although supply data could be obtained from the FERC Form No. 714, private or industry data services, and OASIS information, and demand data obtained from the FERC Form No. 714 and FERC Form No. 1, Staff would appreciate suggestions as to what current reporting requirements exist that include necessary data and what reporting requirements may need to be expanded to collect the data, if a monthly measurement is ultimately adopted.
In addition, some commenters contended that the SMA Order was flawed because it lacked clarity and explanation when defining the data that would be used. In response, Staff has developed definitions for the data used in the interim generation market power screens discussed below. These definitions are set forth in Appendix A and Staff seeks comment on the clarity and accuracy of these definitions. Start Printed Page 75232
Possible Alternatives to SMA Screen
A. Pivotal Supply Screen—Capacity Surplus Index (CSI)
The CSI is a Pivotal Supplier screen that is a modified version of, and an alternative to, the SMA. Much like the SMA, the CSI continues the use of a pivotal supplier concept. However, unlike the SMA, rather than considering the applicant's capacity in relation to the supply margin, the CSI eliminates the applicant's capacity from the analysis entirely and only focuses on whether there is sufficient competing supply in the market to meet peak load.
An important refinement of the CSI over the SMA is that under the SMA, the applicant is assumed to have market power in all months if its installed capacity is higher than the supply margin (which is calculated based on the system's peak day). Rather than calculating the supply margin based on the system's peak day, the CSI incorporates monthly data and determines whether the applicant is a pivotal supplier on a monthly basis. With respect to the applicant's control area, the CSI calculation first computes the Control Area Competing Supply (all non-applicant installed capacity, minus planned outages in the control area, plus imports that are the lesser of Uncommitted Capacity or TTC). The Control Area Competitive Supply is then compared to the Control Area Peak Demand (which includes operating reserves). If the Competitive Supply exceeds the Control Area Demand, then the applicant passes the CSI screen. In other words, if there is sufficient competing supply to meet peak load, the applicant passes the CSI; otherwise, it fails. A similar analysis is computed for markets directly interconnected to the applicant's control area market.
Under the CSI, an applicant may be found to be a pivotal supplier in one or more months and found not to be pivotal in other months. The CSI would only impose price mitigation on the applicant in the season(s) in which it was found to be a pivotal supplier. For example, if an applicant is found to be a pivotal supplier (having the ability to exercise generation market power) during the months of July and August but not during the remaining months of the year, the CSI would impose price mitigation on the applicant only during the summer period (June through August).
B. Market Share Screens
Discussed below are two alternatives which incorporate a market share approach in determining whether an applicant has the ability to exercise generation market power. The Limited Competing Supplier screen assesses both installed and uncommitted capacity. The Wholesale Market Share screen only assesses uncommitted capacity.
Unlike the Pivotal Supplier concept which determines whether a seller's generation must run to meet peak load, Market Share Screens measure whether a seller has a dominant position in the market based on the number of megawatts of capacity owned or controlled, i.e., is the applicant's control of the market excessive compared to competitive supplies. To the extent this is true, the applicant would have generation market power. Under the Market Share Screens, an applicant may be found to be dominant in the market in one or more months and found not to be dominant in the market in other months. Just like the CSI, the Market Share Screens would only impose price mitigation on the applicant in the season(s) in which it was found to be dominant in the market.
1. Limited Competing Supplier Screen. This generation market power screen directly considers the impact of transmission constraints. As proposed, the Limited Competing Supplier Screen examines the applicant's installed and uncommitted capacity. Under this screen, available transmission (measured by TTC) will be factored in from OASIS sites and into the analysis of the applicant's market share of both installed and uncommitted capacity.
Under the installed capacity element of this screen, the applicant's market share is derived by dividing its installed capacity by the sum of the total installed capacity of all suppliers in that control area plus the generation that can be imported (as limited by TTC). Under the uncommitted capacity element of this screen, the applicant's market share is derived by dividing its uncommitted capacity  by the sum of the total uncommitted capacity of all suppliers in that control area plus the generation that can be imported (as limited by TTC).
If the applicant's market share is less than 20% for the month, applicant passes the generation market screen and would be authorized to sell at market-based rates. If the applicant's market share is greater than 35%  for the month, then applicant fails this generation market power screen. If the applicant's market share is between 20% and 35%, the Commission could consider other factors in granting/denying market-based rate authority (e.g., transmission constraints). Staff seeks comments on what other factors the Commission should consider.
2. Wholesale Market Share (WMS). As noted above, the Limited Competing Supplier Screen examines the applicant's installed and uncommitted capacity. Many commenters were critical of using committed generation in determining market power. They contended that it is not possible for a utility to exercise market power over its regulated native load for two primary reasons: 1) state regulation removes the ability of a utility with significant native load responsibilities to exercise market power; and 2) a utility would lack any incentive to exercise market power from its regulated generation because its native load pays a regulated price.
An alternative generation market power screen that may address these concerns by more narrowly focusing dominance in the wholesale market is the Wholesale Market Share (WMS) screen. Like the Limited Competing Supplier Screen, this WMS screen would consider market share, but only for uncommitted capacity for the wholesale market. The intent of this model is to isolate the wholesale supply by first capturing the size of supply and demand for the entire relevant market, and then removing the supply serving retail demand and retail demand itself from the total (and the respective operating reserves.) This would isolate wholesale supplies and demand for a market share analysis. The WMS is calculated by measuring, on a monthly basis, an applicant's market share of uncommitted capacity relative to the market's total uncommitted capacity. Issues needing discussion at the technical conference are the ability of the applicant and vertically integrated utilities to segregate wholesale opportunity sales from retail sales and the reasonableness of seeking to isolate wholesale and retail supplies.
In the relevant geographic market for the WMS, an applicant's market share is determined by dividing the applicant's uncommitted capacity by that of the total uncommitted capacity in the relevant market. The applicant's uncommitted capacity is calculated by taking the applicant's total installed capacity (nameplate capacity plus firm purchases) less planned outages, native load, long-term sales, and operating reserves. An applicant's uncommitted capacity represents its control of resources available for wholesale trade within the relevant market. The relevant market's uncommitted capacity is determined by taking the total control area installed capacity, plus competing supplies which could be imported from adjacent control areas (such imports are assumed to be the lesser of uncommitted capacity or TTC), less peak load (native & long-term sales) and operating reserve margins.
Like the Limited Competing Supplier Screen, the WMS uses 20% to 35% pass/fail thresholds as discussed above.
III. Alternative Models Suggested by Commenters
Three commenters proposed alternative models to the SMA for consideration.
- Reliant proposed the Supply Duration Index (SDI). The SDI first calculates the sum of generation available from non-applicants, imported power, the applicant's committed forward contracts and new generation, and the applicant's existing uncommitted generation. Next, the SDI considers the firm load duration curve in percentage terms over the course of a year. For some period of time during the year, the sum of all available committed generation may be less than the firm load demanded. When this occurs, the SDI screen assumes that this firm load can Start Printed Page 75233only be supplied by the applicant's uncommitted generation resources. This represents a time when the applicant may have the potential to exercise market power. While this model is interesting, the data needed to verify the applicant and control area information is not readily available (hourly data). However, in the alternatives discussed below, many of the aspects of the SDI (i.e., pivotal supplier concept) have been incorporated.
- CAISO proposed the Residual Supplier Index (RSI). The RSI determines if a supplier is pivotal during a specified set of hours or all hours, i.e., without the applicant's supply the market demand cannot be met. Because applying a model down to the hour creates insurmountable data and administrative difficulties, this model is not practical. In particular, obtaining hourly data for markets outside of an organized market is not practical nor is monitoring such markets on an hourly basis. However, some of the critical concepts of the model have been incorporated into the Capacity Surplus Index (CSI) screen.
- Lastly, Old Dominion Electric Cooperative proposed the Market Simulation Analysis. This modeling technique attempts to simulate market conditions using loadflow algorithms which identify parallel/looping power flows, and seasonal variations. While such models can identify load pockets, daily and seasonal variations, and may provide a more precise measure of generation market power, such models require extensive data from all market participants (including small merchants), could take up to 9 months or more to create, and it is unclear how such a model would be applied on a case-by-case basis. Accordingly, Staff does not consider this alternative to be viable as an interim generation market power screen.
IV. Possible Revisions to the SMA Mitigation
With respect to the SMA mitigation measures, among other things, many commenters object to the spot market energy sales mitigation, and in particular to the split-the-savings requirement. Commenters also oppose as ineffective and harmful to the competitive market the requirement to post incremental/decremental cost information.
Set forth below are alternative mitigation approaches for discussion at the technical conference that address many of the concerns expressed by commenters. In each approach, Staff proposes that the mitigation being considered be applied seasonally. If the applicant fails any month of a season, it would thus be mitigated for the entire season (but only that season).
In addition, to address some commenters' concerns, applicants that fail the screen, to the extent necessary, could be required to file incremental and decremental cost information only with the Commission on a confidential basis.
A. Traditional Cost-based Rate
This alternative would require mitigated sellers to have on file an up to rate or a cost-based rate for periods when they are mitigated. The cost-based rate could be based on an average cost of the units expected to run to meet peak demand with an annual revenue cap, or an average system or regionwide rate could be established.
B. Single Market Clearing Price
Under the single market clearing price approach, all transactions of the failing applicant would be executed at a single market clearing price instead of at multiple split-the-savings prices. The applicant would still be required to provide its own 24 hourly incremental and decremental energy costs by noon for the following trading day. The incremental costs would represent offers to sell and the decremental costs would represent bids to buy energy during each hour of the trading day. All additional requests to purchase and offers to sell energy that are received by 6 p.m. for the following trading day would, in combination with the applicant's bids and offers, be used to determine a market clearing price for energy in each hour of the trading day. The market clearing price for any hour would be a price that corresponds to a total quantity of energy that just balances the accepted supply offers with the accepted purchase bids. That is, it is a price that is at least as great as any accepted supply offer and is no higher than any accepted purchase bid. It is also a price at which no entities whose bids and offers were not accepted would be willing to transact.
Appendix A—Data Definitions
The following definitions are recommended for use in the proposed generation market power screens.
Applicant's Peak Demand—Represents the largest electric power requirement (based on net energy for load) during a specific period of time, usually integrated over one clock hour and expressed in megawatts, for the Native Load and Firm Sales that the applicant has an “obligation to serve”.
Applicant's Total Capacity—Represents the applicant's and their affiliate's installed generation nameplate capacity, adjusted for seasonal deratings, plus firm purchases.
Applicant's Uncommitted Capacity—This calculation takes the applicant's installed capacity and subtracts the applicant's planned outages and the peak demand and operating reserves; which then isolates the amount of capacity that is available for wholesale competition. The calculation follows:
Total Applicant Capacity (including imports)
—Applicant Uncommitted Capacity
Control Area Peak Demand—For the control area, this represents the largest electric power requirement (based on net energy for load) during a specific period of time, usually integrated over one clock hour and expressed in megawatts, for the native load and firm sales that are under an “obligation to serve”.
Control Area Uncommitted Capacity—This calculation takes the total control area capacity, adds imports and subtracts the planned outages and the peak demand and operating reserves; which then isolates the amount of capacity that is available for wholesale competition. The calculation follows:
Total Control Area Capacity
Control Area Uncommitted Capacity
Imports—The lesser of either the uncommitted capacity (Installed capacity less peak load and operating reserves) from each adjacent control area or the total transfer capability between each Adjacent Control Area.
Installed Capacity—Total generating resources (installed generation plus firm purchases).
Operating Reserves—Any operating reserves the applicant is required to carry by NERC regional reliability councils or by their state utility regulatory commissions to ensure system reliability. To accommodate this operating requirement, each applicant will submit and support the amount of operating reserves that are mandated.
Planned Outages—Refers to generators that are normally in an operating or stand-by status, but are derated or unavailable due to routine service or planned maintenance.
Relevant Geographic Market—The control area in which the applicant owns the bulk of its generation and the interconnected control areas adjacent to that control area.
Total Control Area Capacity—Total capacity capability for the control area, includes installed generation and firm purchases.End Preamble
1. SMA Order, 97 FERC ¶ 61,219 at 61,967.Back to Citation
2. SMA Order, 97 FERC ¶ 61,219 at 61,967.Back to Citation
3. See AEP Power Marketing, Inc., et al., 97 FERC ¶ 61,219 at 61,967 (2001) (SMA Order).Back to Citation
4. As the Commission explained in the SMA Order, the total amount of TTC is used as only a point of reference to establish the maximum amount of uncommitted generation supply, even though this amount of generation could not be simultaneously imported into an applicant's control area. The Commission stated in the SMA Order that intervenors will be allowed to present arguments on a case-by-case basis that another factor limiting import capability is appropriate, if warranted by the facts.Back to Citation
5. A seller's incremental cost (the out-of-pocket cost of producing an additional MW) is compared with a buyer's decremental cost (the cost of not producing the last MW). The average of the incremental and decremental costs is the split-savings price. The details of how split-the-savings pricing was to be implemented are described in the SMA Order. See 97 FERC at 61,971-73.Back to Citation
6. For purposes of this paper, spot market sales are intended to include only hourly transactions.Back to Citation
7. Although several alternative screens were proposed by commenters (which are summarized below), Staff is not focusing on them at this time because of the intensive data requirements associated with these screens that would make them burdensome and costly for many applicants, and would be administratively difficult for Staff to review and perform in the 60-day statutory time period.Back to Citation
8. Although the generation market screens are applied on a monthly basis, mitigation could be on a seasonal basis. These screens take a snap shot in time, therefore, the month in which companies pass/fail may vary (within the season). Accordingly, to capture the broader time period where market power may exist, seasonal mitigation could be adopted. See note 13.Back to Citation
9. See note 13.Back to Citation
10. Applicant's uncommitted capacity is calculated by taking the applicant's installed capacity (generation owned or controlled by applicant) less planned outages, native load, long-term sales, and operating reserves. The same type of calculation is used when determining the amount of uncommitted capacity of competitive supplies.Back to Citation
11. A ceiling of 35% is consistent with the Department of Justice's safeharbor threshold, per the 1992 Horizontal Merger Guidelines, Section 2.211.Back to Citation
12. Comments of Reliant Resources, Inc., pages 5-8.Back to Citation
13. Comments of the California Independent System Operator Corporation, pages 13-18.Back to Citation
14. Comments of Old Dominion Electric Cooperative, pages 8-10.Back to Citation
15. The four seasons considered are: Summer (June/July/August); Fall (September, October, November); Winter (December/January/February), and Spring (March/April/May).Back to Citation
16. In lieu of disclosing this information publicly, the mitigated applicant could be required to provide the Commission on a confidential basis with all relevant information that supports the clearing price.Back to Citation
[FR Doc. E3-00652 Filed 12-29-03; 8:45 am]
BILLING CODE 6717-01-P