Message-ID: <12724288.1075841862047.JavaMail.evans@thyme> Date: Fri, 10 Nov 2000 05:46:00 -0800 (PST) From: mary.hain@enron.com To: portland.desk@enron.com Subject: FERC Staff Investigations on Midwest and Southeast Bulk Power Systems Cc: christi.nicolay@enron.com, charles.yeung@enron.com, sarah.novosel@enron.com, donna.fulton@enron.com, james.steffes@enron.com Mime-Version: 1.0 Content-Type: text/plain; charset=us-ascii Content-Transfer-Encoding: 7bit Bcc: christi.nicolay@enron.com, charles.yeung@enron.com, sarah.novosel@enron.com, donna.fulton@enron.com, james.steffes@enron.com X-From: Mary Hain X-To: Portland West Desk X-cc: Christi Nicolay, Charles Yeung, Sarah Novosel, Donna Fulton, Joe Hartsoe@Enron, James D Steffes X-bcc: X-Folder: \kate symes 6-27-02\Notes Folders\Ferc X-Origin: SYMES-K X-FileName: kate symes 6-27-02.nsf See attached summary for some excellent FERC decisions thanks to regulatory affairs in Houston and D.C. Given that FERC appears to be applying some of these decisions to all utilities in these regions, I would assume we could argue that the FERC requirements should apply in the West too. ---------------------- Forwarded by Mary Hain/HOU/ECT on 11/10/2000 01:48 PM --------------------------- To: Richard Shapiro/NA/Enron@Enron, Sarah Novosel/Corp/Enron@Enron, Joe Hartsoe/Corp/Enron@Enron, Jeff Brown/NA/Enron@Enron, Bill Rust/HOU/ECT@ECT, Ben Jacoby/HOU/ECT@ECT, Kevin M Presto/HOU/ECT@ECT, Mike J Miller/HOU/ECT@ECT, John Moore/Corp/Enron@Enron, Debbie Chance/Corp/Enron@Enron, Patrick Hanse/HOU/ECT@ECT, Fletcher J Sturm/HOU/ECT@ECT, Rogers Herndon/HOU/ECT@ect, Edward D Baughman/HOU/ECT@ECT, Tom Dutta/HOU/ECT@ECT, Ozzie Pagan/HOU/ECT@ECT, Tom Hoatson/NA/Enron@Enron, Janine Migden/NA/Enron@Enron, Steven J Kean/NA/Enron@Enron, Marchris Robinson/NA/Enron@Enron, John Moore/Corp/Enron@Enron, Bill Moore/NA/Enron@Enron, Robin Kittel/NA/Enron@Enron, Jeffrey M Keenan/HOU/ECT@ECT, Richard Ingersoll/HOU/ECT@ECT, Charles Yeung/HOU/ECT@ECT, Shelley Corman/ET&S/Enron@ENRON, Rogers Herndon/HOU/ECT@ect, Lloyd Will/HOU/ECT@ECT, Maria Valdes/Corp/Enron@Enron, James D Steffes/NA/Enron@Enron, Harry Kingerski/NA/Enron@Enron, Bob Carter/HOU/ECT@ECT, Chris Gaffney/HOU/ECT@ECT, Barton Clark/HOU/ECT@ECT, Sheila Tweed/HOU/ECT@ECT, Oscar Dalton/HOU/ECT@ECT, Dave Mangskau/Corp/Enron@Enron, Kerry Stroup/DUB/EES@EES, Greg Krause/Corp/Enron@Enron, Raimund Grube/Corp/Enron@ENRON, David L Fairley/HOU/ECT@ECT, Janet R Dietrich/HOU/ECT@ECT, Steve Krimsky/Corp/Enron@Enron, Richard Lydecker/Corp/Enron@Enron, Mary Hain/HOU/ECT@ECT, Fred Mitro/HOU/ECT@ECT, Janet R Dietrich/HOU/ECT@ECT, Richard Lydecker/Corp/Enron@Enron, Tom Chapman/HOU/ECT@ECT, Tom Delaney/Corp/Enron@ENRON, Steve Walton/HOU/ECT@ECT, Kay Mann/Corp/Enron@Enron, Rebecca Walker/NA/Enron@Enron, Reagan Rorschach/NA/Enron@Enron, John Berger/HOU/EES@EES, Alan Larsen/PDX/ECT@ECT, Rusty Stevens/Corp/Enron@ENRON, Dave Kellermeyer/HOU/ECT@ECT, Mathew Gimble/HOU/ECT@ECT, Ron Tapscott/HOU/ECT@ECT, Michelle Zhang/HOU/ECT@ECT, Susan M Landwehr/NA/Enron@Enron, Roy Boston/HOU/EES@EES, Aleck Dadson/TOR/ECT@ECT, Joe Connor/NA/Enron@Enron, Ron McNamara/NA/Enron@Enron, Robin Kittel/NA/Enron@Enron, Karen E Carter/NA/Enron@Enron, Chris Booth/NA/Enron@Enron, Steve Montovano/NA/Enron@Enron, Barbara N Gray/HOU/ECT@ECT, steve.wang@enron.com, ebaughm@enron.com, terri.clynes@enron.com, oscar.dalton@enron.com, doug.sewell@enron.com, kcompea@enron.com, mike.e.kelly@enron.com, gary.justice@enron.com, patrick.hanse@enron.com, ozzie.pagan@enron.com, heather.kroll@enron.com, david.fairley@enron.com, ray.hoppe@enron.com, george.mccormick@enron.com, wjennin@enron.com, joseph.wagner@enron.com, elizabeth.johnston@enron.com, bill.rust@enron.com, Kevin M Presto/HOU/ECT@ECT, John J Lavorato/Corp/Enron@Enron, David W Delainey/HOU/ECT@ECT, Janet R Dietrich/HOU/ECT@ECT, Mike J Miller/HOU/ECT@ECT, Lloyd Will/HOU/ECT@ECT, George Hopley/HOU/ECT@ect, Fletcher J Sturm/HOU/ECT@ECT, Robert Benson/Corp/Enron@ENRON, Jeff King/Corp/Enron@Enron, Larry Valderrama/HOU/ECT@ECT, Peter Makkai/NA/Enron@Enron, Larry Jester/Corp/Enron@ENRON, Rogers Herndon/HOU/ECT@ect, Mike Carson/Corp/Enron@Enron, Kyle Schultz/HOU/ECT@ECT, Eric Saibi/Corp/Enron@ENRON, Grace Kim/NA/Enron@Enron, Laura Podurgiel/HOU/ECT@ECT, Mitch Robinson/Corp/Enron@Enron, Kayne Coulter/HOU/ECT@ECT cc: James D Steffes/NA/Enron@Enron Subject: FERC Staff Investigations on Midwest and Southeast Bulk Power Systems On 11/1/00, FERC Staff issued reports on its Investigation of Bulk Power Markets in the Eastern Interconnection. These reports were the result of a Commission order earlier this summer. Enron's Federal regulatory staff (Christi, Charles Yeung, and Sarah Novosel) provided a great deal of information for this investigation and Joe Hartsoe and Donna Fulton discussed many of the problems with the grid with the new head of Staff, Scott Miller (who recently joined FERC from PG&E Gen). While the Commission is under no obligation to take any of Staff's recommendations, the Commission typically looks to Staff for guidance on transmission and market issues. Importantly, Staff concludes that the Commission should consider these options for the Southeast and Midwest -- all of which Enron has been asking FERC to implement for several years: Reduce the advantages of network service over point to point service by requiring that native load be served under the same tariff as other transmission services to eliminate the current incentives that VIUs have to favor their native load through the calculation of ATC and handling of interconnection requests. While the Staff Hotline is used productively, the Commission can direct Staff to conduct formal investigations into entities that have a pattern of complaints. The Commission could require TPs to submit tariff provisions containing a pro forma interconnection process specific to interconnection, rather than simply relying on the Tennessee Power order that utilizes the OATT timelines and procedures. Require TPs to retain real-time transmission data on market functions pertaining to daily load, internal generation to meet that load, and imports and exports. RTOs should submit the basis and methods for calculating ATC and TTC, as well as standardized criteria for curtailment. In addition, since even such standardized criteria might not "get to the root of the problem" -- that control area still control generation -- the Commission could require that each RTO set a date certain by which it will create one control area. Regardless of the implementation of these two options, the Commission could standardize ATC and TTC methodology. Staff finds that while electricity is a commodity with market characteristics similar to many other commodities, it is still viewed as "different," with a reaction of price caps. Staff encourages that basic decisions about the regulatory model be made in order to complete the transition from a traditional cost-of-service model to a model that uses markets to price the commodity and services. DETAILS (Also, the reports contain good summaries of the generation, transmission, state retail, federal reg. and other issues for the region): Midwest: The Midwest is dominated by vertically integrated Transmission Providers ("TPs") that control transmission, generation and load. "As such, they have weak economic incentives to provide access to transmission service to third-parties and strong incentives to favor their own services." Staff received numerous complaints; however, due to the lack of information available from TPs, Staff cannot conclude whether these are isolated incidents or wide-spread. At the very least, the complaints indicate a lack of confidence in the bulk power market and the ability of market participants to rely on transmission access, thus harming the liquidity of the market. TLRs are the most important transmission issue in the Midwest, with an "enormous" increase in 2000. The region showed a decline in peak load from 1999 to 2000 and a growth in new generation since the 1998 price spikes. Even though there was an increase in generation and mild weather with virtually no price spikes, TLRs climbed to record numbers. The TLRs were highly concentrated: only 5 flowgates account for 41% of ECAR TLRs and another 5 flowgates in MAIN account for 42% in that region. Notably, even though the NERC procedures for Level 3 TLRs mandate transaction curtailment, 78 of the 191 TLRs in the Midwest do not show any curtailment amount. The total amount of relief that these curtailments are intended to produce are not posted. Staff notes that TLR rules are established by NERC, whose procedures are voluntary and not enforced by penalties. While the Commission has required certain NERC standards and procedures to be placed in Open Access Transmission Tariffs ("OATT") where the Commission has the power to enforce provisions under the Federal Power Act, in practice the Commission has generally deferred to NERC on transmission reliability questions, including the propriety of TLRs. TLRs inhibit optimal functioning of the transmission system and market because load is not served by the least cost supplier. TLR procedure is an inefficient instrument in mitigating constraints -- curtailment by fiat. In addition, the NERC IDC can result in inappropriate curtailments or increased loading on the affected flowgate. The impact could be mitigated by one control area per RTO. Staff notes that the Midwest state commissions did not petition FERC for price caps following the 1998 price spikes. Some market participants believe that the absence of price spikes is the single reason that NUG construction increased in the Midwest. Market participants must keep track of, and follow, a plethora of information in order to make energy deals, submit reservations and provide schedules for service. Staff received many complaints about barriers to transmission access, including TLR curtailments and a lack of standardized information and protocols, particularly for ATC and interconnection requests, and discriminatory conduct. Unbelievably, key data was unavailable to Staff, such coincident peak load data, system-wide snap shots for days when TLRs were called, and import/export data. This lack of data creates a market inefficiency, because neither market participants nor regulators can fully analyze market conditions in real time. As such, the market is risk adverse, eschewing long-term deals for short-term transactions. Staff also noted that because the Security Coordinators often work for the IOU, there is a mixed incentive to enforce reliability on the grid and maximize profit for the IOU. (Staff cites Richard Tabors' paper, "Transmission Markets, Stretching the Rules for Fun and Profit.") Staff cites the lack of information on OASIS or on the NERC web site, particularly about real time TLRs and curtailments. Examples were provided to Staff of transmission refusals when there were no TLRs posted and improper implementation of TLRs causing substantial financial loss. The currently proposed Midwest RTOs may mitigate some problems; however, all three retain existing control areas with the favortism for generation and native load. These incentives will continue to remain until the RTO exercises complete autonomy over transmission control and security coordinator functions. Staff notes that the Midwest is a balkanized region of 61 control areas with no uniform method for calculating ATC and CBM. The result is that ATCs can be different on 2 different sides of an interface. Staff notes examples in inaccurate ATCs and states that Staff's own ATC audit this summer was consistent with market participant complaints. Staff is weighing follow-up options. The result of these problems is a lack of liquidity. Staff next noted the problems with unfiled "business practices," especially on the next hour market. Staff's audit of OASIS sites revealed several areas of non-compliance. Information transparency is necessary for a market to function efficiently, with equal and timely access to data, including ATC, CBM, TRM, and load flow input data. TPs have incentives to resist efforts to make this information transparent because of native load. This incentive will still exist under RTOs if utilities are allowed to calculate their own ATC. *** "As a consequence, the Commission may wish to eliminate the native load exemption and have all transactions under the same tariff." *** The Commission could benefit by having access to existing transmission data and should require the TPs to retain data, including current real-time network status. Interconnection Issues: IPPs need to be compensated for VAR support. Also, Staff cites a number of Hotline complaints about TPs seeking large deposits or failing to complete System Impact Studies timely. One solution is to have the RTO handle this function to eliminate the disincentive the utilities have against IPPs. The current practice of requiring IPPs to deal with a wide variety of procedures inhibits the free flow of transactions within the region. Network service has inherent advantages over point-to-point, citing the Entergy source and sink order. The Commission has relied on "passively" receiving informal and formal complaints to determine if discriminatory behavior has occurred rather than actively canvassing market participants. While Staff cannot conclude that discriminatory practices are widespread, there is evidence of discriminatory instances. Southeast: The traditional vertically integrated utility ("VIU") model has largely persisted in the SE. This continued control has vastly reduced the economic incentives to facilitate IPP activities. In many cases, the VIUs have dampened IPP involvement without violating any Commission regulation due to the inherent flexibility of the current rules. Staff cites examples of delays in performing system impact studies, transmission hoarding in the name of serving native load growth and manipulation of ATC. TPs have shown little inclination to improve the transmission system and use many TLRs. There is also a lack of market information that has stymied the development of markets in the SE. ATCs change constantly that leads to uncertainty and there is no clearinghouse for electric power prices. TVA, despite having taken steps to participate in reformed markets, has acted as a bulwark against the development of competitive energy markets in the SE. This is significant because of TVA's size and location. IPPs have reported TVA's discouragement of siting in TVA through excessive time to perform studies, excessive fees, and rejection of requests to perform interconnection studies. In addition, Staff cites the Florida Sup. Ct. decision against merchant plants as significantly impeding the competitive market in Florida. Staff discusses the significant flow of power from the Midwest to the SE this summer. Much of this resulted from the import of cheaper coal power, than the use of gas fired peakers due to higher gas prices. Peak prices were radically lower this summer because utilities appear to have been better prepared for peak events through the use of forward contracts, increased generation capacity on line and reduced number of forced outages. SE utilities reported that they have not used market-based rates to extensively increase sales. (Less used than in the midwest.) The SE region lacks information, which has retarded the Staff's efforts to discern the truth about the numerous complaints about transmission in the SE (including ATC and TLRs). Market participants seem to have less confidence in the SE market than in any other market region. This appears to be justified based on Staff's investigations. This lack of confidence discourages investment and participation in the markets. Staff concludes that the Commission may need to be more prescriptive in terms of how transmission is allocated in the SE RTOs, since there are market concerns that the incumbents will continue to dominate operations. The investigation found numerous problems in bad ATCs and TTCs and poor OASIS postings. In addition, several OASIS audit logs actually erased historical data. Staff thinks that additional affiliate transaction information should be posted. Staff could not obtain summer demand data and the Commission's lack of jurisdiction over TVA made it difficult to obtain transmission access information. The Staff investigation revealed unclear interconnection procedures and lack of adherence to schedules and arbitrary cost estimates and deposits. In addition, the TPs have reserved a huge amount of network transmission capacity, much of it reserved shortly after the IPP approached the TP to interconnect. Staff cites the recent Skygen order in which Southern denied Skygen's request for transmission stating that the only option was the construction of an 80 mile 500 kv line that would take 8 years to complete. Staff solutions include allowing network requests by IPPs and limiting self-build capacity in the incumbent's territory. ATC variations are a big problem in the SE. SERC coordination of a standardized ATC is a long process and may not be resolved soon without direction from the Commission. An improved method and improved communication are needed. The SE experienced a 354% increase in TLRs this summer. This increase raises the issue of whether curtailment has become an impediment to the competitive operation of the market in the SE. Staff cites information provided by Charles Y. that an Ameren TLR was not implemented according to NERC criteria. Staff also wonders if transmission is being oversold since TPs do not generally refund transmission revenues when TLRs are implemented. RTOs must have a broad geographic area to internalize much of the constraints. In addition, RTOs will adopt pricing mechanisms that obviate recourse to TLRs. However, if control areas are retained, VIUs will retain mixed incentives. *** As noted in the Midwest report, the manner in which load is calculated weighs heavily on the value of this information. This is an issue that the formation of RTOs may not resolve. Eliminating native load exceptions -- ie, treating all load equally -- and placing all transactions under the same tariff may be an option that provides the right incentives for the provision of transparent and standardized information. Finally, Staff describes specific problems with TVA and FP&L, TVA is a "problem area" for the Eastern Interconnect grid. TVA is a transmission bottleneck due to the many TLRs called this summer. The current federal law and lack of Commission jurisdiction are impediments to the development of deep and robust power markets in this area. TVA simply has no strong incentive to provide effective and efficient transmission service. In addition, the Commission does not have full information on TVA. Staff lists a number of complaints against TVA, including unjustifiably increasing the tag deadline and allowing TVA Marketing, but not others, to sink and park power. Staff concludes that recent proposals by TVA to enhance the development of markets and its system do not appear to have great potential. A Staff audit of FP&L revealed violations of standards of conduct, including confidential information on FP&L's transmission system (including interchange information for other entities) posted on EMS systems that were available to FPL's merchant function. Staff's report found that FP&L does not have an established procedure for review of EMS to ensure that information is not displayed in error. It is "up to individual Managers discretion." ((FRCC web site report dated 9/8/00)). Violations such as these undermine competition. The reports are attached below. - southeast.pdf - midwest.pdf