FERC Staff Investigations on Midwest and Southeast Bulk Power ,
 ----- Forwarded by Jeff Dasovich/NA/Enron on 11/15/2000 04:09 PM -----

	Ginger Dernehl
	11/10/2000 03:38 PM
		 
		 To: Mark Palmer/Corp/Enron@ENRON, Eric Thode/Corp/Enron@ENRON, Karen 
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		 cc: 
		 Subject: FERC Staff Investigations on Midwest and Southeast Bulk Power 
Systems


	Christi L Nicolay@ECT
	11/10/2000 03:22 PM
		 
		 To: Ginger Dernehl/NA/Enron@Enron
		 cc: 
		 Subject: FERC Staff Investigations on Midwest and Southeast Bulk Power 
Systems

Please forward this to Rick's group.  Thanks.

Please note that these FERC staff reports contain some potentially helpful 
information that can be used at the state PUC level, including information on 
the increase in generation in the Midwest that market participants attribute 
to lack of price caps following the summer 1998 price spikes; better 
preparation for summer 2000 through the use of forward contracts and 
transmission problems that may have resulted in keeping cheaper power from 
particular markets.


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
robert.hemstock@enron.com