Message-ID: <32871126.1075846360022.JavaMail.evans@thyme>
Date: Wed, 6 Dec 2000 01:03:00 -0800 (PST)
From: christi.nicolay@enron.com
To: steven.kean@enron.com, richard.shapiro@enron.com, james.steffes@enron.com,
linda.robertson@enron.com, david.delainey@enron.com,
john.lavorato@enron.com, kevin.presto@enron.com,
joe.hartsoe@enron.com, lloyd.will@enron.com,
mitch.robinson@enron.com, donna.fulton@enron.com,
sarah.novosel@enron.com, sherri.sera@enron.com,
maureen.mcvicker@enron.com, kay.chapman@enron.com,
kimberly.hillis@enron.com, ginger.dernehl@enron.com,
bernadette.hawkins@enron.com, lora.sullivan@enron.com
Subject: **For the FERC staff lunch 12/7--FERC Investigation summaries
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***BELOW ARE SUMMARIES OF THE HELPFUL FERC STAFF INVESTIGATIONS LEAD BY SCO=
TT=20
MILLER (WHO REPORTS TO DAN LARCAMP) -- BOTH WILL JOIN THE ENRON EXECUTIVES =
AT=20
LUNCH THURS. 12/7.
-
MIDWEST AND SOUTHEAST SUMMARIES
On 11/1/00, FERC Staff issued reports on its Investigation of Bulk Power=20
Markets in the Eastern Interconnection. These reports were the result of a=
=20
Commission order earlier this summer. Enron's Federal regulatory staff=20
(Christi, Charles Yeung, and Sarah Novosel) provided a great deal of=20
information for this investigation and Joe Hartsoe and Donna Fulton discuss=
ed=20
many of the problems with the grid with the new head of Staff, Scott Miller=
=20
(who recently joined FERC from PG&E Gen). While the Commission is under =
no=20
obligation to take any of Staff's recommendations, the Commission typically=
=20
looks to Staff for guidance on transmission and market issues. Importantly=
,=20
Staff concludes that the Commission should consider these options for the=
=20
Southeast and Midwest -- all of which Enron has been asking FERC to impleme=
nt=20
for several years:
Reduce the advantages of network service over point to point service by=20
requiring that native load be served under the same tariff as other=20
transmission services to eliminate the current incentives that VIUs have to=
=20
favor their native load through the calculation of ATC and handling of=20
interconnection requests.
While the Staff Hotline is used productively, the Commission can direct Sta=
ff=20
to conduct formal investigations into entities that have a pattern of=20
complaints.
The Commission could require TPs to submit tariff provisions containing a p=
ro=20
forma interconnection process specific to interconnection, rather than simp=
ly=20
relying on the Tennessee Power order that utilizes the OATT timelines and=
=20
procedures.
Require TPs to retain real-time transmission data on market functions=20
pertaining to daily load, internal generation to meet that load, and import=
s=20
and exports.
RTOs should submit the basis and methods for calculating ATC and TTC, as we=
ll=20
as standardized criteria for curtailment. In addition, since even such=20
standardized criteria might not "get to the root of the problem" -- that=20
control area still control generation -- the Commission could require that=
=20
each RTO set a date certain by which it will create one control area. =20
Regardless of the implementation of these two options, the Commission could=
=20
standardize ATC and TTC methodology.
Staff finds that while electricity is a commodity with market characteristi=
cs=20
similar to many other commodities, it is still viewed as "different," with =
a=20
reaction of price caps. Staff encourages that basic decisions about the=20
regulatory model be made in order to complete the transition from a=20
traditional cost-of-service model to a model that uses markets to price the=
=20
commodity and services. =20
DETAILS (Also, the reports contain good summaries of the generation,=20
transmission, state retail, federal reg. and other issues for the region):
Midwest: The Midwest is dominated by vertically integrated Transmission=20
Providers ("TPs") that control transmission, generation and load. "As such=
,=20
they have weak economic incentives to provide access to transmission servic=
e=20
to third-parties and strong incentives to favor their own services." Staff=
=20
received numerous complaints; however, due to the lack of information=20
available from TPs, Staff cannot conclude whether these are isolated=20
incidents or wide-spread. At the very least, the complaints indicate a lac=
k=20
of confidence in the bulk power market and the ability of market participan=
ts=20
to rely on transmission access, thus harming the liquidity of the market. =
=20
TLRs are the most important transmission issue in the Midwest, with an=20
"enormous" increase in 2000. The region showed a decline in peak load from=
=20
1999 to 2000 and a growth in new generation since the 1998 price spikes. =
=20
Even though there was an increase in generation and mild weather with=20
virtually no price spikes, TLRs climbed to record numbers. The TLRs were=
=20
highly concentrated: only 5 flowgates account for 41% of ECAR TLRs and=20
another 5 flowgates in MAIN account for 42% in that region. Notably, even=
=20
though the NERC procedures for Level 3 TLRs mandate transaction curtailment=
,=20
78 of the 191 TLRs in the Midwest do not show any curtailment amount. The=
=20
total amount of relief that these curtailments are intended to produce are=
=20
not posted. Staff notes that TLR rules are established by NERC, whose=20
procedures are voluntary and not enforced by penalties. While the Commissi=
on=20
has required certain NERC standards and procedures to be placed in Open=20
Access Transmission Tariffs ("OATT") where the Commission has the power to=
=20
enforce provisions under the Federal Power Act, in practice the Commission=
=20
has generally deferred to NERC on transmission reliability questions,=20
including the propriety of TLRs.
TLRs inhibit optimal functioning of the transmission system and market=20
because load is not served by the least cost supplier. TLR procedure is an=
=20
inefficient instrument in mitigating constraints -- curtailment by fiat. I=
n=20
addition, the NERC IDC can result in inappropriate curtailments or increase=
d=20
loading on the affected flowgate. The impact could be mitigated by one=20
control area per RTO.
Staff notes that the Midwest state commissions did not petition FERC for=20
price caps following the 1998 price spikes. Some market participants belie=
ve=20
that the absence of price spikes is the single reason that NUG construction=
=20
increased in the Midwest. =20
Market participants must keep track of, and follow, a plethora of informati=
on=20
in order to make energy deals, submit reservations and provide schedules fo=
r=20
service. Staff received many complaints about barriers to transmission=20
access, including TLR curtailments and a lack of standardized information a=
nd=20
protocols, particularly for ATC and interconnection requests, and=20
discriminatory conduct. Unbelievably, key data was unavailable to Staff,=
=20
such coincident peak load data, system-wide snap shots for days when TLRs=
=20
were called, and import/export data. This lack of data creates a market=20
inefficiency, because neither market participants nor regulators can fully=
=20
analyze market conditions in real time. As such, the market is risk advers=
e,=20
eschewing long-term deals for short-term transactions. Staff also noted th=
at=20
because the Security Coordinators often work for the IOU, there is a mixed=
=20
incentive to enforce reliability on the grid and maximize profit for the=20
IOU. (Staff cites Richard Tabors' paper, "Transmission Markets, Stretching=
=20
the Rules for Fun and Profit.")
Staff cites the lack of information on OASIS or on the NERC web site,=20
particularly about real time TLRs and curtailments. Examples were provided=
=20
to Staff of transmission refusals when there were no TLRs posted and improp=
er=20
implementation of TLRs causing substantial financial loss.
The currently proposed Midwest RTOs may mitigate some problems; however, al=
l=20
three retain existing control areas with the favortism for generation and=
=20
native load. These incentives will continue to remain until the RTO=20
exercises complete autonomy over transmission control and security=20
coordinator functions. Staff notes that the Midwest is a balkanized region=
=20
of 61 control areas with no uniform method for calculating ATC and CBM. Th=
e=20
result is that ATCs can be different on 2 different sides of an interface. =
=20
Staff notes examples in inaccurate ATCs and states that Staff's own ATC aud=
it=20
this summer was consistent with market participant complaints. Staff is=20
weighing follow-up options. The result of these problems is a lack of=20
liquidity.
Staff next noted the problems with unfiled "business practices," especially=
=20
on the next hour market. Staff's audit of OASIS sites revealed several are=
as=20
of non-compliance. =20
Information transparency is necessary for a market to function efficiently,=
=20
with equal and timely access to data, including ATC, CBM, TRM, and load flo=
w=20
input data. TPs have incentives to resist efforts to make this information=
=20
transparent because of native load. This incentive will still exist under=
=20
RTOs if utilities are allowed to calculate their own ATC. *** "As a=20
consequence, the Commission may wish to eliminate the native load exemption=
=20
and have all transactions under the same tariff." *** The Commission coul=
d=20
benefit by having access to existing transmission data and should require t=
he=20
TPs to retain data, including current real-time network status.
Interconnection Issues: IPPs need to be compensated for VAR support. Also=
,=20
Staff cites a number of Hotline complaints about TPs seeking large deposits=
=20
or failing to complete System Impact Studies timely. One solution is to ha=
ve=20
the RTO handle this function to eliminate the disincentive the utilities ha=
ve=20
against IPPs. The current practice of requiring IPPs to deal with a wide=
=20
variety of procedures inhibits the free flow of transactions within the=20
region.
Network service has inherent advantages over point-to-point, citing the=20
Entergy source and sink order. The Commission has relied on "passively"=20
receiving informal and formal complaints to determine if discriminatory=20
behavior has occurred rather than actively canvassing market participants. =
=20
While Staff cannot conclude that discriminatory practices are widespread,=
=20
there is evidence of discriminatory instances.
Southeast: The traditional vertically integrated utility ("VIU") model has=
=20
largely persisted in the SE. This continued control has vastly reduced the=
=20
economic incentives to facilitate IPP activities. In many cases, the VIUs=
=20
have dampened IPP involvement without violating any Commission regulation d=
ue=20
to the inherent flexibility of the current rules.
Staff cites examples of delays in performing system impact studies,=20
transmission hoarding in the name of serving native load growth and=20
manipulation of ATC. TPs have shown little inclination to improve the=20
transmission system and use many TLRs.
There is also a lack of market information that has stymied the development=
=20
of markets in the SE. ATCs change constantly that leads to uncertainty and=
=20
there is no clearinghouse for electric power prices.
TVA, despite having taken steps to participate in reformed markets, has act=
ed=20
as a bulwark against the development of competitive energy markets in the=
=20
SE. This is significant because of TVA's size and location. IPPs have=20
reported TVA's discouragement of siting in TVA through excessive time to=20
perform studies, excessive fees, and rejection of requests to perform=20
interconnection studies.
In addition, Staff cites the Florida Sup. Ct. decision against merchant=20
plants as significantly impeding the competitive market in Florida.
Staff discusses the significant flow of power from the Midwest to the SE th=
is=20
summer. Much of this resulted from the import of cheaper coal power, than=
=20
the use of gas fired peakers due to higher gas prices. Peak prices were=20
radically lower this summer because utilities appear to have been better=20
prepared for peak events through the use of forward contracts, increased=20
generation capacity on line and reduced number of forced outages. =20
SE utilities reported that they have not used market-based rates to=20
extensively increase sales. (Less used than in the midwest.)
The SE region lacks information, which has retarded the Staff's efforts to=
=20
discern the truth about the numerous complaints about transmission in the S=
E=20
(including ATC and TLRs). Market participants seem to have less confidence=
=20
in the SE market than in any other market region. This appears to be=20
justified based on Staff's investigations. This lack of confidence=20
discourages investment and participation in the markets. Staff concludes=
=20
that the Commission may need to be more prescriptive in terms of how=20
transmission is allocated in the SE RTOs, since there are market concerns=
=20
that the incumbents will continue to dominate operations. The investigatio=
n=20
found numerous problems in bad ATCs and TTCs and poor OASIS postings. In=
=20
addition, several OASIS audit logs actually erased historical data. Staff=
=20
thinks that additional affiliate transaction information should be posted. =
=20
Staff could not obtain summer demand data and the Commission's lack of=20
jurisdiction over TVA made it difficult to obtain transmission access=20
information.
The Staff investigation revealed unclear interconnection procedures and lac=
k=20
of adherence to schedules and arbitrary cost estimates and deposits. In=20
addition, the TPs have reserved a huge amount of network transmission=20
capacity, much of it reserved shortly after the IPP approached the TP to=20
interconnect. Staff cites the recent Skygen order in which Southern denied=
=20
Skygen's request for transmission stating that the only option was the=20
construction of an 80 mile 500 kv line that would take 8 years to complete.=
=20
Staff solutions include allowing network requests by IPPs and limiting=20
self-build capacity in the incumbent's territory.
ATC variations are a big problem in the SE. SERC coordination of a=20
standardized ATC is a long process and may not be resolved soon without=20
direction from the Commission. An improved method and improved communicati=
on=20
are needed.
The SE experienced a 354% increase in TLRs this summer. This increase rais=
es=20
the issue of whether curtailment has become an impediment to the competitiv=
e=20
operation of the market in the SE. Staff cites information provided by=20
Charles Y. that an Ameren TLR was not implemented according to NERC=20
criteria. Staff also wonders if transmission is being oversold since TPs d=
o=20
not generally refund transmission revenues when TLRs are implemented. RTOs=
=20
must have a broad geographic area to internalize much of the constraints. =
In=20
addition, RTOs will adopt pricing mechanisms that obviate recourse to TLRs.=
=20
However, if control areas are retained, VIUs will retain mixed incentives.
*** As noted in the Midwest report, the manner in which load is calculated=
=20
weighs heavily on the value of this information. This is an issue that the=
=20
formation of RTOs may not resolve. Eliminating native load exceptions -- i=
e,=20
treating all load equally -- and placing all transactions under the same=20
tariff may be an option that provides the right incentives for the provisio=
n=20
of transparent and standardized information.
Finally, Staff describes specific problems with TVA and FP&L, TVA is a=20
"problem area" for the Eastern Interconnect grid. TVA is a transmission=20
bottleneck due to the many TLRs called this summer. The current federal la=
w=20
and lack of Commission jurisdiction are impediments to the development of=
=20
deep and robust power markets in this area. TVA simply has no strong=20
incentive to provide effective and efficient transmission service. In=20
addition, the Commission does not have full information on TVA. Staff list=
s=20
a number of complaints against TVA, including unjustifiably increasing the=
=20
tag deadline and allowing TVA Marketing, but not others, to sink and park=
=20
power. Staff concludes that recent proposals by TVA to enhance the=20
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, includin=
g=20
confidential information on FP&L's transmission system (including interchan=
ge=20
information for other entities) posted on EMS systems that were available t=
o=20
FPL's merchant function. Staff's report found that FP&L does not have an=
=20
established procedure for review of EMS to ensure that information is not=
=20
displayed in error. It is "up to individual Managers discretion." ((FRCC=
=20
web site report dated 9/8/00)). Violations such as these undermine=20
competition.
The reports are attached below.
- southeast.pdf
- midwest.pdf
NORTHEAST SUMMARY
Attached is a summary of FERC Staff=01,s November 1, 2000 report on its=20
investigation of the Northeast region. The report is very encouraging=20
because it is comprehensive and recommends many of the changes and solution=
s=20
that Enron has been advocating for years. The report is also encouraging=
=20
because it indicates a significant level of understanding of the northeast=
=20
markets (and the problems in these markets) by the FERC people who worked o=
n=20
this report. Because this is only a brief summary, the entire report=20
(particularly sections 4 and 5) should be read in detail. A copy of the=20
report is attached.
Please let us know if you have any questions or comments.
Sarah
=20