---------------------- Forwarded by Christi L Nicolay/HOU/ECT on 10/03/2000 
06:40 PM ---------------------------


Christi L Nicolay
10/03/2000 06:49 PM
To: Tom Briggs/NA/Enron@ENRON
cc: James D Steffes/NA/Enron@Enron, Richard Shapiro/HOU/EES@EES, Joe 
Hartsoe/Corp/Enron@Enron 

Subject: Re: Draft Questions for Hoecker  

Tom--[[For your background information for Senator Gordon--you will need to 
edit out the information on the part Enron played, but I thought you would 
want the entire picture]].

 Until the Tennessee Power case issued in March, most utilities considered 
interconnection issues and procedures to be within their discretion.  The 
only FERC approved policies were in PJM and NEPOOL.  These policies are 
fairly idiosyncratic to those pools.  Since Enron began siting merchant 
generation with our 1999 peaking plants in TVA, we had told FERC that there 
were problems in getting utilities to be responsive.  The main problem was 
failure to provide study results in a timely manner.

 I think it is important to note that merchant facilities are a fairly new 
idea.  They are not rate-based, and have no guaranteed return paid for 
directly by retail customers (except perhaps to the extent that a utility 
signs a deal to purchase capacity and/or energy from the merchant.)  Plus, I 
think the utilities are incentivized under the current vertically integrated 
structure to benefit their own merchant plants or their utility plants (less 
supply).

? TENNESSEE POWER ORDER ON INTERCONNECTION POLICY -- FERC issued an order on 
3/15/00 clearly expressing its policy on interconnection issues.  The order 
is significant because it was issued in large part due to the lobbying 
efforts of EPMI and other generator members through Enron's membership in the 
Electric Power Supply Association ("EPSA").  

In mid-January, EPSA arranged all-day meetings for Sarah Novosel (Enron) and 
other EPSA members to meet with the FERC Commissioners and staff to discuss 
interconnection issues.  Fourteen EPSA member-companies were represented at 
these meetings, and we expressed to the Commissioners and FERC staff the 
problems we are facing in our efforts to successfully negotiate 
interconnection agreements with utilities.  We urged the Commission to, at a 
minimum, develop procedures that will make requesting and negotiating 
interconnection agreements less time consuming and more even-handed.  The 
Commission had assumed that the procedures laid out in the pro forma tariff 
for requesting transmission service also applied to requests for 
interconnection, and they were surprised to learn that most utilities do not 
abide by the procedures for interconnection requests.  

In the Tenn. Power order (that dealt with a complaint filed by Tennessee 
Power Co. against Central Illinois, which FERC dismissed), FERC clarifies 
that the pro forma tariff procedures established for transmission requests 
apply equally to interconnection requests.  Furthermore, FERC states that a 
utility may not require a generator to submit a request for transmission 
service along with its request for interconnection service, stating that 
these are separate services and should be treated separately by the utility.  
(Many generators have found that utilities are requiring them to submit 
transmission requests at the time they submit interconnection requests, and 
then the utility insists on performing costly and time-consuming system 
impact studies for the transmission service, even if the generator does not 
want the transmission service).  By applying the pro forma tariff procedures 
to interconnection requests and by requiring utilities to accept 
interconnection requests without transmission service requests, FERC is 
eliminating many of the roadblocks currently encountered by generators in 
attempting to obtain interconnection from utilities.  FERC also states that 
if the parties to an interconnection agreement fail to agree on the rates, 
terms or conditions of the interconnection, the transmission customer may 
direct the utility to file within 30 days an unexecuted agreement with FERC.  
FERC will then have 60 days to determine the just and reasonable rates, terms 
and conditions for the interconnection service.  

During the FERC agenda meeting on 3/15, Commissioner Massey was very pleased 
with the order and congratulated his colleagues on providing the industry 
with needed guidance.  Commissioner Massey then encouraged utilities to each 
develop their own standard interconnection agreement that applies to all 
generators requesting interconnection service, and he also encouraged the 
industry to work together to develop an industry-wide pro forma 
interconnection agreement.  EPMI has been working with EPSA on a pro forma 
interconnection agreement, so Commissioner Massey's comments could encourage 
the utility sector to begin negotiating an industry-wide standardized 
agreement.  However, even without a standardized agreement, we hoped that 
FERC's order will help remove many of the obstacles currently used by 
utilities to delay (sometimes indefinitely) the citing of new generation.

? TECO HOURLY IMBALANCE FILING -- TECO made a FERC filing to require minute 
by minute balancing for generators that interconnect to the transmission 
system.  EPMI protested through EPSA and asked for hourly balancing.  Before 
an order was issued (somewhat unprecedented behavior before FERC), TECO 
withdrew its minute filing and refiled for hourly imbalance calculations.  
 At this time, FERC has not accepted requests by EPSA and others to create a 
"standard" generator imbalance schedule for the OATT.  FERC has said it would 
review the filings on a case by case basis.  FERC has not required utilities 
to file imbalance schedules -- it "encourages" them to do so.  At this time, 
only Entergy, SOCO, TECO and several other utilities have filed imbalance 
provisions as amendments to their OATTs.  Most utilities require this to be 
"negotiated" (not much room for negotiation) in the interconnection 
agreements.
 While FERC requires interconnection agreements to be filed at FERC and they 
can be filed "unsigned," and then protested, this can be an impractical 
solution when building a peaker in less than one year, such as Enron has 
done.  A merchant power producer is more likely to move the project to a more 
friendly utility forum or accept some provisions that may be somewhat onerous 
in order to site and build the plant for summer start dates.

? ENTERGY INTERCONNECTION FILING ) On 3/1/00, Entergy filed a proposed 
interconnection policy and procedure at FERC.  EPMI protested various aspects 
and we assisted EPSA on its protest.  Before the order was issued (again 
fairly unprecedented), Entergy agreed to make certain changes to its proposed 
interconnection procedure and interconnection agreement in response to 
protests.  (Entergy asked FERC to delay an order until it could make this 
filing.) 

Entergy agreed to change:

Defines "required" system upgrades as those required to simply interconnect.  
(EPMI and EPSA issue).  ("Required" are those such as resulting from the 
Short Circuit/Breaker Rating Analysis and Transient Stability Analysis--like 
circuit breakers, relaying devices, system protection equipment.)

Customers are not required to supply reactive power except when "in service" 
(did not go as far as EPMI argued -- that we should not be required to 
provide it or should receive the cost of our liquidated damages if we have to 
cut our deal.  Entergy said it will pass through amounts it receives.)

Adopted EPMI's proposed "Emergency" language that loss of Entergy's 
generation and inability to meet its load requirements is not an Emergency.

Agreed that Entergy cannot interrupt generator for "non-emergencies" except 
when "complying with reliability protocols or procedures established by NERC 
or SERC or reg. agency (EPMI issue).

Changed force majeure language to match OATT.

Entergy also states that it will not include generators in Short 
Circuit/Breaker Analysis and Transient Stability Analysis until an 
interconnection agreement is signed, although the generation projects will 
remain in the queue.  This can cause the costs to vary from the 1st estimate 
to time of actual interconnection.

On 5/18/00, FERC issued an order accepting Entergy's pro forma 
interconnection agreement ("IA") and procedures subject to modification.  As 
I mentioned above, Entergy had adopted some of EPMI's suggestion (in EPMI's 
comments), including limiting emergencies to not include Entergy's loss of 
generation.

All transmission must be separately arranged through OASIS -- it is not 
included with an interconnection request.
Entergy's interconnection policy will apply to generators that will serve 
wholesale, as well as unbundled retail.
Dismisses EPSA's call for a "model" and approves Entergy's pro forma 
interconnection agreement, subject to modification.((The Commission stated 
"EPSA, Dynegy, and PG&E argue that the Commission should initiate a generic 
proceeding or industry collaborative to address interconnection 
concerns....The Commission declines at this time to issue a policy statement 
or convene a industry collarboration to establish standardized IPs 
(Interconnection Procedures) and IAs (Interconnection Agreements).  With 
respect to IPs, the Commission's recent findings in Tenn. Power amplify the 
Commission's findings in Order No. 888, which established standard procedures 
for obtaining transmission service.  It is our belief that no additional 
standardized procedures are necessary at this time.  We do, however, 
encourage utilities to do as Entergy has done here and revise their OATTs to 
include procedures for requesting interconnection services and the criteria 
for evaluating those requests.  Because an RTO will administer its pro forma 
tariff, it is our hope that compliance with our RTO rulemaking will eliminate 
concerns about interconnection procedures." at p. 10.)
Agreed with EPMI that billing disputes should be placed in escrow, not paid 
to Entergy subject to refund (FERC said that the IA should conform to other 
aspects of the Order No. 888 tariff--for example, Entergy and customer are 
responsible for their own negligence).
Holds that all other terms of the Order No. 888 pro forma tariff apply to the 
IA, even if  the IA does not repeat all those provisions.
Clarifies Tenn. Power case that if a generator connects first and another 
generator subsequently connects in the same local area and the grid cannot 
accommodate "receipt" of power without expansion, the new generator must pay 
costs of expansion.
Entergy is required to revise IA to make distinction as to which provisions 
are pure "interconnection" and which are applicable when 
transmission/delivery is also requested (on OASIS).
Entergy is required to attempt to complete the interconnection studies in a 
specific timeline (60 days for 1st iteration --system impact), and to provide 
a statement that Entergy will notify applicant of any delay with an 
explanation for the delay (Entergy had included no timelines).
If applicant and Entergy cannot agree on IA terms, Entergy must file the 
unexecuted agreement at FERC for FERC to decide.
Approves Entergy's credits for "optional" upgrades (required to transport 
power away from the plant), but requires Entergy to file an explanation of 
how the credits work.
Entergy will only include prior queued interconnection requests in subsequent 
studies once they have signed an interconnection agreement (to show more 
intent to actually complete the project).  This does not mean that failure to 
execute an IA results in removal from the queue, just that the generator may 
be subject to different actual interconnection costs when it connects.  This 
is a risk that FERC says is inherent in interconnection.  Entergy will also 
post its queue on OASIS.
Reactive power must only be supplied when generator is operating.
Per EPMI,s comments, Entergy cannot keep the initial $10,000 deposit, unless 
actual costs are $10,000 or greater (generator must pay actual costs of 
studies).
Per EPMI's comments, Entergy must pay for energy taken during an emergency 
(or explain why that is inappropriate).
Per EPMI's comments, Entergy must explain the requirement that the generator 
pays for subsequent changes to Entergy's transmission system.

 ComEd Interconnection procedures -- On 3/6/00, ComEd filed interconnection 
procedures.  Enron's comments were included in EPSA's protest on the 
following issues. Proposed procedures:

1.  Submit valid request to interconnect (include # of generating units, 
proposed max MW capacity and MVA, specific location, operational date).  Date 
and time of receipt by ComEd establishes queue position.  This info will be 
posted on OASIS within 15 days (without listing the applicant's name).

2.  Within 30 days of the request, LOI will be tendered.  Applicant has 30 
days to respond or lose queue position.  LOI authorizes commencement of 
engineering work.

3.  Within 45 days of LOI, ComEd will perform an Interconnection Study with a 
project diagram.  Study assumes interconnection of all "competing" requests 
(that ask for a location that affects your interconnection costs) that have 
prior queue dates.

4.  Within 30 of receiving the interconnection study, Applicant must decide 
whether to proceed.

5.  After Applicant decides to proceed, Applicant may have a maximum of 90 
days for a ROFR against lower priority requests and to begin negotiating an 
Interconnection Agreement.  Although somewhat unclear, if there is a 
"competing" request, Applicant must exercise its ROFR within 15 days by 
notifying ComEd of the desire to begin negotiating an interconnection 
agreement.  If Applicant doesn't negotiate an IA-- lose queue spot.

6.  Once IA negotiations begin, Applicant has 90 days to execute it (or 
submit dispute to arbitration).

7.  Before ComEd does inititates construction or installation of facilities, 
IA must be executed.  (if generator is to come on line in < 1 year, ComEd 
will negotiate an agreement (with appropriate financial safeguards) to 
proceed before execution of the IA.)

8.  ComEd will include "reasonable milestones" that must be met in order to 
maintain queue position.

My specific comments for comment:

Some items are unclear.  (1) Whether the "Decision" to proceed is made in 
writing (which it should be); (2) The entire ROFR procedure (does it become a 
race to see who executes an IA faster?)
The 90 day IA execution period is now inconsistent with FERC's new statement 
in Tenn. Power  (30 days).
If ComEd won't start work until after the IA is executed, then the 30 days 
needs to be adhered to (otherwise, the timetable seems too long before work 
begins).
Milestones need to be specified (the current proposal contains "may" include 
milestones, and "may" include the following...)  Also, ComEd wants to 
"reasonably extend" the milestones.  This must be done on a 
non-discriminatory basis.
ComEd allows itself 45 days to complete the Interconnection Study and this 
can be extended in ComEd's "sole judgment."  I disagree and think it should 
only be extended if ComEd provides a reasonable explanation to FERC (similar 
to the pro forma procedures now in section 19.3 re: system impact studies).

On 4/26/00, FERC issued an order that again declined to initiate a generic 
interconnection proceeding, but "encouraged" utilities to revise OATTs to 
include interconnection procedures.  FERC also stated that the timelines in 
the OATT for transmission system impact studies (60 days) and facilities 
studies (60 days) are applicable to interconnection studies and that ComEd is 
required to provide an explanation for any delays past these deadlines.  FERC 
required ComEd to change some other procedures identified by the EPSA protest.


? FERC ORDER ON AEP,S INTERCONNECTION POLICY ) On 6/29, FERC issued an order 
on AEP's proposed interconnection procedures.  EPMI participated in comments 
through EPSA.  While FERC largely reiterated its recent orders on Tenn Power 
and Entergy interconnection procedure, there are several items of interest:

AEP said that it had a backlog of interconnection requests and needed more 
than 60 days to complete the System Impact Study.  FERC held that AEP must 
commit to completing the SIS within 60 days (consistent with the pro forma 
tariff), but if AEP determines it needs more than 60 days, it is required to 
notify the customer with the reasons for the delay.  FERC further stated, "We 
expect AEP to dedicate sufficient resources to these interconnection requests 
to eliminate its backlog."

FERC rejected AEP's proposal to only provide transmission credits for "firm" 
transmission (to a customer that is required to pay for system upgrades).  
FERC said credits must apply to firm PTP, non-firm PTP, or network.

Allows AEP discretion on hiring third party contractors (since AEP would have 
to spend time educating the third party contractors); however, FERC 
reiterates that AEP must eliminate its backlog.


? SPP Interconnection procedures  -- In 7/00, SPP filed clarifications to its 
interconnection procedures recently filed at FERC.  EPMI participated in 
EPSA's protest that the System Impact Study should be completed in 60 days 
(or SPP should provide an explanation for the delay), instead of the 90 days 
requested by SPP.  SPP has agreed to this change (which is also consistent 
with FERC's recent order on AEP's interconnection procedures.)  Also, it 
appeared that SPP wanted the Interconnection Agreement to be executed within 
15 days, which is close to physically impossible, especially when SPP has no 
pro forma IA.  SPP agreed to 60 days.

 CP&L interconnection procedures -- Most recently, CP&L filed interconnection 
procedures that ask for a 90 day study period despite the FERC orders in AEP 
and SPP stating that the deadlines are 60 days.  EPSA protested with yet 
another appeal to FERC to standardize these procedures.  FERC has not issued 
an order.  

 The lack of standardized procedures has become problematic in just the few 
months since Entergy's procedures were filed.  We are required to constantly 
monitor the notices for any procedures that have been filed, then check each 
one carefully to determine how it deviates from the Commission's orders in 
other cases.  The utilities are not required to point this out in their 
filings (ie, no redlining from an OATT, which is required in transmission 
OATT changes.)












Tom Briggs@ENRON
10/03/2000 02:48 PM
To: Richard Shapiro/NA/Enron@Enron, Mary Hain/HOU/ECT@ECT, Cynthia 
Sandherr/Corp/Enron@ENRON, Sarah Novosel/Corp/Enron@ENRON, Christi L 
Nicolay/HOU/ECT@ECT
cc:  

Subject: Draft Questions for Hoecker

Attached please find draft questions to be provided to Sen. Gorton for his 
hearing on NW price spikes to be held Thursday. I hve tried to design 
questions that focus on FERC jurisdiction.  However, i may have med the 
questions too specific and detailed.  please give me your comments and ideas.