From: drew.fossum@enron.com
To: stephen.thome@enron.com
Date: 2000-06-21 16:11:00+00:00
Subject: Re: Pueblo

Great--Steve, what's your phone no. ?  The operator didn't have it and I'd 
like to talk for a few minutes on this.  Thanks. DF




Stephen Thome@ECT
06/20/2000 04:20 PM
To: Drew Fossum/ET&S/Enron@ENRON
cc: William Gang/HOU/EES@EES@ECT, John M 
Rose/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Bill Votaw@ECT, Jerry D 
Martin/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Arnold L 
Eisenstein/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Steven 
Harris/ET&S/Enron@Enron, Lorraine Lindberg/ET&S/Enron@ENRON, Kevin 
Hyatt/ET&S/Enron@Enron, Christopher F Calger/PDX/ECT@ECT 

Subject: Re: Pueblo  

Here are some peaker data points:

Two LM6000's in simple cycle configuration can be installed for between $43 m 
and $50 m, providing a total of 80 MW.  Looking at a 10 year deal, there is 
no way to recoup this value and ENA would not be willing to take the back 10 
years on its books without an offtaker.  If EES or DOE were willing to step 
up for 20 years, there might be an opportunity.   Assuming a 9700 heat rate, 
$3 per MWh O&M, and NYMEX plus $0.39 for gas, the spread option for a peaker 
at 4 Corners would be worth between $33 m and $47 m.  The first number 
represents the intrinsic value, and the second is inclusive of an option 
premium.  ENA's desk (EPMI) would pay somewhere in between.  Having just 
inquired with the desk regarding their appetite for taking positions (short 
65 MW, long 80 MW) in Albuquerque, they were luke warm.  Considering 
transmission constraints into Albuquerque, their bid offer spread might run 
the range of the extrinsic value on the 65 MW load.  

Depending on site conditions (available infrastructure), a barebones LM6000 
plant could make economic sense.  The plant host would likely need to pay 
some sort of premium for generation reliability.  EES could sell fixed priced 
energy with a reliability premium to the DOE.  ENA would back-to-back the EES 
contract, managing market price risk and economically optimizing the 
peaker.   

As a stand-alone market play, a peaker is marginal at best.  By receiving 
value for reliability, the project might have merit.  Based on the thin 
margins, I am skeptical that we would want to build a plant larger than the 
host's load... that is more MW than that amount on which we could expect to 
receive some sort of demand charge.  Ultimately, the demand charge needs to 
make up the shortfall between EPMI's swap value and the cost of the plant.

Steve




   
	Enron North America Corp.
	
	From:  Drew Fossum @ ENRON                           06/19/2000 08:27 AM
	

To: Stephen Thome/HOU/ECT@ECT
cc: William Gang/HOU/EES@EES@ECT, John M 
Rose/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Bill Votaw@ECT, Jerry D 
Martin/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Arnold L 
Eisenstein/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT@ECT, Steven 
Harris/ET&S/Enron@Enron, Lorraine Lindberg/ET&S/Enron@ENRON, Kevin 
Hyatt/ET&S/Enron@Enron 
Subject: Re: Pueblo  

Thanks for the extremely helpful analysis Steve and John.  I'm getting a 
pretty clear sense that this project isn't going anywhere as it is currently 
configured.  Just to satisfy myself, though, let me throw out a couple of 
observations for the group to react to, along the lines of Steve's "However" 
section of his memo:

1.  Running this thing as a baseload unit won't work.  The fuel cost is a 
killer.  However, I keep thinking about the $200/mwh 4 Corners spot price 
someone mentioned on the phone.   Is there enough volatility at 4 Corners to 
support a peaking merchant plant?  How often are those types of opportunities 
available, and could a power plant in Alb. capture that upside by 
transporting power to 4 Corners over PNMs system?  
  
2.  We have been assuming that the power plant should be a baseload plant.  
Someone on the phone last week had some numbers indicating that the DOE/DOD 
electric load at Kirtland had a fairly high load factor.  I think we have all 
assumed further that the plant should run at a high load factor to sell 
surplus power into the grid (either at 4 Corners or, after N.M. elec. 
restructuring, into the Alb. area).   I just found the numbers I was 
remembering on the conf. call--1998 peak load was 63.6 mw, and total annual 
1998 consumption was 334.5 million Kwh.  By my lawyer-math, that is about a 
60% load factor for DOE.  If the DOE load is only 60% L.F., and the plant 
only generates surplus power when it can capture profit opportunities that 
arise when the market clearing price at 4 Corners or in Albuquerque exceeds 
some benchmark rate ($.05/Kwh?  $.10/Kwh?  higher?)  the plant might run at a 
30-40% load factor on an annual basis.  The question is can we reduce the 
capital cost significantly by building a peaker instead of a baseload unit?

3.  Could we get debt financing for a 140 mw plant that had a baseload demand 
charge contract for only 65 mw (i.e., DOE) but sold the rest of its output 
into the grid only when profit opportunities arose?      

4.  If the answer to 3. is no, would ENA backstop the debt financing by 
signing a demand charge contract for all surplus power over and above what 
the government needs?   At what price?  Based on its knowledge of volatility 
and profit opportunities currently available at 4 Corners, and future profit 
opportunities that will be available in Albuq. is that just a dumb bet, or 
would ENA get interested if someone else (i.e., DOE) split the risk and 
reward?  

John, how much of the information in your analysis could be sanitized in a 
way that we could provide it to Dennis Langley?  If we pull the plug on the 
project, I'd like to be in a position that we could let him in on some of our 
information on why the turbines we would use can't provide acceptable 
economics.  I don't expect that we'd want to disclose the swap value analysis 
in Steve's memo, however.  

Thanks again, and I'd appreciate anyone's reaction to the above questions.  
DF  





Stephen Thome@ECT
06/16/2000 06:12 PM
To: William Gang/HOU/EES@EES
cc: John M Rose/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Bill Votaw@ECT, Jerry D 
Martin/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Arnold L 
Eisenstein/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Steven Harris@ENRON, Drew 
Fossum@ENRON, Lorraine Lindberg@ENRON 

Subject: Re: Pueblo  

John's proposed plant costs are consistent with what we have seen for our 
ongoing LM6000 development.   I have priced 130 MW at Four Corners  assuming 
Permian gas plus 50 cents for transport.  This also assumes $4.70 per MWh for 
O&M and an 8000 heat rate.

For an hourly 7x24 product, the intrinsic value of the gas-power swap is 
$52.5 million on a 20 year deal, well below the $108 million estimate of 
constructing the facility.  A ten year swap is worth only $42 million (NPV = 
-66 m ).  That implies a market mid-price of $34 per MWh levelized over the 
period.  

Using the ENA Power and Gas structuring model and curves, we can determine 
the following:
1.  New build gas turbines cannot compete against the New Mexico market on 
price.  
2.  LM6000 CCGT efficiency gain does not pay for HRSG and ST over a ten year 
period.

However:
1.  Transmission constraints could create market value in Albuquerque that 
does not exist at Four Corners.
2.  ENA's power prices typically undersell the market.
3.  Commodity pricing does not accurately value capacity or reliability in 
constrained markets.

If Enron wants to do a deal in Albuquerque, we should be selling capacity and 
reliability.  Given the number of power- critical industries in the area, we 
could look at siting several remote units at different locations in the 
city.  Numerous chip manufacturing facilities and the Kirtland base could 
support several LM6000's for power reliability that is specific to their 
installations.  

I might also suggest that peaking units would have advantages over CCGT 
units.  Existing generation already provides ample baseload supply, however, 
the production of peak and intermediate energy is not necessarily well suited 
to existing units.  LM6000's have exceptionally good ramp rates that provide 
real value to a utility customer.  Not only can the HRSG/ST hinder the 
flexibility of the units, it can add substantial capital and operating 
expense with little real market benefit.  

We should also explore the ability to schedule load.  If the DOE wants to 
peak for a test, would it be willing or able to schedule a test for the 
off-peak hours?  Under those circumstances, we might be able to cut them a 
break on power and provide reliability of supply.  

Steve Thome

503-464-3708




John M Rose@ENRON_DEVELOPMENT
06/15/2000 06:53 PM
To: Bill Gang@EES
cc: , Stephen Thome@ECT 
Subject: Pueblo

Bill,

Yesterday, we decided to look at two options for Pueblo; a 60 MW case and a 
140 MW case.  In order to match these outputs as closely as possible with 
available equipment, I made the following selections:

Case 1
Equipment     3 X GE LM 2500 Gas Turbine Generators with Heat Recovery and 1 
X 22 MW Steam Turbine Generator
Output at 95 deg F & 5000 ft   67 MW
Output at avg. conditions (60 deg F)  73.4 MW
Heat Rate at avg. conditions  8170 Btu/kWh (HHV)

  
Case 2
Equipment     3 X GE LM 6000 Gas Turbine Generators with Heat Recovery and 1 
X 44 MW Steam Turbine Generator
Output at 95 deg F & 5000 ft   130 MW
Output at avg. conditions (60 deg F)  143.7 MW
Heat Rate at avg. conditions  7900 Btu/kWh (HHV)

There is a wide fluctuation in ambient temperature in Albuquerque and I sized 
the blocks based on 95 deg F but used the annual average output at 60 deg F 
for estimating power sales.  I have attached files that show the build-up of 
the estimated EPC price for the plants. 

The required power prices are projected in a simple-minded economics file 
attached.  The projections are based on:

70% debt financing at 10% rate.
10-year project and debt life.
8500 hours per year at average output (97% capacity factor).
Gas at $4.40/MMBtu.

The results turn out pretty much as anticipated.  Even with the larger plant, 
we'd have to sell the power for over 6c/kWh.