Subject: Electric Developments
From: [email-masked]
To: [email-masked]
Cc: [email-masked]
Date: Fri, 27 Oct 2000 05:34:00 -0700 (PDT)

I consulted with Kevin before I took the oars in trying to answer your 
question, as well as the questions raised in Drew's e-mail.  Here's what we 
found out...

Steve's question:

What economics would determine if a developer could site a power plant in New 
Mexico (maybe 3,000MW) and build a line to the grid in California versus us 
expanding to deliver the gas to a power plant in California?

What you're really asking here is "What are the comparative economics of 
energy delivered by wire versus energy delivered by pipeline?"  In this 
analysis, there are a few considerations -- (1) original capital cost to 
construct facilities, (2) the operating cost of the facilities, including 
energy loss, and (3) environmental and other permitting considerations. 

 Engineers tell us that, as a rule of thumb, high voltage transmission lines 
and tower facilities cost approximately $800,000 to $1MM/mile to construct 
turnkey.  This figure is comparable to the $1MM/mile "rule of thumb" we use 
for turnkey construction of mainline diameter (30-36") high-pressure steel 
pipeline.  

In terms of operating costs, for anything over 100 miles in length, there are 
three (3) basic sources of energy loss in electric transmission: (1) 
transformation loss, (2) radiation loss (EFM) and (3) heat loss across the 
conductors.  A rule of thumb for electric transmission loss is 3%.  This 
number is comparable to the actual fuel used for compression on 
Transwestern's pipeline.   

The most critical issue impacting construction of high voltage transmission 
lines is in the area of permitting.  There just aren't many new transmission 
lines being approved.  It was suggested by more than one source that an 
electric transmission project on the order posited in your example, could 
take anywhere from 6 to 10 years to secure authorization.  The issues of 
electromagnetic field (EMF) radiation around high voltage power lines, along 
with other wildlife endangerment concerns, are significant obstacles in 
securing permits for right-of-way.

In short, the answer is that while the economics on face appear to be 
comparable for construction and operation of both natural gas pipelines and 
electric transmission lines, the protracted permitting process for electric 
transmission lines tips the scale considerably towards the more immediate 
returns available on investment in natural gas pipeline infrastructure.

Drew's questions:

1. What are the key factors that determine where a power plant developer puts 
his plant?

For purposes of this exercise, I'm assuming we're talking gas-fired 
generation.  Developers generally describe four considerations in deciding 
where to site a new electric power plant:
 1. Market area demand (distributive) and/or Transmission access to market
 2. Water rights for turbine cooling
 3. Ease of permitting (environmental, encroachment, fed/state/local 
regulations, affected agencies/jurisdiction)
 4. Proximity to natural gas pipeline/supply infrastructure  

2. Do the transmission access and pricing rules of the various 
utilities/power pools vary all that much or are Order 888 tariffs pretty much 
the same all over?

FERC Order 888 and 889 require public utilities to commit to standards of 
conduct and to file open access tariffs affecting transmission among and 
between other utilities and/or power pools in the various operating regions.  
FERC ordered public utility transmission owners to provide transmission 
access and comparable service to competitors and to functionally separate 
their transmission/reliability functions from their wholesale merchant 
functions. The rulemaking is analogous to the open access requirements under 
FERC Order 436/500/636 affecting interstate natural gas pipelines.  It's 
pretty obvious from the California example this past summer, that with 
respect to the overall operation of a deregulated power market in individual 
states, particularly as concerns the establishment and regulation of 
Independent System Operators (ISO's), there is substantial room for 
improvement (and possible further FERC involvement).
 
"In the open access final rule (Order No. 888), the Commission issues a 
single pro forma tariff describing the minimum terms and conditions of 
service to bring about this nondiscriminatory open access transmission 
service.  All public utilities that own, control, or operate interstate 
transmission facilities are required to offer service to others under the pro 
forma tariff.  They must also use the pro forma tariffs for their own 
wholesale energy sales and purchases.  Order No. 888 also provides for the 
full recovery of stranded costs--that is, costs that were prudently incurred 
to serve power customers and that could go unrecovered if these customers use 
open access to move to another supplier."  

3.  How do IPP's decide what fuel supply strategy works best (i.e., buy 
bundled delivered fuel from someone vs. buy gas, storage, transport, etc. 
separately)?

In my experience, there is no "one size fits all" formula or strategy.  For 
example, in the past we've seen Calpine take a very hands-on approach to 
supplying its IPP projects.  In the mid to late '80's, during the build out 
of several QF's (cogens), Calpine bought natural gas reserves in the ground 
and dedicated them to the project.  In today's market, Calpine has scavenged 
the gas and basis traders from Statoil and set-up a natural gas desk for the 
purchase and transportation management of gas supplies needed for its western 
U.S. power projects.  In other projects, developer/owners and their lenders 
are satisfied with a less active role in securing gas supply/transportation 
to the project.  In short, projects look at the liquidity of the gas supply/ 
transportation market in deciding whether they can achieve project economics 
and secure reliable supply by taking bids or RFP's for gas 
supply/transportation, or whether to take a more hands-on approach ala 
Calpine.

4.  What is the RTO Rule and why should we care?

Last December, the FERC issued Order No. 2000, a final rule on Regional 
Transmission Organizations (RTO's).  Order 2000 builds on the foundation of 
Orders 888 and 889 (issued in 1996).  According to FERC Chairman Jim Hoecker, 
Order 2000 makes "a persuasive case for separating control of grid operations 
from the influence of electricity market participants."  Therefore, Order 
2000 can be seen as a natural outgrowth of the perceived limitations on the 
functional unbundling adopted in Orders 888 and 889, continuing balkanization 
of the electric transmission grid based on corporate, not state or regional 
boundaries, as well as pressure to provide guidance on acceptable forms of 
privately-owned transmission companies.  

FERC prescribes a voluntary approach to RTO participation.  The order 
initiates a regional collaborative process to foster RTO formation.  The 
Order also imposes filing requirements on the privately owned "public 
utilities" that are subject to FERC jurisdiction, and requires these private 
utilities to describe in their filings how they have attempted to accommodate 
the needs of transmission owning state/municipal, cooperative and federally 
owned systems.  FERC believes that, regardless of format, RTO's will offer 
the following benefits: (1) alleviate stress on the bulk power system caused 
by structural changes in the industry, (2) improve efficiencies in 
transmission grid management through better pricing and congestion 
management, (3) improve grid reliability, (4) remove remaining opportunities 
for discriminatory practices, (5) improve market performance, (6) increase 
coordination among state regulatory agencies, (7) cut transaction costs, (8) 
facilitate the success of state retail access programs, and (9) facilitate 
lighter-handed regulation. 

Critics point out that with its emphasis on flexibility, voluntary RTO 
formation and transmission rate reforms (i.e., incentives), Order 2000 defers 
for case-specific disposition many of the tough issues that must be resolved 
in order to create an operational RTO.   Moreover, Order 2000 does not compel 
any transmission owner to join an RTO, but provides only regulatory guidance 
and incentives for willing participants, as well as a veiled threat of 
further consequences for the hold-outs. 

As to the final part of the question ("why should we care?"), presumably, the 
development of a fully-functioning RTO network will promote both the 
efficiency and market transparency goals of the original FERC orders.  As 
FERC reads it, the future of gas-fired generation for both merchant and 
utility systems, depends on an efficiently operated open access transmission 
system.  Therefore, the promise of the RTO is to stimulate competition and 
the ongoing investment in new generation infrastructure.  Unfortunately, 
sources tell me that the voluntary nature of the RTO program may ultimately 
cripple its effectiveness in meeting its stated goals.  

5.  Has $5/mmbtu gas killed the gas fired power market?

Natural gas prices of $5/MMBtu can only "kill" gas-fired power plants in 
those instances where (1) there are more economical alternatives to natural 
gas fuel, (2) demand for electric power is offset through demand side 
management or (3) natural gas in an environment of short supply is expressly 
prohibited from use as a power plant fuel.  In the Western U.S. marketplace, 
particularly in California, I see no viable alternative to natural gas fuel 
for electric power generation.  Renewable resources currently meet less than 
5% of the total electric resource requirements.  $32/barrel oil prices give 
fuel oil no clear economic advantage over natural gas (even at a $5/MMBtu 
price).  Moreover, California environmental and permitting regulations make 
the installation of new electric generation based on anything other than 
natural gas fuel or renewable resources virtually impossible.   While demand 
side management programs are the politically correct approach to meeting 
resource needs, historically, they have served only a minor role in 
offsetting the growth in electric power.  As to the final point, I'm unable 
to comment on the risk of future legal/regulatory restrictions governing the 
use of natural gas as a boiler or turbine fuel.

Steven Harris
10/26/2000 10:05 AM
To: Kevin Hyatt/ET&S/Enron@Enron
cc: Jeffery Fawcett/ET&S/Enron@ENRON 

Subject: Re: Electric Developments  

Since you are the "expert" in this area, I need to know what economics would 
determine if a developer could site a power plant in New Mexico (maybe 
3,000MW) and build a line to the grid in California versus us expanding to 
deliver the gas to a power plant in California. If you could let me know by 
next Friday I would appreciate it.   

Kevin Hyatt
10/25/2000 04:32 PM
To: [email-masked]
cc:  

Subject: Electric Developments

Steve, see below.  Drew asked me to help him out with his meeting.
kh

---------------------- Forwarded by Kevin Hyatt/ET&S/Enron on 10/25/2000 
04:34 PM ---------------------------
   
	Enron Energy Services
	
	From:  Drew Fossum                           10/25/2000 01:49 PM

To: Dari Dornan/ET&S/Enron@ENRON, Lee Huber/ET&S/Enron@ENRON, Tony 
Pryor/ET&S/Enron@ENRON, Maria Pavlou/ET&S/Enron@ENRON, Susan 
Scott/ET&S/Enron@ENRON, Jim Talcott/ET&S/Enron@ENRON, Kathy 
Ringblom/ET&S/Enron@ENRON
cc: Michael Moran/ET&S/Enron@ENRON, Kim Wilkie/ET&S/Enron@ENRON, Kevin 
Hyatt/ET&S/Enron@Enron, John Dushinske/ET&S/Enron@ENRON, Shelley 
Corman/ET&S/Enron@ENRON 
Subject: Electric Developments

When we originally decided to use my staff meetings for "graduate education" 
one of the hot topics was the electric industry.  We all had a first lesson 
on this topic in Shelley's electricity seminar last summer.  Now, John and 
Kevin have graciously agreed to join us Tuesday at 1:30 to discuss recent 
developments in electric markets and NN's and TW's efforts to attract power 
generation load to the system.  Specific topics I hope to cover include the 
following:
1.  What are the key factors that determine where a power plant developer 
puts his plant?  
2.  Do the transmission access and pricing rules of the various 
utilities/power pools vary all that much or are Order 888 tariffs pretty much 
the same all over? 
3.  How do IPPs decide what fuel supply strategy works best (i.e., buy 
bundled delivered fuel from someone vs. buy gas, storage, transport, etc.  
separately)?
4.  What is the RTO Rule and why should we care? 
5.  Has $5/mmbtu gas killed the gas fired power market?
 Depending on how deeply we get into these topics, we may need to schedule a 
follow-up session at a later date.  I look forward to seeing you on Tuesday.  
DF