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Enron Mail |
please distribute for your staff meeting
KH ---------------------- Forwarded by Kevin Hyatt/ET&S/Enron on 10/31/2000 12:37 PM --------------------------- Jeffery Fawcett 10/27/2000 12:34 PM To: Steven Harris/ET&S/Enron@ENRON cc: Kevin Hyatt/ET&S/Enron@Enron Subject: Electric Developments 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: sharris1@enron.com 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
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