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<br />I O~!"15('5 <br />...- .~ .. ~urpose, and Need <br /> <br />1-5 <br /> <br />1.4.1 <br /> <br />Electrical Power <br /> <br />Power from the facility will be sold to one or more electric utilities. The PElS reviewed <br />local and regional power supplies, and concluded that a need for power from the facility <br />existed. At that time, the Sponsors held a power sales contract with Public Service <br />Company of Colorado, to run for the first 15 years of Project operation. Due to delays in <br />permitting the facility, the Sponsors were unable to meet the commercial operation <br />deadline set in that contract. In 1994, Public Service terminated that agreement for <br />failure to deliver power by the scheduled date. <br /> <br />The Sponsors have not actively pursued renegotiation of this or other power contracts <br />since that time. The Sponsors do not plan to commence negotiations until the <br />Department of the Army Permit and Lease of Power Privileges are issued. There are two <br />reasons for this. First, until major permits are issued, the Sponsors cannot reasonably <br />commit to a firm date to begin operations. Second, the mitigation measures and <br />alternatives being considered under this SElR will affect Project generation. Thus, the <br />Sponsors cannot commit to electric output levels until a new ROD and Department of the <br />Army permit are issued. Because the date of operations and output are important <br />components of contract negotiations, the Sponsors cannot reasonably negotiate a new <br />contract until these items are known. <br /> <br />The power market within Colorado is dominated by three public utilities: Public Service <br />of Colorado (PSCC), Tri-State Generation & Transmission Cooperative (Tri-State G&T), <br />and West Plains Energy - Colorado. The electricity needs of PSCC are summarized in its <br />draft 1999 Integrated Resource Plan (lRP) filed with the Colorado Public Utilities <br />Commission (CPUC). PSCC forecasts that annual (base case) peak demand will grow by <br />about 3.2% per year between 1999 and 2004, and 2.2% thereafter. After deducting <br />anticipated demand-side management credits, and adding necessary reserves, this forecast <br />shows an incremental need for approximately 200 to 300 MW of new capacity per year, <br />beginning in 2002, and continuing throughout the planning horizon. The cumulative need <br />for new resources is 1,307 MW by 2006 and 2,763 MW by 2011. <br /> <br />Tri-State G&T has not updated its lRP since 1996. That filing (Tri State G&T, 1996) <br />showed loads smaller than PSCC's, totaling about 1,400 MW of capacity, and 6,700 <br />million kWh of energy. Load was forecast to grow at about 1 % per year for the 20-year <br />planning horizon. Loads reported in PSCC (1999) grew substantially faster than that <br />between 1996 and 1999 (approximately 4%/year), so Tri-State's 1996 forecasts are <br />probably low. Tri-State G&T has flexible power purchase contracts with various entities <br />that allow it to increase purchases to meet increased demand. As such, Tri-State G&T <br />had no plans for new construction as of the 1996lRP. However, the Sponsors indicate <br />that Tri-State may still be a potential market, as AB Lateral sales could be used to offset <br />or replace purchases from other sources. <br /> <br />AB Laleral Hydropower Project <br /> <br />July 2000 <br /> <br />> <br /> <br />" <br /> <br />.., <br /> <br />"'1' <br />.'..... '.".. <br />-" <br />.... ..,...,. .,.~i~ <br />,... ~"",,~h ,_ <_,.~,_ ' <br />