Please reference the following number on all billings or pa meme. Contract AGREEMENT CONCERNING OF SHOSHONE CALL This Agreement is between the City and County of Denver, acting by and through its Board of Water Commissioners (Board), and Public Service Company of Colorado d/b/a Xcel Energy (Company). Recital The Board?s ability to store water in its reservoirs for bene?cial use by its customers is adversely impacted, especially in dry years, by the Company?s Shoshone Cali. Following the drought year of 2002, a brief relaxation of the Shoshone Call during the spring of 2003 provided some bene?t to storage reservoirs operated by both west slope and east slope entities, including the Board. Although a more comprehensive and long-term agreement on relaxation achieved through multi- party negotiations may be desirabie, the Company and the Board agree to a relaxation of the Call under the provisions in this Agreement. The Company agrees to participate in developing a long-term program of relaxation, including a relaxation of the junior Shoshone Call, with the Board, other water users on the Colorado River and appropriate west slope entities. Agreement 1. Agreement to Relax Call. When a water shortage occurs, as defined in Paragraph 2, the Company agrees to reduce the Shoshone Call to a one-turbine call of 704 cfs. if the Call is relaxed and the ?ow of the Colorado River at the Shoshone Power Plant, together with ?ows contributed by intervening tributaries, is not sufficient to meet the then-current demand of the major Grand Valley water rights, up to 1950 (commonly referred to as the ?Cameo Cali?), then the level of the Shoshone Call will be adjusted to an amount greater than 704 so as to avoid the initiation of a Cameo Cali. 2. Water Shortage Defined. For purposes of this Agreement, a water shortage occurs when the following two conditions are met: 3. Using its regular methodology and based on the ?normal" scenario, the Board predicts that reservoir storage in its system on July 1 will be at or below 80% full; and b. The Most Probable forecast of streamflow prepared by the Natural Resources Conservation Service (NCRS) orjointly by NCRS and the Colorado Basin River Forecast Center indicates that the April July flow of the Colorado River at the Kremmiing gage will be less than or equal to 85% of average. if no forecast for the Kremmiing gage is available, then the Dotsero gage will be used. 03/13/2006 1 3. Timing of Relaxation of Call. If the two forecasts described in paragraph 2 occur in March, then the call will be relaxed beginning March 14 until May 20, inclusive, in accordance with this Agreement. If the two conditions described in paragraph 2 occur in April or May forecasts, then the Call will be relaxed in accordance with this Agreement until May 20, inclusive. The methodology that the Board uses to predict system storage shall be substantially the same as that described in the attached Exhibit A. 4. Power lnterference. The Board agrees to pay power interference to compensate the Company for its incremental cost of replacement power and energy as a result of relaxing the Shoshone Call, regardless of which entity ultimately stores the water not called. The procedure for determining poWer interference is shown in Exhibit B. 5. Potential for Lonqer Call Relaxation. The Company agrees to consider a longer period of relaxation when water supplies are more severely impacted than described in paragraph 1, if such longer period is defined cooperatively between the Board, the Company and appropriate west slope entities. 6. Water for the Company?s Facilities. The Board agrees to deliver water as described in this paragraph to the Company?s Cherokee, Arapahoe, or Zuni Power Plants or a future Company power plant located within the Board's Combined Service Area. The Company will select the plant or plants to which the water will be delivered. Deliveries to the Arapahoe, Zuni or a future plant will be made to the South Platte River. Deliveries to the Cherokee plant will be made, at the Board?s choice, to the South Platte River or through the Board?s Recycled Water Plant. The Board may choose in its discretion the type of water delivered to these facilities, so long as the water is suitable for their use. The Board will. not deliver water under this paragraph to the South Platte River of the Cherokee plant's diversion structures. Any water delivered by the Board to the Company under this paragraph shall be used by the Company only at the plants listed in this paragraph 6 and only for purposes for which the Board?s water rights have been decreed. 6.1 Amount of Water. The Board shall deliver under this paragraph 6 an amount of water equivalent to 15% ofthe ?net water? it is able to store or divert as a direct result of the reduction of the Shoshone Call. ?Net water? is defined as the total amount of water the Board is able to store or divert as a direct result of the reduction of the Shoshone Call at the following facilities, less any deductions described below: a. Water stored or diverted at the Board?s Dillon Reservoir, less any water spilled from Dillon after filling and any water bypassed from Dillon for ?ood management purposes; and 03/ ?l 3/2006 2 b. Water stored or diverted at the Board?s Williams Fork Reservoir, less any water spilled from Williams Fork after filling and any water bypassed from Williams Fork for flood management purposes; and 6. Water stored in the Board?s account in Wolford Reservoir, less any water spilled from the Board?s account after filling; and d. Water diverted through the Board?s Moffat Tunnel, less any water Spilled from the Fraser Collection System in excess of the Forest Service minimum bypass flow requirements; and a. Water stored or diverted at any western sl0pe reservoir or storage account acquired or constructed by the Board after the date of this agreement, less any water spilled after filling and any water bypassed for flood management purposes. 6.2 Schedule for 15% Water Delivery. .The Board shall make deliveries under this paragraph 6 between June 1 in the same calendar year as the Shoshone Call is reduced and March 31 of the following calendar year. The delivery schedule will be subject to approval by the Company. 6.3 Cost of Water Delivered. For each acre foot of water delivered to the Company under this paragraph 6, the Company shall reimburse the Board for the Board?s power interference payments at the same rate per acre foot as the Board paid to the Company under paragraph 4. 7. Water for West Slope Entities. The Board agrees to make available to entities on the west slope, at no charge to the recipients,_an amount of water equivalent to 10% of the "net water? it is able to store or divert as a direct result of the reduction of the Shoshone Call. ?Net water? is defined in paragraph 6.1. The Board may choose in its discretion the method of delivery that is consistent with its water right decrees, so long as the delivery method is suitable for each recipient?s desired use. The Board shall deliver the water in the same calendar year as the Shoshone Call is reduced. The Board agrees to cooperate with the?Colorado River Water Conservation District to determine the particular west slope entities and the proportionate share of the water to be made available to each entity. 8. Additional East Slope Participants. The Board and the Company agree to make a good faith effort to secure commitments from the Municipal Subdistrict of the Northern Coiorado Water Conservancy District, the City of Aurora and Colorado Springs Utilities to deliver to the Company, at no charge, 15% of their additional water diversions that result from a relaxation of the Shoshone Call, in accordance with paragraph 6, and to deliver 10% of the water diverted or stored to west slope entities in accordance with paragraph 7. 03/13/2006 3 9. Priority System. Water made available by the relaxation of the Shoshone Call will be allocated in accordance with the priority system. 10. No Warranties. The Company is not warranting or representing that the diversion and use by the Board of additional water as a result of the relaxation of the Shoshone Call is administrable or lawful. To the extent that the State Engineer or a court with jurisdiction determines that the diversion and use by the Board of additional water as a result of the relaxation of the Call" Is not administrable or lawful the Company can continue to place the Shoshone notwithstanding this Agreement. 11. Increased Call for Company Operations. if the Company in its sole discretion determines that additional river flow is required for safe operation of the Shoshone Hydroelectric Station or the Company?s electrical system, then the Company may increase the Call, notwithstanding this Agreement. 12. Operational Meeting. The Company agrees to meet with the Board each October to discuss operation of the Shoshone Call and any planned outages of the Shoshone Plant for repair or maintenance during the following twelve months so that the parties may better coordinate their activities. 13. Sale of Shoshone Water Rights. In the event the Company should determine that it is in its best interest to sell the Shoshone water rights. it agrees to do so only on an open bidding basis in which the Board shall have an equal opportunity to purchase the water rights as all others. If the Company sells the Shoshone water rights to an entity other than the Board, the new owner shall have the right to terminate this Agreement two years after closing of the sale. 14. Term. This Agreement shall be effective as of January 1, 2007 and will terminate on February 28, 2032. 15. Prior Agreement. The previous Letter Agreement between the Company and the Board dated April 14, 1986, is hereby terminated in its entirety. IN WITNESS WHEREOF, the Board and the Company have executed this Agreement. PUBLIC SERVICE COMPANY OF ATTEST: COLORADO dlbla XCEL ENERGY Cum EL Way M, Secretary President and CEO Public Service Company of Colorado Reviewed Legal 03/13/2006 2 I3- "53% p. 4 2mm ATTEST: Secretary Qw Director of Phqr?jng D?I'rector of'Fin'aI?Ice APPROVED AS TO FORM: Lega?lrl?gg?zo> 03/13/2008 CITY AND COUNTY OF DENVER, actin by and through its BOA OF WATER COMMISSIONERS REGISTERED AND COUNTERSIGNED Dennis J. Gallagher, Auditor 19W A Title: a? Depu?y A mica? Exhibit A DESCRIPTION OF PROCEDURES USED BY THE BOARD FOR RESERVOIR PROJECTIONS Denver Water projects future reservoir levels in the springtime and less frequently throughout the rest of the year. Active storage levels (excluding the dead storage pools) for the10 largest reservoirs in Denver?s system (Antero, Eleven Mile, Cheesman, Marston, Chat?eld, Gross, Ralston, Dillon, Williams Fork, and Mountain) are forecasted. Calculations of gross and net aggregate reservoir contents are made. The calculation of net reservoir contents excludes any water in Denver?s system owed to others (primarily Green Mountain Reservoir). The net active storage of the 10 reservoirs will be used in the forecast for the Shoshone call reduction. The reservoir projections are based on natural stream?ow forecasts produced primarily by the Natural Resources Conservation Service (NRCS). However, streamflow forecasts produced by other organizations including the Colorado Basin River Forecast Center, the Bureau of Reclamation, the Northern Colorado Water Conservancy District and Denver Water are also used. The reservoir projections utilize correlations between natural stream?ow and divertible stream?ow to estimate how much of the natural streamflow can be diverted under Denver?s water rights. Other factors incorporated in the reservoir projections include projections of treated water use, raw water deliveries, evaporation (based on rates approved by the State Engineer?s Office), minimum bypass and release requirements, carriage losses assessed by the State Engineer?s Office, existing capacities of diversion and conveyance facilities, system outages and river calls. The assumed treated water use considers any water use restrictions approved by the Denver Water Board at the time of the forecast. Usually, three levels of reservoir projections are produced. These projections are based on three scenarios after the forecast date: ?dry?, ?normal? and ?wet? conditions. The ?dry? scenario is based on the "reasonable minimum? streamflow forecasts, which have a 90% chance of being exceeded. The ?normal" scenario is based on the ?most probable? stream?ow forecasts, which have a 50% chance of being exceeded. The ?wet" scenario is based on the ?reasonable maximum" streamflow forecasts, which have a 10% chance of being exceeded. The ?normal" scenario Will be used for the Shoshone call reduction. 03/13/2006 6 Exhibit COMPENSATION FOR POWER INTERFERENCE The Board agrees to pay power interference to compensate the Company for its incremental cost of replacement power and energy as a result of relaxing the Shoshone Call. The procedure for determining power interference is shown below. Depletions to Shoshone Power Plant The Board will compensate the Company for each acre?foot of net turbine flow depletion caused to the Shoshone Power Plant through the relaxation of the Shoshone Call. Net depletions are defined as gross depietions caused by the Board and all other water users upstream of the Shoshone power plant, less any water subsequently released from Green Mountain and Wolford Reservoirs utilized to generate power at the Shoshone plant. Some of the water stored in Green Mountain and Wolford as a result of relaxation of the Cali will later be released, run through the Shoshone Plant for power generation, and delivered for use below the plant; such amounts of water do not constitute a net depietion for purposes of calculating power interference. Similarly, amounts of water spilled from Dillon Reservoir, Williams Fork Reservoir, the Board's account in Wolford Reservoir, or a new west slope reservoir or storage account described in Paragraph and run through the Shoshone Plant for power generation, do not constitute a net depletion for purposes of calculating power interference. Depietions will be calculated at the Shoshone plant and will be adjusted for stream carriage losses assessed by the State Engineer in water rights administration. - Reimbursement to Xcel The Board will reimburse the Company for power interference at the rate of at least $500 per acre?foot of the net depletion described above. The $5.00 per acre-foot minimum will be adjusted on a basis (but not below $5.00 per acre-foot) by the change in the Price of Spot Gas Delivered to Pipelines for Colorado Interstate Gas. Rocky Mountain (Index) as published in ?Platts inside FERC Gas Market Report,? compared to a baseline representing the average index for the first three months of 2006. Accountinq and Payment. After the Call relaxation has ended, the Board will prepare an accounting of the power interference and provide it to the Company for review. Once final accounting as been determined, the Board will make payment to the Company within 60 days. Upon mutual agreement and the development of mutually agreeable terms, the Board may substitute a delivery of energy to the Company for the payment of power interference. 03/13/2006 7