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Xcel Energy Inc – ‘10-K’ for 12/31/09 – ‘XML.R25’

On: Friday, 2/26/10, at 4:23pm ET · For: 12/31/09 · Accession #: 1047469-10-1536 · File #: 1-03034

  As Of               Filer                 Filing    For·On·As Docs:Size             Issuer                      Filing Agent

 2/26/10  Xcel Energy Inc                   10-K       12/31/09   53:8.9M                                   Toppan Merrill-FA

Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                       HTML   2.22M 
 2: EX-10.24    Material Contract                                   HTML     22K 
 4: EX-21.01    Subsidiaries List                                   HTML     27K 
 5: EX-23.01    Consent of Experts or Counsel                       HTML     24K 
 6: EX-24.01    Power of Attorney                                   HTML     39K 
10: EX-99.01    Miscellaneous Exhibit                               HTML     23K 
 3: EX-12.01    Statement re: Computation of Ratios                 HTML     42K 
 7: EX-31.01    Certification -- §302 - SOA'02                      HTML     24K 
 8: EX-31.02    Certification -- §302 - SOA'02                      HTML     24K 
 9: EX-32.01    Certification -- §906 - SOA'02                      HTML     20K 
42: XML         IDEA XML File -- Definitions and References          XML    126K 
49: XML         IDEA XML File -- Filing Summary                      XML    158K 
47: XML.R1      Consolidated Statements of Income                    XML    362K 
48: XML.R2      Consolidated Statements of Income (Parenthetical)    XML     49K 
28: XML.R3      Consolidated Statements of Cash Flows                XML    504K 
33: XML.R4      Consolidated Balance Sheets                          XML    323K 
40: XML.R5      Consolidated Statements of Common Stockholders'      XML    531K 
                Equity and Comprehensive Income                                  
39: XML.R6      Consolidated Statements of Common Stockholders'      XML     73K 
                Equity and Comprehensive Income (Parenthetical)                  
52: XML.R7      Consolidated Statements of Capitalization,           XML   2.19M 
                Long-Term Debt                                                   
22: XML.R8      Consolidated Statements of Capitalization, Equity    XML    288K 
38: XML.R9      Consolidated Statements of Capitalization, Equity    XML     72K 
                (Parenthetical)                                                  
20: XML.R10     Summary of Significant Accounting Policies           XML     73K 
19: XML.R11     Accounting Pronouncements                            XML     45K 
27: XML.R12     Selected Balance Sheet Data                          XML     59K 
44: XML.R13     Discontinued Operations                              XML     50K 
29: XML.R14     Short-Term Borrowings and Other Financing            XML     35K 
                Instruments                                                      
30: XML.R15     Long-Term Borrowings and Other Financing             XML     73K 
                Instruments                                                      
36: XML.R16     Generating Plant Ownership and Operation             XML     69K 
53: XML.R17     Income Taxes                                         XML    142K 
25: XML.R18     Preferred and Common Stock                           XML     91K 
17: XML.R19     Share-Based Compensation                             XML    139K 
32: XML.R20     Benefit Plans and Other Postretirement Benefits      XML    270K 
43: XML.R21     Other Income, Net                                    XML     43K 
23: XML.R22     Derivative Instruments                               XML    152K 
41: XML.R23     Financial Instruments                                XML     65K 
31: XML.R24     Fair Value Measurements                              XML    110K 
51: XML.R25     Rate Matters                                         XML    106K 
46: XML.R26     Commitments and Contingent Liabilities               XML    218K 
34: XML.R27     Nuclear Obligations                                  XML     64K 
37: XML.R28     Regulatory Assets and Liabilities                    XML     87K 
18: XML.R29     Segments and Related Information                     XML     93K 
21: XML.R30     Summarized Quarterly Financial Data (Unaudited)      XML     65K 
24: XML.R31     Lubbock Electric Distribution Assets                 XML     34K 
26: XML.R32     Condensed Financial Statements of Xcel Energy Inc.   XML    124K 
35: XML.R33     Valuation and Qualifying Accounts                    XML     44K 
45: XML.R34     Document and Entity Information                      XML    129K 
50: EXCEL       IDEA Workbook of Financial Reports (.xls)            XLS    220K 
11: EX-101.INS  XBRL Instance -- xel-20091231                        XML   2.29M 
13: EX-101.CAL  XBRL Calculations -- xel-20091231_cal                XML    205K 
14: EX-101.DEF  XBRL Definitions -- xel-20091231_def                 XML    194K 
15: EX-101.LAB  XBRL Labels -- xel-20091231_lab                      XML   1.03M 
16: EX-101.PRE  XBRL Presentations -- xel-20091231_pre               XML    524K 
12: EX-101.SCH  XBRL Schema -- xel-20091231                          XSD    115K

‘XML.R25’ — Rate Matters

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<table style="font-size:10pt; font-family:'Times New Roman',times,serif;"> <tr> <td> 16. Rate Matters NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings — MPUC Base Rate NSP-Minnesota Electric Rate Case — In November 2008, NSP-Minnesota filed a request with the MPUC to increase Minnesota electric rates by $156 million annually. This request was later modified to $136 million. In September 2009, the MPUC voted to approve a rate increase of approximately $91.4 million. As part of its decision, the MPUC approved a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation and decommissioning expenses, effective Jan. 1, 2009. This decision reduced NSP-Minnesota's overall revenue deficiency by approximately $40 million, while at the same time reducing expense accruals by a corresponding amount. A summary of the key terms is listed below: <div style="PADDING-RIGHT: 0pt; PADDING-LEFT: 0pt; PADDING-BOTTOM: 0pt; MARGIN-LEFT: 20%; WIDTH: 60%; PADDING-TOP: 0pt; POSITION: relative">   <div align="center"> <table cellspacing="0" cellpadding="0" width="100%" border="0"> <tr style="HEIGHT: 0px"> <td style="FONT-FAMILY: times" align="left"></td> <td style="FONT-FAMILY: times" width="12"></td> <td style="FONT-FAMILY: times" align="right" width="6"></td> <td style="FONT-FAMILY: times" width="73"></td> <td style="FONT-FAMILY: times" width="12"></td> <td style="FONT-FAMILY: times" align="right" width="6"></td> <td style="FONT-FAMILY: times" width="73"></td> <td style="FONT-FAMILY: times" width="12"></td></tr> <tr style="HEIGHT: 0px" valign="bottom"> <th style="FONT-FAMILY: times" align="left"> </th> <th style="FONT-FAMILY: times"> </th> <th style="BORDER-BOTTOM: #000000 1pt solid; FONT-FAMILY: times" align="center" colspan="2">Revised Request </th> <th style="FONT-FAMILY: times"> </th> <th style="BORDER-BOTTOM: #000000 1pt solid; FONT-FAMILY: times" align="center" colspan="2">Approved </th> <th style="FONT-FAMILY: times"> </th></tr> <tr style="HEIGHT: 0px" valign="top" bgcolor="#CCEEFF"> <td style="FONT-FAMILY: times" valign="bottom"> Rate increase</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">$</td> <td style="FONT-FAMILY: times" valign="bottom" align="right">136 million</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">$</td> <td style="FONT-FAMILY: times" valign="bottom" align="right">91 million</td> <td style="FONT-FAMILY: times" valign="bottom"> </td></tr> <tr style="HEIGHT: 0px" valign="top" bgcolor="white"> <td style="FONT-FAMILY: times" valign="bottom"> Return on equity</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">11.0</td> <td style="FONT-FAMILY: times" valign="bottom">%</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">10.88</td> <td style="FONT-FAMILY: times" valign="bottom">%</td></tr> <tr style="HEIGHT: 0px" valign="top" bgcolor="#CCEEFF"> <td style="FONT-FAMILY: times" valign="bottom"> Equity ratio</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">52.5</td> <td style="FONT-FAMILY: times" valign="bottom">%</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">52.5</td> <td style="FONT-FAMILY: times" valign="bottom">%</td></tr> <tr style="HEIGHT: 0px" valign="top" bgcolor="white"> <td style="FONT-FAMILY: times" valign="bottom"> Electric rate base</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">$</td> <td style="FONT-FAMILY: times" valign="bottom" align="right">4.1 billion</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">$</td> <td style="FONT-FAMILY: times" valign="bottom" align="right">4.1 billion</td> <td style="FONT-FAMILY: times" valign="bottom"> </td></tr> <tr style="HEIGHT: 0px" valign="top" bgcolor="#CCEEFF"> <td style="FONT-FAMILY: times" valign="bottom"> Depreciation life extension for Prairie Island nuclear plant</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">0 years</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">10 years</td> <td style="FONT-FAMILY: times" valign="bottom"> </td></tr></table></div> </div> The written order was issued Oct. 23, 2009. As of December 2009, NSP-Minnesota recorded a customer refund of approximately $39.7 million to reflect the difference between interim rates that were implemented Jan. 2, 2009 and the amount approved by the MPUC. NSP-Minnesota Gas Rate Case — In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota gas rates by $16.2 million for 2010, which represents a 2.8 percent overall increase in customer bills. This request is based on a ROE of 11 percent, an equity ratio of 52.46 percent and a rate base of $441 million. NSP-Minnesota also requested an additional increase of $3.45 million, for recovery of pension funding costs effective Jan. 1, 2011 to comply with federal law. In December 2009, the MPUC voted to approve an interim rate increase of $11.1 million, subject to refund. These rates went into effect on Jan. 11, 2010. The procedural schedule is listed below and a decision is expected in the fall of 2010. <dl compact="compact"> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Intervenor direct testimony on May 3, 2010; </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">NSP-Minnesota rebuttal testimony on June 2, 2010; </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Surrebuttal testimony on June 15, 2010; </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Evidentiary hearings on June 21-25, 2010; </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Initial briefs on July 27, 2010; </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Reply briefs and proposed findings on Aug. 19, 2010; and </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">ALJ report on Oct. 1, 2010.</dd></dl> Electric, Purchased Gas and Resource Adjustment Clauses TCR Rider — The MPUC has approved a TCR rider, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases. The MPUC approved a rider request to recover approximately $14 million in 2009. NSP-Minnesota has a request pending seeking recovery of $12.1 million in 2010. The OES recommended disallowance of $1.7 million of plant costs because one project was over budget and also recommended that the Brookings line, which is subject to dispute at the FERC on cost allocation, not be recovered through the rider at this time. The request is pending MPUC action. RES Rider — The MPUC has approved a rider to recover the costs for utility-owned projects implemented in compliance with the RES. In 2009, the MPUC approved the RES rider request to recover approximately $22 million in 2009. In September 2009, NSP-Minnesota submitted its proposed RES rider, seeking to recover $45.6 million in 2010. The OES expressed concerns because some of the projected costs were slightly higher than the levels included in NSP-Minnesota's certificate filings and requested additional information, which has been provided. The request is pending MPUC action. MERP Rider — The MPUC authorized NSP-Minnesota to recover costs related to environmental improvement projects amounting to approximately $113.7 million in 2009 through the MERP rider. In December 2009, the MPUC authorized a new rate adjustment, which will recover approximately $116.7 million in 2010. Mercury Cost Rider — The MPUC has approved mercury control plans for reducing mercury emissions at the Sherco Unit 3 and A. S. King plants. A sorbent injection control system was put into service at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled to be completed in December 2010. Currently, the estimated project costs are approximately $6.6 million for these two units, and the MPUC authorized NSP-Minnesota to collect the 2010 revenue requirement associated with these projects, which is approximately $3.5 million from customers through a mercury rider in 2010. On Dec. 21, 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and MPCA. Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost rider. The plan proposes a flexible program of testing and monitoring as new technology emerges and federal regulations change over the next several years. The plan calls for the addition of sorbent injection by the statutory deadline of the end of 2014. The MPCA has six months to review the plan. SEP Rider — In September 2009, the MPUC approved NSP-Minnesota proposed rider to recover approximately $2.5 million from its electric customers and $0.1 million from its natural gas customers to recover costs related to SEP mandates and a cast iron natural gas pipe replacement project to reduce GHG emissions. The revised SEP rate recovery factors were placed into effect in October 2009. Energy Innovation Corridor (EIC) Initiative — In December 2009, NSP-Minnesota filed a request with the MPUC for approval of specific projects totaling $15 million including a $2 million deferral request. The EIC initiative will be a first-of-its-kind clean energy and transportation model in an established urban center in the upper Midwest. The 2009 legislation authorized rider cost recovery for MPUC approved projects, including NSP-Minnesota's costs to relocate its facilities along the transportation corridor. Rider cost recovery is also authorized for MPUC approved EIC projects that demonstrate the best energy efficiency management practices and the installation of innovative and sustainable energy technologies and programs for transforming a mature urban center into a national model for the future development of transportation and energy corridors. The EIC initiative will advance critical local, state, regional and federal efforts to invest in energy efficiency, transportation electrification, renewable energy and smart grid technology. MPUC action is pending. Annual Automatic Adjustment Report for 2007/2008 — In September 2008, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2007 through June 30, 2008. During that time period, $848.5 million in fuel and purchased energy costs, including $258.8 million of MISO charges, were recovered from Minnesota electric customers through the FCA. In addition, approximately $680 million of purchased natural gas and transportation costs were recovered through the PGA. In February 2010, the MPUC voted to accept the 2008 natural gas annual automatic adjustment report. Annual Automatic Adjustment Report for 2008/2009 — In September 2009, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2008 through June 30, 2009. During that time period, $803.6 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the FCA. In addition, approximately $499.4 million of purchased natural gas and transportation costs were recovered through the PGA. Comments are due in May 2010 on NSP-Minnesota's 2008/2009 electric and natural gas annual automatic adjustment reports. The request is pending MPUC action. Conservation Incentive Filing — In July 2009, NSP-Minnesota filed its proposed incentive plan for achieving significantly higher DSM goals. The incentive would allow for sharing of savings of up to 15 percent of the net present value of benefits, depending on the level of savings achieved. In December 2009, the MPUC approved the proposed shared savings model. The plan would allow NSP-Minnesota to earn a higher incentive than under the previous method if it achieves the higher goals established by the OES. The amount of the incentive increases to the extent that NSP-Minnesota cost-effectively exceeds the goal. A written order was issued in January 2010. Gas Meter Module Failures — Approximately 8,700 customers in the St. Cloud and East Grand Forks areas of Minnesota and about 4,000 customers in the Fargo, N.D. area were under billed for a period of time during the 2007-2008 heating season due to the failure of the automated meter reading (AMR) module installed on their natural gas meters. While the modules failed to register usage, the meters continued to function. Pursuant to the NDPSC-approved plan, which provided customers with a $50 service quality credit for each customer experiencing a module failure, NSP-Minnesota began implementing the service quality credits and the rebilling of remaining North Dakota customers in June 2009. In total, NSP-Minnesota rebilled North Dakota customers approximately $1.5 million for the estimated gas usage during the module failure period. In July 2009, NSP-Minnesota filed with the MPUC a withdrawal of its request to rebill Minnesota customers experiencing a module failure, which the MPUC approved in October 2009. NSP-Minnesota completed the customer refunds in January 2010. In November 2009, NSP-Minnesota completed its dispute resolution with its provider of the AMR modules and meter reading services, and filed a summary of the resolution and proposed disposition of any proceeds with the MPUC. MPUC action is pending. NSP-Minnesota has determined that a number of AMR modules designed for commercial customers are defective and as a result broadened its efforts to evaluate the performance of both gas and electric AMR modules. Annual Review of Remaining Lives — In February 2009, NSP-Minnesota filed a petition with the MPUC requesting an increase in proposed service lives, salvage rates and resulting depreciation rates for its electric and gas production facilities and a depreciation study for other gas and electric assets, effective Jan 1, 2009. In addition, the OES recommended a 10-year lengthening of depreciation life of the Prairie Island nuclear plant. In July 2009, the MPUC approved the proposed service lives, salvage rates, and resulting depreciation rates effective Jan. 1, 2009, for plant in service, with the exception of the Prairie Island nuclear plant. In the NSP-Minnesota electric rate case, the MPUC extended the depreciation life of the Prairie Island nuclear plant by 10 years beyond the current license life in light of NSP-Minnesota's application to extend the life of its nuclear plants by 20 years. Nuclear Decommissioning Expenses — In June 2009, the MPUC issued its order in its review of NSP-Minnesota's 2009 nuclear plant decommissioning accruals. The order extended the decommissioning life for the Prairie Island nuclear plant by 10 years. The order reduced the amount of future nuclear decommissioning expenses that must be collected from customers from $32 million to zero, effective Jan. 1, 2009. In August 2009, NSP-Minnesota filed a proposal with the MPUC to provide one-time refunds to return to customers their contributions of $22.8 million made to the external escrow decommissioning fund for the Monticello nuclear plant, which the MPUC approved in November 2009. NSP-Minnesota began refunding the excess escrow to customers in February 2010. Pending and Recently Concluded Regulatory Proceedings — NDPSC and SDPUC South Dakota Electric Rate Case — In June 2009, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $18.6 million annually, or 12.7 percent. This proposed increase includes approximately $2.9 million in revenues currently recovered through automatic recovery mechanisms. Thus, the requested increase, net of current automatic recovery mechanisms, is approximately $15.7 million or 10.7 percent. The request is based on a 2008 historic test year adjusted for known and measurable changes in rate base and O&M expenses, an electric rate base of $282 million, a requested ROE of 11.25 percent, and an equity ratio of 51.63 percent. On Jan. 5, 2010, the South Dakota Commission approved a settlement agreement, which increases electric base rates by $10.9 million. The primary difference between the approved rate increase and requested amount was due to a lower ROE and the use of a 20-year life for the Prairie Island nuclear plant, which reduced the revenue deficiency and expense accruals by a corresponding amount. New rates were effective on Jan. 18, 2010. Pending and Recently Concluded Regulatory Proceedings — FERC Revenue Sufficiency Guarantee (RSG) Charges — The MISO tariff charges certain market participants a real-time RSG charge, which is designed to ensure that any generator scheduled or dispatched by MISO will receive no less than its offer price for start-up, no-load and incremental energy. A proposal in 2005 by MISO to refine the RSG charge initiated protracted proceedings. In the subsequent compliance proceeding, the FERC has issued numerous orders, attempting to refine and clarify the RSG charge. With the issuance of these orders, the FERC has directed certain refunds to market participants, but has subsequently refined or waived various refund requirements. The FERC granted rehearing in part of certain earlier orders directing refunds to correct a rate mismatch in the RSG charge. In August 2007, numerous parties filed complaints against MISO, arguing that the allocation of the RSG charge (only to certain market participants actually withdrawing energy) was unjust, unreasonable, and unduly discriminatory. After protracted proceedings, the FERC found in November 2008 that the RSG charge was unjust and unreasonable, and directed refunds. In May 2009, FERC granted rehearing in part regarding the applicability of refunds for the RSG charges. Specifically, the FERC determined that the refund-effective date is November 2008, the date of the FERC order determining that the allocation to market participants of the RSG charges was unjust and unreasonable. The FERC directed MISO to implement an interim RSG cost allocation to be effective starting in August 2007. The FERC further directed MISO to submit a complete and final proposal, to be implemented on a prospective basis after the commencement of the MISO's ASMs in January 2009. In February 2009, MISO submitted a filing to implement the new RSG rate design; however, the FERC has not yet rendered a final decision to implement the new rate design. In August 2009, the FERC issued an order in which it invalidated numerous exemptions to the RSG that had previously been utilized by MISO through its business practice manuals. Several parties have sought rehearing of the order and a final FERC decision is still pending. Xcel Energy is a party to each of the relevant RSG-related proceedings. Each of the relevant RSG-related orders has been the subject of requests for rehearing at the FERC and petitions for review filed at the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The separate RSG proceedings have proceeded in parallel at the FERC, and the most recent orders are subject to pending requests for rehearing. The D.C. Circuit proceedings are being held in abeyance pending final action in the FERC proceedings. FERC Section 5 Rate Cases for Interstate Gas Pipelines — In November 2009, the FERC approved orders initiating rate investigations under Section 5 of the Natural Gas Act (NGA) against Northern Natural Gas Company (NNG) and Great Lakes Gas Transmission Company (GLGT). NSP-Minnesota and NSP-Wisconsin are together the largest customer on NNG, holding $41 million per year of maximum rate storage and transportation contracts. According to the FERC orders, FERC staff concluded, based on a review of the financial information filed with the FERC by the pipelines, that each of the pipelines are substantially over-recovering their cost of service and earning excessive ROEs. The orders require the pipelines to file full cost and revenue studies, and the matters were set for hearing before an ALJ on an expedited basis. If the FERC orders the pipelines to reduce their transportation and storage rates, the rate reductions and any associated refunds would be reflected in the purchased gas and electric fuel cost adjustment mechanisms of the Xcel Energy utility subsidiaries. Xcel Energy has filed an intervention as part of a group of similarly-situated GLGT shippers in the GLGT Section 5 case, and filed to intervene individually in the NNG Section 5 rate case. The FERC ALJ conducted a pre-hearing conference on Jan. 12, 2010 and established the procedural schedule for the proceedings. If fully litigated, the Section 5 rate cases can be expected to go to hearings before the ALJ beginning Aug. 2, 2010. An initial decision must be issued by Nov. 11, 2010. NSP-Wisconsin Pending and Recently Concluded Regulatory Proceedings — PSCW Base Rate 2008 Electric Rate Case — Nuclear Decommissioning Expenses — In January 2008, the PSCW issued the final order in NSP-Wisconsin's 2008 test year rate case. The PSCW's final order included recovery of $8.7 million of annual nuclear decommissioning expenses, subject to refund, in anticipation of potential decreases in NSP-Minnesota's decommissioning expenses. In June 2009, the MPUC issued the final order in its review of NSP-Minnesota's 2009 nuclear plant decommissioning accrual, and as a result of that order, the Wisconsin retail jurisdiction's share of annual nuclear decommissioning expenses decreased to approximately $1.4 million, effective January 2009. The PSCW reviewed NSP-Wisconsin's nuclear decommissioning expenses in the context of the company's 2010 electric rate case, and reduced the NSP-Wisconsin's 2010 revenue requirements pursuant to the refund provision in the 2008 rate case order. The June 2009 MPUC order also directed NSP-Minnesota to return to customers their contributions made to the external escrow decommissioning fund for the Monticello nuclear plant. In NSP-Wisconsin's 2010 electric rate case the PSCW decided that NSP-Wisconsin should return the Wisconsin retail jurisdiction's share of these funds, with interest to customers in the next rate case. NSP-Wisconsin's share of these funds is approximately $5.9 million as of Dec. 31, 2009. 2010 Electric and Natural Gas Rate Case — In June 2009, NSP-Wisconsin filed an electric and gas rate case in Wisconsin seeking an increase in retail electric rates of $30.4 million, or 5.7 percent, and proposed no change in natural gas rates. The request was based on an ROE of 10.75 percent, an equity ratio of 53.12 percent, an electric rate base of $644 million, a gas rate base of $81 million and a 2010 forecasted test year. The request was comprised of a base rate increase of $45.1 million offset by projected fuel decreases of $14.7 million. In December 2009, the PSCW approved an electric rate increase of approximately $6.4 million or 1.2 percent and no change in gas rates, based on a 10.4 percent ROE and a 52.30 percent equity ratio. The PSCW ordered NSP-Wisconsin to apply $6.4 million of the estimated 2009 fuel refund obligation to offset the rate increase. Lastly, the PSCW approved NSP-Wisconsin's request for a limited rate case reopener in 2011 to update certain costs that are billed to NSP-Wisconsin through the interchange agreement with NSP-Minnesota. The base non-fuel adjustments made by the PSCW include: (1) adjustments to the ROE and equity ratio as discussed above; (2) reduced interchange agreement fixed charge billings; and (3) a disallowance of certain employee compensation expenses. In addition, the PSCW adjustments include a $9.1 million reduction for Prairie Island nuclear plant decommissioning and depreciation expense as a result of the 10-year life extension approved by the MPUC earlier this year. The PSCW approved NSP-Wisconsin's request to discontinue the practice of reducing rate base and common equity to account for appropriated retained earnings associated with certain hydro licenses. A summary of the PSCW's adjustments is listed below: <div style="PADDING-RIGHT: 0pt; PADDING-LEFT: 0pt; PADDING-BOTTOM: 0pt; MARGIN-LEFT: 10%; WIDTH: 80%; PADDING-TOP: 0pt; POSITION: relative">   <div align="center"> <table cellspacing="0" cellpadding="0" width="100%" border="0"> <tr style="HEIGHT: 0px"> <td style="FONT-FAMILY: times" align="left" width="9"></td> <td style="FONT-FAMILY: times" align="left"></td> <td style="FONT-FAMILY: times" width="12"></td> <td style="FONT-FAMILY: times" align="right" width="6"></td> <td style="FONT-FAMILY: times" width="65"></td> <td style="FONT-FAMILY: times" width="12"></td> <td style="FONT-FAMILY: times" align="right" width="6"></td> <td style="FONT-FAMILY: times" width="65"></td> <td style="FONT-FAMILY: times" width="12"></td></tr> <tr style="HEIGHT: 0px" valign="bottom"> <th style="FONT-FAMILY: times" align="left" colspan="2"> </th> <th style="FONT-FAMILY: times"> </th> <th style="BORDER-BOTTOM: #000000 1pt solid; FONT-FAMILY: times" align="center" colspan="2">Request </th> <th style="FONT-FAMILY: times"> </th> <th style="BORDER-BOTTOM: #000000 1pt solid; FONT-FAMILY: times" align="center" colspan="2">PSCW Approved </th> <th style="FONT-FAMILY: times"> </th></tr> <tr style="HEIGHT: 0px" valign="bottom"> <th style="FONT-FAMILY: times" align="left" colspan="2"> </th> <th style="FONT-FAMILY: times"> </th> <th style="FONT-FAMILY: times" align="center" colspan="5">Millions of Dollars </th> <th style="FONT-FAMILY: times"> </th></tr> <tr style="HEIGHT: 0px" valign="top" bgcolor="#CCEEFF"> <td style="FONT-FAMILY: times" valign="bottom" colspan="2"> Base non-fuel</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">$</td> <td style="FONT-FAMILY: times" valign="bottom" align="right">45.1</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">$</td> <td style="FONT-FAMILY: times" valign="bottom" align="right">35.8</td> <td style="FONT-FAMILY: times" valign="bottom"> </td></tr> <tr style="HEIGHT: 0px" valign="top" bgcolor="white"> <td style="FONT-FAMILY: times" valign="bottom" colspan="2"> Fuel</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">(14.7</td> <td style="FONT-FAMILY: times" valign="bottom">)</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">(20.3</td> <td style="FONT-FAMILY: times" valign="bottom">)</td></tr> <tr style="HEIGHT: 0px" valign="top" bgcolor="#CCEEFF"> <td style="FONT-FAMILY: times" valign="bottom" colspan="2"> Prairie Island decommissioning</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">—</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">(9.1</td> <td style="FONT-FAMILY: times" valign="bottom">)</td></tr> <tr style="FONT-SIZE: 1.5pt; HEIGHT: 0px" valign="top"> <td style="FONT-FAMILY: times" valign="bottom" colspan="2"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="BORDER-BOTTOM: #000000 1pt solid; FONT-FAMILY: times" valign="bottom" align="right" colspan="2"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="BORDER-BOTTOM: #000000 1pt solid; FONT-FAMILY: times" valign="bottom" align="right" colspan="2"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td></tr> <tr style="HEIGHT: 0px" valign="top" bgcolor="white"> <td style="FONT-FAMILY: times"> </td> <td style="FONT-FAMILY: times" valign="bottom"> Rate increase</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">$</td> <td style="FONT-FAMILY: times" valign="bottom" align="right">30.4</td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="FONT-FAMILY: times" valign="bottom" align="right">$</td> <td style="FONT-FAMILY: times" valign="bottom" align="right">6.4</td> <td style="FONT-FAMILY: times" valign="bottom"> </td></tr> <tr style="FONT-SIZE: 1.5pt; HEIGHT: 0px" valign="top"> <td style="FONT-FAMILY: times" valign="bottom" colspan="2"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="BORDER-BOTTOM: #000000 2.25pt double; FONT-FAMILY: times" valign="bottom" align="right" colspan="2"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td> <td style="BORDER-BOTTOM: #000000 2.25pt double; FONT-FAMILY: times" valign="bottom" align="right" colspan="2"> </td> <td style="FONT-FAMILY: times" valign="bottom"> </td></tr></table></div> </div> Other 2009 Electric Fuel Cost Recovery — NSP-Wisconsin's actual fuel and purchased power costs for 2009 were less than the amount authorized in rates, primarily due to lower load and lower market prices for fuel and purchased power. In April 2009, the PSCW determined fuel costs were outside the established variance ranges and set NSP-Wisconsin's electric rates subject to refund with interest, pending a full review of 2009 fuel costs. The PSCW has not yet completed its review of NSP-Wisconsin's 2009 fuel costs. However, based on actual 2009 fuel costs, NSP-Wisconsin has established a liability of $18.5 million to reflect its expected 2009 fuel refund obligation. As noted above, the PSCW ordered NSP-Wisconsin to apply $6.4 million of the 2009 fuel refund obligation to offset the 2010 electric rate increase. NSP-Wisconsin filed an application with the PSCW in February 2010, requesting authorization to immediately refund the remainder of its 2009 fuel refund obligation to customers before the PSCW completes its review of actual 2009 fuel costs. If the PSCW review determines an additional refund is owed, the balance would be deferred and returned to customers in NSP-Wisconsin's next rate filing. PSCo Pending and Recently Concluded Regulatory Proceedings — CPUC Base Rate PSCo 2009 Electric Rate Case — In November 2008, PSCo filed a request with the CPUC to increase Colorado electric rates by $174.7 million annually, or approximately 7.4 percent. The rate filing was based on a 2009 forecast test year, an electric rate base of $4.2 billion, a requested ROE of 11.0 percent and an equity ratio of 58.08 percent. PSCo's request included a return of approximately $40 million for CWIP associated with incremental expenditures on the Comanche Unit 3 since Jan. 1, 2007. PSCo does not record AFUDC income for the months this return is actually received from customers. In March 2009, PSCo filed rebuttal testimony and revised its rate increase request to $159.3 million to reflect updated data. In May 2009, the CPUC approved a blackbox settlement agreement which provided for an overall $112.2 million increase in base rates. The settlement provides that incremental CWIP not included in existing rates for the Comanche Unit 3 be removed from rate base and that PSCo would be allowed to continue to record AFUDC income on this balance until the Comanche Unit 3 is placed into service. New rates went into effect on July 1, 2009. PSCo 2010 Electric Rate Case — In May 2009, PSCo filed with the CPUC a request to increase Colorado electric rates by $180.2 million, or 6.8 percent, effective in 2010. The request was based on a 2010 forecast test year, an 11.25 percent ROE, a rate base of $4.4 billion and an equity ratio of 58.05 percent, In October 2009, PSCo filed rebuttal testimony and revised the requested rate increase to $177.4 million. In November 2009, PSCo reached a settlement agreement with certain intervenors. The settlement included an electric rate increase of approximately $136 million, effective Jan. 1, 2010. The settlement was based on a 10.5 percent ROE and reflects PSCo's actual capital structure. The settlement was based on an historic test year, adjusted for 2010 known and measurable changes related to plant investment as well as certain operating costs. In December 2009, the CPUC approved a rate increase of approximately $128.3 million. The difference between the settlement rate increase and the approved amount was primarily related to adjustments related to rate base for non-major projects and an adjustment to interest on long-term debt. In December 2009, due to the delay in Comanche Unit 3 coming online, the CPUC approved PSCo's proposal to phase in the approved electric rate increase to reflect the actual cost of service. This decision is not expected to have a material impact on PSCo or Xcel Energy's financial results. Under the plan the following increases will be implemented: <dl compact="compact"> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">A rate increase of $67 million was implemented on Jan. 1, 2010. The adjustments to the rate increase, as a result of the delay of the in-service date of Comanche Unit 3, include reduced O&M, property taxes, the impact of a delay in changes to jurisdictional allocators and depreciation expenses. </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Base rates will increase to $121 million, once Comanche Unit 3 goes into service (currently expected by the end of the first quarter of 2010). </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Finally, base rates will increase to $128.3 million on Jan. 1, 2011 to reflect 2011 property taxes.</dd></dl> Several parties, including the Office of Consumer Counsel, have filed motions for reconsideration. The CPUC has denied those requests that would change the initial order approving the rate increase, with the exception of PSCo's request to not include long-term debt interest in the working capital calculation. The CPUC will reconsider PSCo's request after parties have filed additional comments. A written order is pending. Unreasonable Rates for Natural Gas Formal Complaint — In July 2009, the trial advocacy staff of the CPUC proposed a formal draft complaint against PSCo for unjust and unreasonable rates for natural gas service associated with earnings in excess of PSCo's authorized return that occurred in 2008. In January 2010, the CPUC opened a proceeding and assigned this matter to an ALJ. The procedural schedule in the case has been set as follows: <dl compact="compact"> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Direct testimony of CPUC staff on May 10, 2009; </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">PSCo answer testimony on June 28, 2010; </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Staff rebuttal testimony on July 19, 2010; </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Surrebuttal testimony on Aug. 9, 2010; and </dd> <dt style="MARGIN-BOTTOM: -11pt; FONT-FAMILY: times">•</dt> <dd style="FONT-FAMILY: times">Hearings on Aug. 23 - 27, 2010. </dd></dl> TCA Rider — PSCo filed its annual update to the TCA rider in November 2008, and new rates went into effect on Jan. 1, 2009, to recover approximately $18.0 million on an annual basis until the rates in the 2009 rate case take effect. Coincident with the implementation of new electric rates on July 1, 2009, approximately $16.0 million from the TCA rider were included in base rates with a corresponding reduction in the TCA rider. Renewable Energy Credit (REC) Sharing Settlement — In August 2009, PSCo filed an application seeking approval of treatment of margins associated with certain sales of Colorado RECs bundled with energy into California. PSCo's request sought 45 percent of the margins on these specific transactions for both the customers and PSCo with the remaining ten percent being used to fund a program to develop carbon offset projects and expertise. On Jan. 20, 2010, PSCo, the Office of Consumer Council, the CPUC staff, the Colorado governor's energy office and Western Resource Advocates entered into a unanimous settlement in this case. The settlement establishes a pilot program and defines certain margin splits during this pilot period. The settlement provides that 10 percent of margins will go to carbon offsets, 40 percent of the first $10 million in margins, 35 percent of the next $20 million and 30 percent of all remaining margins will go to PSCo with all remaining margins going to Colorado retail customers as a credit toward renewable energy projects. The unanimous settlement also clarified that margins associated with RECs bundled with Colorado energy would be shared 20 percent to PSCo and 80 percent to customers and margins associated with sales of stand-alone renewable energy credits without energy would be credited 100 percent to customers. It is expected that PSCo will file an application by Aug. 31, 2010 for future treatment of margins from transactions for RECs bundled with energy after the end of the pilot program. On Feb. 18, 2010, the CPUC approved the settlement. Pending and Recently Concluded Regulatory Proceedings — FERC Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period Dec. 25, 2000 through June 20, 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million. In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC's orders in this proceeding with the U. S. Court of Appeals for the Ninth Circuit. In an order issued in August 2007, the Court of Appeals remanded the proceeding back to the FERC. The Court of Appeals also indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Court of Appeals denied a petition for rehearing in April 2009, and the mandate was issued. The FERC has yet to act on this order on remand; currently, certain motions concerning procedures on remand are pending before the FERC. Wholesale Rate Case — In 2009, PSCo proposed to increase Colorado wholesale rates by $30 million based on a 12.5 percent ROE, a 58 percent equity ratio and an electric production rate base of $315 million. PSCo has requested that FERC suspend action on the filing to allow time for settlement negotiations. Settlement discussions with PSCo's wholesale customers are continuing. PSCo expects rates subject to refund to go into effect in the second quarter of 2010. SPS Pending and Recently Concluded Regulatory Proceedings — PUCT Base Rate Texas Retail Base Rate Case — In June 2008, SPS filed a rate case with the PUCT seeking an annual rate increase of approximately $61.3 million, or approximately 5.9 percent. Base revenues are proposed to increase by $94.4 million, while fuel and purchased power revenue would decline by $33.1 million, primarily due to fuel savings from the Lea Power Partners (LPP) purchase power agreement. The rate filing was based on a 2007 test year adjusted for known and measurable changes, a requested ROE of 11.25 percent, an electric rate base of $989.4 million and an equity ratio of 51.0 percent. Interim rates of $18 million for costs associated with the LPP power purchase agreement went into effect in September 2008. In January 2009, a settlement agreement was reached with various intervenors, which provided for a base rate increase of $57.4 million, a reduced depreciation expense of $5.6 million, allowed SPS to implement the transmission rider in 2009 and precludes SPS from filing to seek any other change in base rates until Feb. 15, 2010. In January 2009, an ALJ approved interim rates effective February 2009. On June 2, 2009, the PUCT issued its order approving the settlement. John Deere Wind Complaint — In June 2007, several John Deere Wind Energy subsidiaries (JD Wind) filed a complaint against SPS disputing SPS' payments for energy produced from the JD Wind projects. SPS responded that the payments to JD Wind are appropriate and in accordance with SPS' filed tariffs. In March 2009, the ALJ recommended that SPS payment methodology to JD Wind is proper and that JD Wind's complaint be denied. In May 2009 the PUCT issued a final order denying JD Wind's request for relief against SPS. In June 2009, JD Wind filed a petition for review of the final order in Texas District Court. In July 2009, the PUCT filed an answer to JD Wind's petition in Texas District Court in which the PUCT denied all allegations contained in the JD Wind petition. The case is pending in Texas District Court. In November 2009, the FERC declined to rule on a request to overturn the PUCT decision by JD Wind but did issue a declaratory order stating that the PUCT's order denying JD Wind's complaint is not consistent with the FERC's regulations. In December 2009, SPS requested that the FERC reconsider its November 2009 declaratory order. In December 2009, JD Wind filed a complaint against the PUCT in U. S. District Court seeking federal law enforcement, including declaratory and injunctive relief to enforce and give proper effect to the PURPA. JD Wind requests a declaration that the PUCT's order does not implement PURPA and FERC PURPA rules and is preempted by federal law. The complaint also requests that the PUCT be required to revise its order and be enjoined from enforcing its current order. SPS intends to intervene in this case and defend the PUCT's order. On Jan. 28, 2010, JD Wind filed a damage suit against SPS in Texas state district court to toll the statute of limitations while the above cases are being decided. Texas Jurisdictional Fuel Allocation Methodology — In May 2009, SPS filed an application to revise the calculation of Texas retail jurisdictional fuel and purchased power expense, effective in January 2008. SPS has determined that its current method results in a material amount of unrecovered fuel and purchased power expense. The application seeks approval for a revised methodology, which matches the fuel and purchased power expenses in a month with the fuel factor revenue received from each kilowatt hour used that month. In November 2009, the PUCT issued a final order approving a unanimous settlement that would allow for the change in the calculation of deferred fuel consistent with the approach proposed by SPS. The estimated impact is expected to result in an approximate $6.5 million increase to fuel and purchased power expenses for the Texas retail jurisdiction for Jan. 1, 2008 to Dec. 31, 2009. SPS has agreed to reduce the new allocated portion by $3 million subsequent to adopting the new methodology going forward. Texas Transmission Cost Recovery Factor (TCRF) — In 2007, the PUCT implemented rules allowing utilities to request a TCRF in between rate cases for recovery of new transmission investment costs. In June 2009, SPS filed a request to implement a TCRF with proposed revenues of $7.4 million annually. This is SPS' first filing under that rule. In November 2009, the parties filed a unanimous stipulation, which allows SPS to recover $4.5 million annually, and the ALJ issued an order approving interim TCRF rates beginning Jan. 1, 2010. In January 2010, the PUCT approved the unanimous stipulation. Pending and Recently Concluded Regulatory Proceedings — NMPRC Base Rate 2008 New Mexico Retail Electric Rate Case — In December 2008, SPS filed with the NMPRC a request to increase electric rates in New Mexico by approximately $24.6 million, or 6.2 percent. The request was based on a historic test year (split year based on the year ending June 30, 2008), an electric rate base of $321 million, and an equity ratio of 50.0 percent and a requested ROE of 12.0 percent. SPS also requested interim rates of $7.6 million per year to recover capacity costs of the Lea Power facility, which became operational in September 2008. In March 2009, the NMPRC approved a partial stipulated settlement between the parties that allows SPS to recover approximately $5.7 million of interim rates, effective May 1, 2009, through an LPP cost rider until the final rates from the remainder of the case are effective. In July 2009, the NMPRC issued an order approving the stipulation settlement agreement. Under the stipulation, SPS receives a base rate increase of $14.2 million, effective July 1, 2009. SPS has agreed that Dec. 1, 2010 is the earliest date it will file its next base rate case, subject to a force majeure provision triggered by additional environmental compliance costs. SPS implemented the new rates on July 15, 2009. Pending and Recently Concluded Regulatory Proceedings — FERC Wholesale Rate Complaints — In November 2004, Golden Spread Electric, Lyntegar Electric, Farmer's Electric, Lea County Electric, Central Valley Electric and Roosevelt County Electric, all wholesale cooperative customers of SPS, filed a rate complaint with the FERC alleging that SPS' rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustment charges to such customers (the Complaint). Among other things, the complainants asserted that SPS had inappropriately allocated average fuel and purchased power costs to other wholesale customers, effectively raising the fuel cost charges to the complainants. Cap Rock Energy Corporation (Cap Rock), another full-requirements customer of SPS, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental), SPS' largest retail customer, intervened in the proceeding. Golden Spread Complaint Settlement — In December 2007, SPS reached a settlement with Golden Spread (which now includes Lyntegar Electric) and Occidental regarding base rate and fuel issues raised in the complaint described above as well as a subsequent rate proceeding. In April 2008, the FERC approved the settlement, which resolved all issues pertaining to Golden Spread that were the subject of the Complaint; implemented a formula rate and extended the term of its partial requirements sale to Golden Spread beginning 2012 at 500 MW and ramping down to 200 MW for the two years prior to the end of the term in 2019. The settlement made the extended purchase contingent on certain state approvals. Golden Spread agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed sale and SPS agreed to contingent payments ranging from $3 million to a maximum of $12 million, payable in 2012, in the event that there is an adverse cost assignment decision or a failure to obtain state approvals. Request for approvals are currently pending before the NMPRC and the PUCT, and SPS anticipates actions by the state commissions during the first quarter of 2010. New Mexico Cooperatives' Complaint Settlement — In January 2010, SPS reached a settlement with Farmers' Electric Cooperative of New Mexico, Lea County Electric Cooperative, Central Valley Electric Cooperative and Roosevelt County Electric Cooperative, all wholesale customers of SPS located in New Mexico, and Occidental regarding the same base rate and fuel issues raised in the complaint described above. The settlement with these wholesale customers is now pending approval by the FERC. The settlement resolves all issues arising from the complaint docket and implements a replacement contract with a formula production rate at 10.5 percent ROE and extended term of its requirements sale to the four wholesale customers. The four wholesale customers must reduce their system average cost power purchases by 90 to 100 MW in 2012, and implement staged reductions in system average cost power purchases through the term of the agreement, which terminates on May 31, 2026. The settlement made the replacement contract contingent on certain state approvals. In the event all regulatory approvals are not received, the Settlement includes a one time total contingent payment of $12 million by SPS to these wholesale customers. These wholesale customers agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed wholesale power sale. Order on Wholesale Rate Complaints — In April 2008, the FERC issued its Order on the Complaint applied to the remaining non-settling parties. The Order addresses base rate issues for the period from Jan. 1, 2005 through June 30, 2006, for SPS' full requirements customers who pay traditional cost-based rates and requires certain refunds. Several parties, including SPS, filed requests for rehearing on the order. These requests are pending before the FERC. In July 2008, SPS submitted its compliance report to the FERC and calculated the base rate refund for the 18-month period to be $6.1 million and the fuel refund to be $4.4 million. Several wholesale customers have protested the calculations. Once the final refund amounts are approved by the FERC, interest will be added to the refund due to the remaining non-settled customers. As of Dec. 31, 2009, SPS has accrued an amount sufficient to cover the estimated refund obligation. SPS 2008 Wholesale Rate Case — In March 2008, SPS filed a wholesale rate case seeking an annual revenue increase of $14.9 million or an overall 5.14 percent increase, based on 12.20 percent requested ROE. In April 2009, the parties reached a settlement in which SPS will receive an annual revenue increase of approximately $9.6 million or an increase of 3.3 percent. The FERC issued an order approving the uncontested settlement in September 2009. SPS 2008 Transmission Formula Rate Case — In December 2007, Xcel Energy submitted an application to implement a transmission formula rate for the SPS zone of the Xcel Energy OATT. The changed rates affect all wholesale transmission service customers using the SPS transmission network under either the Xcel Energy OATT or the SPP Regional OATT. In September 2009, Xcel Energy filed an uncontested offer of settlement with the FERC which resolves all issues in the proceeding with the exception of the ratemaking and rate design treatment for certain radial lines under the SPP OATT. The parties are still formulating the methodology for designating direct assignment of radial transmission lines to wholesale and retail customers pursuant to the SPP OATT. The settlement provides for a formula rate using a fully forecasted test year effective Jan. 1, 2009, with a stated ROE of 11.27 percent (including the 50 basis point adder for SPP RTO participation). The settlement will result in approximately $0.8 million in additional revenues for 2008 and 2009 in aggregate and will allow SPS to update its transmission rates annually for predicted costs and loads, subject to an annual true-up. In October 2009, SPS announced the 2010 costs and charges pursuant to the formula rate and are expected to provide $2.7 million in additional revenue, subject to true-up. The settlement was approved by the FERC in December 2009, and SPS and SPP are now effectuating the settlement.</td></tr></table>

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<NonNumericTextHeader> 16. Rate Matters NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings — MPUC Base Rate NSP-Minnesota </NonNumericTextHeader>

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2 Subsequent Filings that Reference this Filing

  As Of               Filer                 Filing    For·On·As Docs:Size             Issuer                      Filing Agent

 8/20/10  SEC                               UPLOAD¶     9/12/17    1:45K  Xcel Energy Inc.
 8/05/10  SEC                               UPLOAD¶     9/12/17    1:71K  Xcel Energy Inc.

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Filing Submission 0001047469-10-001536 – Alternative Formats (Word / Rich Text, HTML, Plain Text, et al.)

Xcel Energy Inc – ‘10-K’ for 12/31/09 – ‘XML.R25’

On: Friday, 2/26/10, at 4:23pm ET · For: 12/31/09 · Accession #: 1047469-10-1536 · File #: 1-03034

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Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34Filing Table of Contents

‘XML.R25’ — Rate Matters

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Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34
Filing Table of Contents